RÉGIE DE L’ÉNERGIE
HYDRO-QUÉBEC DISTRIBUTION’S
RATE APPLICATION
FOR 2009-2010
FILE: R-3677-2008
EVIDENCE OF
WILLIAM HARPER
ECONALYSIS CONSULTING SERVICES
ON BEHALF OF:
OPTION CONSOMMATEURS
OCTOBER 28th, 2007
TABLE OF CONTENTS
1
INTRODUCTION...................................................................................................... 1
2
PURPOSE OF EVIDENCE ...................................................................................... 1
3
TREATMENT OF WEATHER-NORMALIZATION VARIANCE ACCOUNT.............. 4
3.1
HQD’s Proposal ................................................................................................ 4
3.2
Comments......................................................................................................... 5
4
RECOVERY OF OPERATING COSTS ASSOCIATED WITH MAJOR OUTAGES.. 8
4.1
HQD’s Proposal ................................................................................................ 8
4.2
Comments......................................................................................................... 9
5
COST ALLOCATION ............................................................................................. 14
5.1
HQD’s Proposal .............................................................................................. 14
5.2
Comments....................................................................................................... 16
6
DIFFERENTIATED CUSTOMER CLASS RATE INCREASES .............................. 19
6.1
HQD’s Proposal .............................................................................................. 19
6.2
Comments....................................................................................................... 20
7
RESIDENTIAL RATE DESIGN .............................................................................. 24
7.1
HQD’s Proposal .............................................................................................. 24
7.2
Comments....................................................................................................... 25
8
CONCLUSIONS..................................................................................................... 29
8.1
Treatment of Weather Normalization Variance Account ................................. 29
8.2
Recovery of Operating Costs Associated with Major Outages........................ 29
8.3
Cost Allocation ................................................................................................ 30
8.4
Differentiated Customer Class Rate Increases ............................................... 30
8.5
Residential Rate Design ................................................................................. 30
Appendix:
CV for ECS Consultant
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
1
2
3
On August 1st, 2008 Hydro-Québec Distribution (HQD) filed an Application with the
4
Régie de l’énergie (the “Régie”) for approval of a revised revenue requirement and
5
distribution rates effective April 1st, 2009. The Application requests approval for a
6
revenue requirement of $10,683 M based on a 2009 test year, which translates into an
7
average overall rate increase of 2.2%1. The Application also includes a cost allocation
8
study that allocates the requested revenue requirement to customer classes and
9
proposes a 2.2% increase for all customer classes. Finally, the Application includes a
10
proposed set of rates for the residential customer class that continues the rate design
11
evolution initiated in earlier proceedings.
12
2
INTRODUCTION
PURPOSE OF EVIDENCE
13
14
After reviewing HQD’s Application and the Procedural Order2 issued by the Régie,
15
Option Consommateurs (OC) retained Econalysis Consulting Services (ECS), a
16
Canadian consulting firm offering regulatory services to clients in the electricity and
17
natural gas sectors to provide evidence that would assist OC and the Régie in
18
assessing various aspects of HQD’s proposal.
19
20
The Evidence was prepared by Bill Harper who, prior to joining ECS in July 2000,
21
worked for over 25 years in the energy sector in Ontario, first with the Ontario Ministry
22
of Energy and then, with Ontario Hydro and its successor company Hydro One. Since
23
joining ECS, he has assisted various clients participating in regulatory proceedings on
24
issues related to electricity and natural gas utility revenue requirements, cost
25
allocation/rate design and supply planning. Mr. Harper has served as an expert witness
26
in public hearings before the Manitoba Public Utilities Board, the Manitoba Clean
27
Environment Commission, the Régie, the Ontario Energy Board, the Ontario
28
Environmental Assessment Board and a Select Committee of the Ontario Legislature on
1
2
HQD-1, Document 1, pages 5-7
D-2008-103
1
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
matters dealing with electricity regulation, rates and supply planning. His most recent
2
experience includes:
3
•
4
OC in the Régie proceeding (R-3541-2004) dealing with HQD’s rate design proposals
5
for 2005.
6
•
7
OC in the Régie proceedings (R-3579-2005; R-3610-2006 and R-3644-2007) dealing
8
with HQD’s cost allocation and rate design proposals for 2006, 2007 and 2008
9
respectively. In addition, the R-3644-2007 evidence dealt with issues regarding the
The preparation of evidence and appearance as an expert witness on behalf of
The preparation of evidence and appearance as an expert witness on behalf of
10
recovery of various deferral account balances.
11
•
12
Manitoba Public Utilities Board with respect to its review of Manitoba Hydro’s 2002
13
Status Update as well as General Rate Applications for 2004 and 2008. Evidence dealt
14
with issues related to the overall revenue requirement as well as cost allocation and
15
rate design matters.
16
•
17
Manitoba Public Utilities Board with respect to the Board’s Generic Review of Manitoba
18
Hydro’s 2006 Cost Allocation Proposals.
19
•
20
Application for Experimental Residential Time of Use Rates.
21
•
22
the BCUC proceedings dealing with BCHydro’s 2007 Rate Design Application3,
23
BCHydro’s 2007 Residential Inclining Block Application and BCHydro’s General Rate
24
Applications for 2007-2008 and 2009-2010.
25
•
26
allocation for Ontario electricity distributors.
The preparation of evidence and appearance as an expert witness before the
The preparation of evidence and appearance as an expert witness before the
Providing expert evidence and support to clients regarding BC Hydro’s 2006
Providing expert advice and support to clients in British Columbia participating in
Member of the OEB’s 2005/06 Technical Advisory Team regarding cost
27
28
A full copy of Mr. Harper’s CV is attached in Appendix A.
29
3
The Application, which also included a proposed cost allocation methodology.
2
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
The evidence specifically addresses the following aspects of HQD’s Application:
2
•
3
transmission and distribution revenues.
4
•
5
revenue requirement and the creation of a deferral account to manage exceptional
6
costs.
7
•
8
treatment of electricity resale, the treatment of the annual true-up debit/credit from HQT
9
related to its variance account for point-to-point revenues and the application of HQT’s
HQD’s proposals regarding the recovery of weather-related variations in
HQD’s proposals regarding the provision for major outages to be included in the
HQD’s response to the Régie regarding specific cost allocation issues (i.e., the
10
cost allocation methodology to HQD’s billed transmission costs).
11
•
12
adjustments for various customer classes.
13
•
14
charge.
HQD’s response to the Régie regarding the application of differentiated rate
HQD’s response to the Régie regarding the basis for the Residential service
15
16
Applicable comments are noted throughout the text and summarized in the concluding
17
section.
18
3
Evidence of
William Harper
1
3
2
3.1
Hydro-Québec Distribution
R-3677-2008
TREATMENT OF WEATHER-NORMALIZATION VARIANCE ACCOUNT
HQD’s Proposal
3
4
Background
5
6
In Decision D-2006-34, the Régie accepted HQD’s proposal for the creation of a
7
weather-related transmission and distribution averaging mechanism applicable as of
8
January 1, 20064. At that time, the expectation was that the annual weather-related
9
revenue variances would be recorded in the account and that, over time, the positive
10
and negative fluctuations would cancel each other out. Based on this premise, HQD did
11
not make any proposals regarding the refund/recovery of the balance in the account.
12
As of December 31, 2007, the balance associated with the account was $128.9 M –
13
including interest5.
14
15
As part of its 2008 rate application (R-3644-2007), HQD introduced a new definition of
16
“normal weather” for purposes of weather normalization6. For 2006 and 2007,
17
application of the revised definition would have reduced the principal amounts recorded
18
in the variance account by $62.01 M7.
19
20
Current (R-3677-2008) Application
21
22
For 2009 rates, HQD is proposing8 to:
23
•
24
Fully amortize in one year (i.e., 2009) the $62.01 M associated with the change in
weather normalization methodology. The amount to be recovered from each
4
HQD-4, Doc 2, page 4
HQD-9, Doc 1, page 16
6
HQD-4, Doc 2, page 7
7
HQD-4, Doc 2, page 7
8
HQD-4, Doc 2, page 13
5
4
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
customer class would be based on each class’ contribution to the $62.01 M
2
difference9.
3
•
Amortize over 5 years (starting in 2009) the remaining $66.6 M in the account.
4
Again, the calculation of the annual variance is done by customer class and the
5
outstanding amounts for each class would be amortized over five years10.
6
HQD is also proposing that, in future years’ rates, the actual amount recorded in the
7
account for the test year minus two (i.e., t-2) would be amortized over a five year
8
period11.
9
10
3.2
Comments
11
With respect to the $62 M, HQD contends that even if the weather normalization
12
account averages out over time, the change in definition of “weather normal” means
13
that the $62 M would not be recovered12. When asked why the amount should not be
14
recovered over a longer period (e.g., 5 years) HQD responded13 that such an approach
15
would increase the financial costs associated with the account (since interest costs
16
would accrue on any outstanding balance) and that there is no prospect of this amount
17
being zeroed out over time.
18
19
ECS concurs with HQD’s conclusion that, given the change in definition of “weather
20
normal”, the $62 M would not be recovered. Assuming the new weather normalization
21
methodology better reflects average weather conditions, at best the weather effects on
22
load and revenues can be expected to average out to this newly derived value over
23
time. Thus, there is a need to address the recovery of this amount which represents the
24
impact of changing the definition of “normal weather” on the 2006 and 2007 balances.
25
9
HQD-4, Doc 2, pages 7 and 12
HQD-4, Doc 2, pages 11-12
11
HQD-16, Doc 9, Questions 6.1 and 5.1
12
HQD-4, Doc 2, page 7 and HQD-16, Doc 9, Question #5.1
13
HQD-16, Doc 1 (No. 2), Question 17.1
10
5
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
As noted in ECS’s R-3644-2007 Evidence14, the recovery of outstanding amounts in
2
deferral/variance accounts must balance issues of inter-generational equity (which
3
typically suggest more rapid recovery) with issues of rate stability (which may suggest
4
the need for a longer recovery period depending on the nature of the costs being
5
accrued in the variance account and the overall financial outlook). The $62 M is a one-
6
time cost, with no prospect of offsetting amounts in future years. Furthermore, the one-
7
year recovery is being proposed within the context of an overall average rate increase
8
of 2.2% which is just slightly in excess of inflation15. Finally, the range of individual
9
customer bill impacts for residential customers is such that virtually all will experience
10
bill impacts of less than 3% overall16 and for the other customer classes the
11
circumstances are generally similar17.
12
13
Overall, HQD’s proposal to recover the $62 M in one year is reasonable given the
14
context of an average rate increase of 2.2% for each customer class. ECS notes that
15
the one-year recovery period is also consistent with the Régie’s request that HQD clear
16
its Transmission Deferral account as quickly as possible18.
17
18
HQD’s proposal to amortize the current $66.6 M remaining balance over five years (and
19
apply a similar treatment to any annual variations recorded in the future) is also
20
reasonable. There is some expectation that the volume variances will average out over
21
time. However, the time frame involved could be exceptionally long. Also, even if the
22
volumes average out, different rates are in effect each year and there is less likelihood
23
that the revenue variances will average out over time. Prudence would suggest
24
adopting a proactive approach to managing the variance as opposed to waiting until a
25
large variance potentially is accumulated and needs to be addressed. However, given
26
there is some expectation of offsetting variances over time, it is also reasonable to
14
Page 15
HQD-1, Doc 2.1, page 3
16
HQD-12, Doc 1, page 118
17
HQD-12, Doc 1, pages 124-126
18
D-2007-012, page 20
15
6
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
amortize the variance calculated in any one year over a “number of years” and therefore
2
(hopefully) smooth the overall impact on any one year’s rates.
3
4
The issue then becomes what is an appropriate number of years given the need to
5
balance inter-generational equity and rate stability. This is a matter to be determined by
6
judgment as opposed to analysis. In this regard, the five year amortization appears to
7
strike a reasonable balance:
8
•
9
HQD suggests that the maximum annual variance could be in the order of $120 M19.
Amortization of such an amount over 5 years would result in a change in the
10
revenue requirement of +/- $24 M or 0.2%. This suggests the proposed recovery
11
period will not generate an undue degree of rate instability.
12
•
13
14
amortization amounts to offset each other.
•
BCHydro’s current proposal for clearance of its deferral account balances is based
on a 4-6 year recovery period20.
15
16
The five year period also offers some opportunity for the individual annual
•
The OEB in its 2004 Decision21 regarding the recovery of outstanding regulatory
17
assets by all Ontario electricity distributors established a 3 year recovery period.
18
Subsequent decisions by the Board regarding the clearance of various regulatory
19
accounts by individual distributors have set recovery periods generally ranging from
20
one to three years. However, in many cases the accounts involved were associated
21
with one-time costs as opposed to ongoing variances.
22
23
19
HQD-16, Doc 4, Question 4.1
BCHydro’s F09/F10 Revenue Requirements Application, page 6-9
21
OEB Decision, Recovery of Regulatory Assets-Phase 2, December 9, 2004, page 85 and 93
20
7
Evidence of
William Harper
1
4
2
4.1
Hydro-Québec Distribution
R-3677-2008
RECOVERY OF OPERATING COSTS ASSOCIATED WITH MAJOR OUTAGES
HQD’s Proposal
3
4
Background
5
6
In previous cases, the HQD has included and the Régie has approved revenue
7
requirement provisions to address uncertainties such as loss of major customers or the
8
need to deal with major outages22. More recently, the Régie has expressed some
9
concerns about the approach HQD used in setting this provision23 and in its ability to
10
report on the actual use of the provisions24. HQD has undertaken to address the
11
reporting issues in its Annual Report to the Régie25.
12
13
Current (R-3677-2008) Application
14
15
One of the more significant uncertainties facing HQD (from a budgeting perspective) is
16
the potential for unforeseen major outages to occur26. As a result, HQD’s 2009 Rate
17
Application focuses on an approach for addressing this particular uncertainty. For 2009
18
rates, HQD is proposing27 that:
19
•
A provision for major outages in the amount of $8 M be included in rates. This
20
amount represents the average cost of major outages over the 2001-2007 period,
21
excluding two years with extreme values (i.e., 2004 and 2006).
22
•
23
A deferral account be created that would record costs associated with major outages
that exceed an annual threshold of $16 M.
22
HQ-4, Doc 4, page 5
D-2007-12, page 45
24
D-2008-24, pages 54 and 135
25
HQD-4, Doc 4, pages 6 and 19
26
HQD-4, Doc 4, page 5 and R-3610-2006, HQD-19, Doc 11
27
HQD-4, Doc 4, page 18
23
8
Evidence of
William Harper
1
2
3
4.2
Hydro-Québec Distribution
R-3677-2008
Comments
Need for Special Treatment of Major Outages
4
5
Dealing with outages and the restoration of power is part of an electricity distribution
6
utility’s core business and budgeting processes typically make provision for spending to
7
address a normal/expected level of outages. What is particularly difficult to address is
8
the impact that major outages can have. A good example of this are the outages that
9
occur from major storms. First, such events are highly random and, therefore, tend to
10
defy forecasting. Second, the cost impacts of these events are equally difficult to
11
forecast but can be significant28. The significance of the costs means that they cannot
12
be ignored. However, as demonstrated by the Régie’s concerns29 about “budgeting” for
13
such events, utilities are challenged in terms of how to achieve a reasonable
14
expectation of cost recovery.
15
16
Alternatives Considered by HQD
17
18
HQD considered30 three potential approaches to addressing the costs associated with
19
major outages:
20
•
21
22
overall annual revenue requirement application.
•
23
24
Integrate a forecast of the costs associated with major outages into its budget and
Include a special provision in its annual revenue requirement application for the
costs associated with major outages.
•
Don’t make any budgetary or special provision for major outage costs in the annual
25
revenue requirement application and accrue all such costs in a deferral account for
26
future recovery.
28
The potential significance of such costs can be seen from the Edison Report referenced by HQD (HQD-4, Doc 4,
page 9); BCHydro’s experience (HQD-4, Doc 4, page 8) and HQD’s own experience (HQD-4, Doc 4, page 15)
29
D-2007-12, page 45
30
HQD-4, Doc 4, pages 12-14
9
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
HQD’s proposal represents a hybrid of the last two options in that it includes a limited
2
provision for the costs of major outages ($8 M) and requests deferral account treatment
3
for annual costs in excess of a pre-established threshold ($16 M).
4
5
In its discussion, HQD indicates that the issues involved in considering the various
6
alternatives are:
7
•
The difficulty in forecasting major outages (and the associated costs) which can lead
8
to a significant over or under recovery of cost in a particular year (and perhaps even
9
over the long term) if addressed entirely through a budget or special provision.
10
•
11
Intergenerational equity if the associated costs are deferred and recovered over an
extended period.
12
•
The financing cost associated with carrying deferral accounts.
13
•
The annual fluctuations in costs (and revenue requirement) that could occur
14
depending upon the approach adopted.
15
16
In ECS’ view the two most important considerations are: i) the difficulty in forecasting
17
major outages and ii) the annual fluctuation in costs (charges to customers) that can
18
occur depending upon the approach adopted. Intergenerational equity issues are of
19
less concern since the costs incurred were not directly “caused” by customers. In the
20
case of financing costs, customers have their own “time value of money” which they will
21
associate with deferred payments.
22
23
After considering the options available and focusing on these two criteria, ECS
24
considers some form of hybrid approach that includes an annual provision but also
25
allows for significant cost variations to be reasonable. History demonstrates that major
26
outages do occur each year31 and therefore it is reasonable to include some provision
27
for such events in the annual revenue requirement. However, while annual amounts
28
can be significant (e.g., more than $30 M in 2006) such occurrences are infrequent32.
31
32
HQD-16, Doc 9, Questions 9.9 and 11.5
Only one the most recent seven years exceeded HQD’s proposed threshold of $16 M.
10
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
As a result, it is reasonable to manage exceptional costs by means of a
2
deferral/variance account that captures amounts exceeding a pre-established threshold.
3
4
HQD’s approach is one way of accomplishing this. However, the approach assumes
5
that the costs for major outages (up to a maximum of $16 M) will average out over time
6
at $8 M. The most recent experience (2001-2007) suggests this is the case – as
7
illustrated in the following Table.
8
9
Table 1
10
Average Cost of Outages (up to $16 M)
11
Year
12
Cost of Major
Cost with $16 M
Cumulative
Outages
Threshold
Average
2001
$10.8 M
$10.8 M
$10.8 M
2002
$5.6 M
$5.6 M
$8.2 M
2003
$4.8 M
$4.8 M
$7.1 M
2004
$1.2 M
$1.2 M
$5.6 M
2005
$7.6 M
$7.6 M
$6.0 M
2006
$34.1 M
$16.0 M
$7.7 M
2007
$9.6 M
$9.6 M
$7.9 M
Source: HQD-4, Doc 4, page 15
13
14
However, there is no guarantee that this will be the case in the future. While HQD has
15
based its $8 M provision on the period for which data is available and assumed a
16
symmetry around the average, it acknowledges33 that future data will provide the
17
necessary information to validate its approach.
18
33
HQD-16, Doc 9, Question 12.1
11
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
During the interrogatory process both OC34 and Régie staff35 suggested an alternative
2
approach whereby a provision was set each year and included in the revenue
3
requirement and any difference would be tracked in a variance account for future
4
refund/recovery. The advantage of such an approach is that it addresses any concerns
5
regarding the accuracy of the provision included in the revenue requirement and
6
ensures that the Distributor recovers no more/less than the actual costs associated with
7
major outages. In responding to the suggestion, HQD expresses36 the concern that this
8
alternate approach is inadequate since it does not include a proposal as to how any
9
shortfall in cost recovery would be dealt with. However, ECS notes that the same issue
10
exists with HQD’s proposal in that it does not address how any annual spending that is
11
in excess of the $16 M and accumulated to a deferral account would ultimately be
12
recovered. Rather, the application states that this issue would be addressed on a case
13
by case basis37. A key difference between the two approaches therefore appears to be
14
a question of when the matter of disposing of the deferral/variance account balance will
15
be addressed.
16
17
Given the lack of certainty regarding the symmetry of major outage costs, ECS
18
considers that it would be prudent to adopt a variance account approach that tracked
19
the differences on an annual basis.
20
21
As HQD has noted, this gives rise to the question of how the balance in the account
22
should be managed over time. While this issue does not have to be addressed
23
immediately, it is one that HQD should be directed to make proposals on as part of its
24
next rate application. One approach worth considering is setting a threshold for the
25
overall level of variance account and when the cumulative balance exceeds that
26
threshold the matter would be brought before the Régie. In setting the appropriate
27
“threshold” one would want to ensure that it was not so high that refund/recovery of the
28
amount created issues of significant rate instability. On the other hand, too low a
34
HQD-16, Doc 9, Question 12.3
HQD-16, Doc 1, Question 20.2
36
HQD-16, Doc 1, Question 20.2
37
HQD-4, Doc 4, page 16
35
12
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
threshold would reduce the opportunity to have the balance average out overtime and
2
thereby introduce rate instability of another form.
3
4
Canadian Industry Practice
5
6
HQD’s application includes a discussion of the practices in BC and Ontario regarding
7
the recovery of costs associated with major outages. What is important to note is that in
8
the case of both BCHydro and Ontario’s electricity distributors the revenue requirement
9
(and rates) approved by the regulator does not include an allowance for the costs
10
associated with exceptional events. Such costs are addressed through deferral
11
accounts in a manner similar to the third approach considered by HQD. Furthermore, in
12
addressing the clearance of such accounts a utility is expected to demonstrate that it
13
requires incremental resources (over and above those provided for in rates) to deal with
14
the exceptional event38.
15
16
The number of claimed exceptional events by Ontario electricity distributors has been
17
very limited and treatment as a deferral account with no annual provision is likely the
18
preferable approach in such instances. In the case of BCHydro, there have been a
19
number of events that would qualify as major storms using its definition. However, the
20
number of occurrences is materially less over the 2004-2007 period39 than the number
21
of major outages experienced by HQD during the same period40. Again, the
22
infrequency of qualifying events in BC relative to Quebec would support a full deferral
23
account treatment as opposed to a hybrid approach.
24
25
One of the reasons for this difference in number of “events” in HQD versus
26
BCHydro/Ontario is that the criteria used in BC and Ontario is based on costs per major
27
storm/event. In contrast, HQD’s criterion identifies major outages based on their impact
38
Illustration of this point can be found in the OEB’s July 31st Decision Regarding Storm Damage Cost Claims
(page 19) and BCHydro’s 2009/2010 Rate Application, page 6-18.
39
One major storm in 2003/04; no major storms in 2004/05 or 2005/06; four in 2006/07 and on in 2007/08 (as of
February 2008).
40
HQD-16, Doc 9, Questions 9.9 and 9.10
13
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
on its continuity of service measure41. Based on the number of events that occurred
2
annually in 2001-2007 and the total associated costs42, a large number of these events
3
would likely not meet the $2 M threshold that BC Hydro is currently proposing43 for
4
identifying “major events” and the related costs eligible for deferral account treatment.
5
As a result, it would appear that HQD’s threshold is lower than BCHydro’s which
6
contributes to more events and costs qualifying as being associated with what are
7
considered exceptional circumstances. There is nothing inherently wrong with a
8
different definition. However, such differences do suggest that the same cost recovery
9
approach may not be appropriate for HQD as for BCHydro and Ontario.
10
5
11
12
5.1
13
Background
COST ALLOCATION
HQD’s Proposal
14
15
HQD’s cost allocation methodology has been reviewed in previous proceedings and the
16
Régie has determined the appropriate treatment for the various cost elements in the
17
revenue requirement. However, in the last proceeding (R-3644-2007) the Régie
18
requested44 that HQD address a couple of issues that, in its view, had not been
19
adequately canvassed to date. The first issue is the appropriate allocation factor to be
20
used for the Native Load bill from HQT and the credit (or debit) received from HQT as a
21
result of its disposition of the variance account associated with PTP sales. The second
22
issue is regarding the treatment of resale revenues in the overall allocation of post-
23
heritage electricity costs.
24
41
HQD-4,Doc 4, page 10
HQD-16, Doc 9, Questions 9.9 & 11.5 and HQD-4, Doc 4, page 15
43
HQD-16, Doc 1, Question 19.1
44
D-2008-024, pages 75 and 79
42
14
Evidence of
William Harper
1
Hydro-Québec Distribution
R-3677-2008
Current (R-3677-2008) Application
2
3
Allocation of HQT Costs
4
5
In last year’s decision45, the Régie directed HQD to assign HQT’s billed transmission
6
costs to customer classes by reflecting HQT’s cost allocation methodology through to
7
the Distributor’s Native Load customer classes. The actual transmission costs charged
8
to HQD are less than the costs allocated to the Distributor using HQT’s cost allocation
9
methodology. As a result, in order to apply HQT’s allocation methodology to HQD
10
transmission costs, HQD reduces the functional costs allocated to it (by HQT’s
11
methodology) on pro rata basis in order to match with the its forecast “bill” from HQT. In
12
the 2008 Rate Application, this proration was applied to all of HQT’s cost functions,
13
including those used exclusively by the distributor46. In its D-2008-024 decision, the
14
Régie requested47 that HQD specifically look at the impact of excluding the HQT
15
functions used exclusively by the Distributor when establishing the proration required to
16
match the Native Load bill from HQT and when allocating the credit (or debit) received
17
from HQT as a result of its disposition of the variance account associated with PTP
18
sales.
19
20
In its Application HQD has provided a calculation of the impact on the total costs
21
allocated by customer class of this alternative approach. The results range from an
22
increase of roughly 0.07% for the Residential and Small Power customers to a
23
decrease of 0.17% for the Large Power customers48. In its subsequent discussion of
24
this issue, HQD stated49 that the appropriate approach is to include all functions in the
25
proration (as per last year’s Application).
26
27
45
D-2008-028, page 75
R-3644-2007, HQD-11, Doc 3, page 17
47
D-2008-028, page 75
48
HQD-11, Doc 1, page 5 and HQD-19, Doc 4,Question No. 2 - 2 a)
49
HQD-11, Doc 1, pages 5-6
46
15
Evidence of
William Harper
1
Hydro-Québec Distribution
R-3677-2008
Treatment of Resale Revenues
2
3
As directed50 by the Régie, HQD reviewed the cost allocation treatment of electricity
4
resale revenues during an information session held in May 2008. During this session
5
and in the current Application, HQD explained that the costs of all post-heritage pool
6
purchases (including purchases of surplus energy) are allocated across the hours of the
7
year and then allocated to the customer classes based on their post-heritage pool
8
usage in each hour51. The revenues from resale are allocated across the hours based
9
on the surplus in each hour and the hourly price for resale52.
10
11
5.2
Comments
12
13
Allocation of HQT Costs
14
15
In calculating the Régie’s alternative allocation of the Native Load Bill and the allocation
16
of the 2009 credit related to historic point to point revenue variances (from forecast),
17
HQD applied the proration required to reduce HQT’s cost allocation results to an
18
amount equal to HQT’s forecast bill to the distributor only to those functions that are
19
common to both Native Load and Point to Point Service53. However, HQD has rejected
20
this approach noting that the transmission rates are established by including the
21
connection functions that are specific to native load and point to point service.
22
23
ECS agrees with HQD’s position on this issue as it relates to the allocation of HQT’s
24
Native Load bill. The $/kW rates that are used to bill both Native Load and Point to
25
Point service are determined using a cost base that includes the costs assigned to
26
HQT’s connections function. As a result, there is no logical reason to exclude this
27
function when considering which function’s costs should be pro-rated so as to reconcile
50
D-2008-024, page 79
HQD-11, Doc 1, page 4 and HQD-11, Doc 4
52
HQD-16, Doc 9, Question 14.3
53
HQD-16, Doc 4, Question No. 2 – 2 a)
51
16
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
the difference between the HQT’s billing costs to HQD and the costs allocated to HQD
2
using HQT cost allocation methodology.
3
4
With respect to the allocation of the credit related to historic point to point revenue
5
variances, in its D-2008-019 decision the Régie directed54 HQT to allocate such
6
variances based on MWs of Native versus annual Firm Point to Point load. The MW
7
value for Native Load is HQD’s coincident peak. Applying this same principle to the
8
portion assigned to HQD would suggest that the appropriate allocation factor would be
9
the contribution that each customer class makes to HQD’s coincident peak55. The
10
following table sets out the impact by major customer class of using this alternative
11
allocation. It should be noted that the overall impact for 2009 Rates is small since the
12
amount being disposed of is ($2.2 M).
13
14
Table 2
Allocation Factors for HQT PTP Variance Refund/Recovery
Customer
Class
Current
Method(1)
1-CP
Method(2)
Domestic
48.5%
62.8%
Small Power
9.2%
8.8%
Medium Power
14.7%
13.8%
Large Power
27.6%
24.6%
Total
100%
100%
Source
15
1) HQD-11, Doc 3, page 18
2) HQD-11, Doc 3, page 20
16
54
55
R-3669-2008, HQT-12, Doc 1, page 17 and D-2008-019, page 31
See HQD-11, Doc 3, page 20 (FR1) for the 2009 values.
17
Evidence of
William Harper
1
Hydro-Québec Distribution
R-3677-2008
Treatment of Resale Revenues
2
3
As noted above, HQD’s treatment of surplus power purchases costs and re-sale
4
revenues follows the hourly allocation method. While resale revenues help ameliorate
5
the impact of surplus power purchases, they do not fully offset the costs. As indicated
6
in the response to OC #21.1, the implicit cost of surplus post-heritage pool purchases in
7
2009 is $55 M, while the revenues from resale are $29.5M. – for a $25.5 M difference.
8
This serves to increase the cost of electricity in those hours where surplus occurs,
9
which are primarily the summer hours56.
10
11
This, in turn, has a greater impact on the overall cost of post-heritage pool energy for
12
those customer classes where the summer represents a larger portion of their overall
13
post-heritage pool use (e.g. Large Power customers). To some extent, this contributes
14
to higher unitary cost for this customer class. Indeed, if one looks at the 2008 data
15
shared with participants at the May 2008 session, it is only after the allocation of the
16
surplus costs and resale revenues that the unit cost for Residential is less than that for
17
the Large Power class57. Thus, contrary to HQD’s suggestion58, the existence of
18
surplus power and the associated resale revenues do contribute to higher unit costs for
19
the higher load factor customer class. However, this impact will abate if and when HQD
20
no longer has to manage surplus power purchases.
21
56
HQD-16, Doc 9, Question 14.2
HQD-11, Doc 4, Slide 4
58
HQD-11, Doc 1, page 4 and HQD-11, Doc 4, Slide 8
57
18
Evidence of
William Harper
1
6
2
3
6.1
4
Background
Hydro-Québec Distribution
R-3677-2008
DIFFERENTIATED CUSTOMER CLASS RATE INCREASES
HQD’s Proposal
5
6
In its D-2006-34 Decision the Régie concluded59 that to the extent costs to serve
7
different customer classes do not evolve uniformly, there was nothing impeding it from
8
carrying out rate adjustments that are differentiated between customer classes. To this
9
end it observed that starting with the 2008 Rate Application, the Distributor could
10
propose rate adjustments that were differentiated by customer according to the
11
evolution of costs.
12
13
In its 2008 Rate Application, HQD’s proposed rates were based on a uniform 2.9% rate
14
increase across all customer classes. However, it also included in the Application60 the
15
differentiated rate increases that would result from the methodology it had earlier
16
introduced for determining such increases and suggested that the decision regarding
17
differentiated rate increases was a matter for the Régie to decide61. In its decision
18
regarding 2008 rates the Régie directed HQD to implement a uniform rate increase for
19
all customer classes but also directed it to file scenarios for differentiated rate increases
20
as part of its next Rate Application62.
21
22
Current (R-3677-2008) Application
23
24
For 2009 HQD has requested a uniform rate increase across all customer classes of
25
2.2%63. However, in response to the Régie’s request it has also filed:
•
26
27
The differentiated rate increase results from its methodology for reflecting
variations in cost of service in annual rate changes. The results produce a range
59
Pages 77-78
R-3644-2007, HQD-12, Doc 1, Annexe A
61
R-3644-2007, HQD-1, Doc 1, page 7
62
D-2008-024, page 120
63
HQD-12, Doc 1, page 13
60
19
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
of increases across the various customer classes from 0.2% for Medium Power
2
customers to 3.6% for Residential customers64.
•
3
A set of scenarios where, for any individual customer class, the maximum value
4
for a customer class’ rate increase is restricted to a certain percentage (e.g.,
5
20%, 30% and 40%) over the average all customer increase65.
6
In its 2009 Application, HQD reiterates its view that the application of differentiated
7
rate adjustments remains a question of public interest that is best left to the Régie to
8
arbitrate66.
9
10
6.2
11
The following comments focus on two issues:
12
•
13
14
Comments
HQD’s methodology for establishing differentiated rate increases based on cost
evolution, and
•
The application of maximum deviation approach suggested by HQD.
15
16
HQD’s Rate Differential Methodology
17
18
The mechanics of HQD’s methodology were set out in last year’s application67 and also
19
summarized in the evidence filed by ECS in R-3644-200768. Last year’s ECS evidence
20
raised a number of concerns69 regarding the HQD methodology which suggested that
21
the results needed to be applied with some caution and not interpreted as being
22
precise70. In summary, these concerns included:
23
•
24
The process used to separate the impact of cost allocation methodological changes
from the impact of trends in cost evolution,
25
•
The use of energy to extrapolate the previous year’s results, and
26
•
The determination of what constitutes a change in cost allocation methodology.
64
HQD-12, Doc 1, page 14
HQD-12, Doc 1, pages 15-16
66
HQD-12, Doc 1, page 14
67
R-3644-2007, HQD-12, Doc 1, Annex A
68
Pages 39-40
69
Pages 40-44
70
Page 64
65
20
Evidence of
William Harper
1
Hydro-Québec Distribution
R-3677-2008
These concerns are still relevant.
2
3
In applying its methodology to the 2009 cost allocation results, HQD has assumed there
4
were no cost allocation methodology changes in 2009 to account for and the 2008
5
results reflect only the impact of the Régie’s D-2008-024 decision71. However, in
6
previous applications HQD has suggested72 that the Pass-On Account refund/recovery
7
should be treated as a methodology change. Adopting such an approach would change
8
the 2009 results of HQD’s rate differential methodology as follows:
9
Table 3
Differentiated Rate Increases
Treatment of Pass-On Account Refund/Recovery
As a Methodology Change
CUSTOMER
CLASS
NO
YES
Residential
3.6%
3.4%
Small Power
2.6%
2.5%
Medium Power
0.2%
0.3%
Large Power
0.7%
1.1%
Average
2.2%
2.2%
Sources:
10
1) HQD-12, Doc 1, Annexe A
2) HQD-16, Doc 9, Question 16.4
11
12
The current application also includes a proposal to amortize annual variances in
13
revenue associated with the recovery of transmission and distribution costs due to
14
weather. An issue arises as to whether these amortization amounts should be excluded
15
from the calculation. The same rationale would seem to apply for these costs as was
71
72
HQD-11, Doc 1, page 6 and HQD-16, Doc 9, Question16.2
R-3610-2006, HQD-11, Doc 1, page 30
21
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
employed by HQD in suggesting the Pass-On account refund or recovery values should
2
be excluded. They do not represent any “trend in costs” and their inclusion could lead
3
to rate instability.
4
5
In ECS’ view there is a continued need for caution when interpreting results of HQD’s
6
rate differential methodology.
7
8
HQD’s Maximum Deviation Approach
9
10
In responding to the Régie’s request for different scenarios regarding differentiated rate
11
increases, the Distributor noted that there was no recognized rule or principle in this
12
field. ECS concurs. The approach taken on this issue varies by utility/regulator and
13
according to the particular circumstances that exist at the time. Considerations
14
regarding the degree of class rate increase differentials relative to the all customer
15
average can include:
16
•
The level of the overall rate increase,
17
•
The level of the rate increase relative to inflation and customer expectations,
18
•
The quality of the cost allocation study supporting the suggested need for
19
20
differentiated rate increases, and
•
21
22
The resulting impacts on individual customers when combined with proposed rate
design changes.
This view is illustrated by a recent BCUC decision73 which stated that:
23
24
25
26
27
28
29
30
31
32
33
With respect to BC Hydro’s bill impact test the Commission Panel agrees with
those Intervenors who submitted that the Commission should not endorse a “one
size fits all” approach to “rateshock” but should evaluate each application on its
own merits. In addition, as was noted in the Oral Phase of Argument by virtually
all counsel, the Commission has a considerable degree of latitude in determining
whether a proposed rate is fair, reasonable and not unduly discriminatory.
Counsel for BCOAPO observes that there is no “red light” to go off when a rate
crosses into “a zone that’s unfair, unreasonable or discriminatory” and that
“essentially the question for the Commission is this: Does the structure pass the
sniff test?” The Commission Panel agrees.
73
Order G-124-08, page 105
22
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
Also relevant is the statutory framework within which each regulator (and utility)
2
operates. In the case of BCUC and BCHydro, recent decisions by the regulator
3
regarding differentiated rate increases to reflect the results of BCHydro’s cost of service
4
study were subsequently set aside until 2010 by a change in the Utilities Commission
5
Act and any annual changes in revenue to cost ratios thereafter capped at 2%74. In the
6
Régie’s case, consideration must be given to the recent government Decree 1164-
7
200775 which requires:
8
9
10
11
12
13
14
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.
(Unofficial translation)
15
16
Another issue in HQD’s case is the impact of its ongoing rate design changes. While
17
the overall average rate increase proposed by HQD is just slightly in excess of the
18
forecast rate of inflation76, the rate design changes proposed for the various customer
19
classes mean that almost half the Residential customers (47.9%) will see increases in
20
excess of inflation77. Under HQD’s 40% maximum deviation scenario, the average rate
21
increase for Residential is 3.1% and more than 70% of customers have increases in
22
excess of inflation. Furthermore, while the average increase for the Residential class
23
may have a differential of only 40% over the average 2.2% increase, close to 40% of
24
the customers will see increases that are more than 1.5 times the average rate
25
increase.78
26
27
Finally, within the context of the current case, the Régie also needs to consider the
28
overall global economic environment within which HQD operates and the economic
74
Recently enacted s. 58.1 of the Utilities Commission Act.
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.
76
HQD-12, Doc 1, page 12
77
HQD-12, Doc 1, page 118
78
HQD-1, Doc 9, Question 19.1
75
23
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
uncertainty faced by all of its customers79. Under such circumstances, differentiated
2
rate increases could be viewed as unfairly targeting particular customers who are
3
already economically challenged.
4
5
In ECS’ view it would be inadvisable for the Régie to adopt a maximum deviation
6
approach. Simplistic formulae cannot capture the range of considerations that need to
7
go into determining the merits of a differentiated rate increase.
8
7
RESIDENTIAL RATE DESIGN
9
10
7.1
11
Background
HQD’s Proposal
12
13
HQD’s residential rate design strategy was outlined in its R-3579-2005 Application80 and
14
called for:
15
•
The daily fixed charge to be held constant (at 40.64 cents),
16
•
The rate for the second energy block to increase at double the increase of the rate
17
for the first usage block, and
18
•
19
($0.18/kW for bulk metered contracts).
20
The Régie has generally supported this strategy in its subsequent Decisions including
21
its most recent D-2008-024 decision81. However, in its last Decision the Régie
22
indicated82 that the costs included in the customer charge should be reviewed to ensure
23
the amount accurately reflects the fixed costs actually incurred to serve each customer.
The winter demand charge (for usage over 50 kW) to be increased by $0.75
24
25
As part of last year’s application HQD also gave notice that it was proposing to change
26
the application of demand charges to residential customers effective April 1, 2009.
27
These changes included:
79
HQD-2, Doc 1, pages 9-12
R-3579, HQD-13, Doc 1, pages 22-27
81
Pages 81-87
82
D-2008-024, page 81.
80
24
Evidence of
William Harper
1
•
Hydro-Québec Distribution
R-3677-2008
Applying the demand charge to power use in excess of 50 kW in any month of the
2
year. To limit annual rate impacts, the winter demand charge would be “frozen” at
3
the 2008 level and the summer demand charge increased by $0.63/kW/annum until
4
it reached the winter demand charge (roughly 10 years)83.
5
•
the previous 12 months84.
6
7
•
Billing customers whose power factor is below 90% based on kVA as opposed to
kW85.
8
9
Introduction of a minimum billing demand equal to 65 % of the maximum demand in
This proposed change was also supported by the Régie86.
10
11
HQD’s 2009 Application
12
13
In its current rate application HQD indicates87 that the level of the customer charge must
14
take into account a number of factors including:
15
•
The customer costs identified through the cost allocation study,
16
•
The desirability of stabilizing revenues,
17
•
The price signal inherent in the resulting rate structure.
18
Overall, HQD concludes that its current residential rate strategy, which includes a
19
continuation of the freeze in the customer charge, is appropriate and should be
20
continued for 200988.
21
22
7.2
23
In ECS’ view the setting of monthly service requires a balancing of the rate setting
24
objectives that include:
Comments
25
•
Reflecting Cost Causality
26
•
Sending the Appropriate Price Signal
83
HQD-12, Document 3, page 56
HQD-15, Document 8, Question 105 a)
85
HQD-12, Document 3, page 57
86
D-2008-024, pages 88-89
87
HQD-12, Doc 1, page 33
88
HQD-12, Doc 1, page 44
84
25
Evidence of
William Harper
•
1
Hydro-Québec Distribution
R-3677-2008
Customer Acceptance.
2
3
Cost Causality Considerations
4
5
Utility practice regarding the classification of costs as customer-related for purposes of
6
cost allocation varies widely. Some utilities include just basic customer costs (i.e.,
7
those related to customer service, billing and metering) while others may progressively
8
include other customer service costs, connection costs and minimum system costs.
9
Treating only metering, meter reading and billing costs as “fixed” customer-related costs
10
is one approach but represents what would be the minimum level of costs that could
11
generally be considered to be customer-related. Indeed, these costs could be viewed
12
as representing a “floor” in term of what would be a reasonable customer charge from a
13
cost causality perspective. The 2009 value of these costs is 20.31 cents per day89.
14
15
However, the Régie has approved a cost allocation methodology for HQD and the full
16
costs arising from this allocation also provide a benchmark as to what a reasonable
17
customer charge could be from a cost causality perspective. The 2009 value for these
18
costs is 64.67 cents per day90.
19
20
HQD’s proposal is that the customer charge should exclude connection and minimum
21
system costs but cover the cost of customer service and metering91. The 2009 costs of
22
customer service and metering total 38.91 cents per day. In contrast, application of the
23
alternative approach suggested by RNCREQ’s experts92 would appear to yield a 2009
24
value of 22.63 cents per day.
25
26
In ECS’ view, the HQD approach is more reasonable. First it fits comfortably within the
27
floor and ceiling values discussed above; while the alternative is just barely above the
89
Calculated based on HQD-12, Doc 1, Table 19 and including the costs for meter reading, billing, cash receipts and
metering.
90
HQD-12, Doc 1, page 36
91
HQD-12, Doc 1, page 35
92
ECS understands the method to include all Customer Service and Metering costs except for 90% of Collection
costs and 80% of the Call Centre costs.
26
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
floor value. Second, ECS questions the rationale behind excluding a material portion of
2
the Collections and Call Center costs.
3
4
The RNCREQ experts argued that Collections should be excluded since it related
5
mainly to bad debt93. However, less than half of the costs in Collections are attributable
6
to bad debt (i.e. $49 M out of $120.6M)94. The RNCREQ experts also argued for the
7
exclusion of most Call Centre costs on the basis that the 1-800-Énergie line dealt
8
mainly with energy conservation matters95. However, HQD’s evidence in this
9
proceeding96 suggests that only a small portion of the calls received relate to this 1-800
10
number. Finally, both HQD and the RNCREQ experts have excluded Connection costs
11
which arguably are incurred to offer service to a customer regardless of how much
12
energy is actually used.
13
14
Price Signal
15
16
Apart from considerations of cost causality, a lower customer charge would allow HQD
17
to further increase the energy rate in the second consumption block. Since the current
18
rate is 7.33 cents / kWh and the marginal cost of supply and transmission exceeds 10
19
cents / kWh97 this would allow the second block rate to more quickly approach marginal
20
costs98. However, as noted in the previous section, there are also year-over-year bill
21
impact considerations to take into account when considering how quickly rate design
22
changes should be implemented.
23
24
Since HQD’s current strategy was first adopted, the energy rate for the second energy
25
block in the Residential rate has increased from 6.32 cents / kWh (as of April 1st 2005)
26
to a proposed value of 7.56 cents per kWh (as of April 1st 2009). This represents an
93
R-3644-2008, Exhibit C-9-3, page 6
HQD-16, Doc 9, Question 28.2
95
R-3644-3008, Exhibit C-9-3, page 7 and December 12, 2007 Transcript, page 216
96
HQD-16, Doc 10, Question 24
97
HQD-12, Doc 1, page 54
98
HQD-12, Doc 1, page 41
94
27
Evidence of
William Harper
Hydro-Québec Distribution
R-3677-2008
1
increase of 19.6% over four years compared to a cumulative overall rate increase of
2
12.8% for the same period99 .
3
4
In ECS’ view the HQD rate design strategy reasonably balances issues of customer bill
5
impact versus the need to improve the pricing signal by aligning the price for
6
incremental electricity use with the utility’s marginal costs.
7
8
Practice Elsewhere
9
10
In terms of recent practice in other Canadian jurisdictions that ECS is familiar with:
11
•
A recent decision by the Manitoba Public Utilities Board directed Manitoba Hydro to
12
increase its monthly service charge in line with the overall rate increase. The Board
13
noted that the current charge (which is roughly half that of HQD’s) was well below
14
Manitoba Hydro’s actual customer based charges100. Indeed, Manitoba Hydro’s
15
customer charge as of April 1, 2007 was only $6.24 / month, while its cost allocation
16
results suggested that direct costs associated with just billing, metering and account
17
collection represented $6.18 per month101.
18
•
Following a recent proceeding dealing with BCHydro’s Residential Inclining Rate
19
Application, the BCUC accepted the Company’s proposal not to change the
20
emphasis on the customer charge which was set at 12.38 cents/day effective
21
October 1, 2008. The decision102 noted that the fully allocated cost of providing
22
distribution service was 35.22 cents per day while the cost of providing customer
23
billing and support service was 5.22 cents per day. However, the BCUC also found
24
that there was inadequate attention to the basic serviced charge in the Application
25
and directed BCHydro to address the role of service charge in its next rate design
26
application.
99
Based on increases of 5.3%, 1.9%, 2.9% and 2.2% for 2006, 2007, 2008 and 2009 respectively
MPUB Order 116/08, page 308
101
MH’s 2008 GRA Proceeding, COALITION/MH Information Request I-48 b)
102
Order G-124-08, pages 118-120
100
28
Evidence of
William Harper
1
•
Hydro-Québec Distribution
R-3677-2008
The OEB is in the process of reviewing the appropriate rate design for electricity
2
distribution utilities. As an interim measure, the Board directed103 distributors to
3
maintain their service charges within a range defined by:
4
o A floor based on meter-related, billing and collection costs, and
5
o An upper bound set at 120% of fully allocated customer costs.
6
7
Finally, in terms of the actual service charge level, HQD’s current customer charge is
8
comparable to that charged by other Canadian utilities104.
9
10
Overall, HQD’s practice regarding the setting of service charges is generally consistent
11
with that elsewhere.
12
13
8
CONCLUSIONS
14
15
8.1
16
•
17
18
Treatment of Weather Normalization Variance Account
HQD’s proposal to recover the $62 M in one year is reasonable given the context
of an average rate increase of 2.2% for each customer class.
•
HQD’s proposal to amortize the current $66.6 M remaining balance over five years
19
(and apply a similar treatment to annual variations recorded in the future) is also
20
reasonable.
21
22
8.2
23
•
24
25
Recovery of Operating Costs Associated with Major Outages
Some form of hybrid approach that includes an annual provision but also
recognizes the potential for significant cost variations is reasonable.
•
The Régie should adopt a variance account approach whereby a provision is set
26
each year for inclusion in the revenue requirement and any differences (forecast
27
versus actual) tracked in a variance account for future refund/recovery.
103
Application of Cost Allocation for Electricity Distributors, Report of the Board (EB-2007-0667), November,
2007
104
HQD-12, Doc 1, page 38
29
Evidence of
William Harper
1
•
2
HQD should be directed to make proposals regarding the disposition of any
outstanding balances in the variance account as part of its next rate application.
3
4
8.3
5
•
6
7
Hydro-Québec Distribution
R-3677-2008
Cost Allocation
ECS agrees with HQD’s position (and current practice) regarding the application of
HQT’s cost allocation methodology to HQD’s billed transmission costs.
•
The allocation of any refund/recovery of HQT’s PTP revenue variances should be
8
based on the contribution each Native Load customer class makes to HQD’s
9
coincident peak.
10
•
11
with the hourly method.
12
13
8.4
14
•
15
16
Differentiated Customer Class Rate Increases
Caution must be exercised in applying the results of HQD’s approach to
determining the evolution of costs and the need for differentiated rate increases.
•
17
18
HQD’s treatment of surplus power purchases and resale revenues is consistent
The Régie should not adopt a simplistic formula such as a maximum deviation
approach as the basis for determining differentiated rate increases.
•
19
In making decisions regarding the need for differentiated rate increases the Régie
should also take into account the range of bill impacts by customer class.
20
21
8.5
22
•
Residential Rate Design
HQD’s current approach to setting the residential service charge is appropriate.
23
The resulting service charge for 2009 reasonably reflects customer-related costs
24
and allows continued evolution of the second block energy rate towards marginal
25
costs.
26
30
APPENDIX A
CV FOR ECS CONSULTANT
31
ECONALYSIS CONSULTING SERVICES
William O. Harper
Mr. Harper has over 25 years experience in the design of rates and the regulation of
electricity utilities. While employed by Ontario Hydro, he has testified as an expert
witness on rates before the Ontario Energy Board from 1988 to 1995, and before the
Ontario Environmental Assessment Board. He was responsible for the regulatory policy
framework for Ontario municipal electric utilities and for the regulatory review of utility
submissions from1989 to 1995. Mr. Harper also coordinated the participation of Ontario
Hydro (and its successor company Ontario Hydro Services Company) in major public
reviews involving Committees of the Ontario Legislature, the Ontario Energy Board and
the Macdonald Committee. He has served as a speaker on rate and regulatory issues for
seminars sponsored by the APPA, MEA, EPRI, CEA, AMPCO and the Society of
Management Accountants of Ontario. Since joining ECS, Mr. Harper has provided
consulting support for client interventions on energy and telecommunications issues
before the Ontario Energy Board, Manitoba Public Utilities Board, Québec’s Régie de
l’énergie, British Columbia Utilities Commission, and CRTC. He has also appeared
before the Manitoba’s Public Utilities Board, the Manitoba Clean Environment
Commission, the Ontario Energy Board, the Saskatchewan Rate Review Panel and
Quebec’s Régie de l’énergie. Bill is currently a member of the Ontario Independent
Electricity System Operator’s Technical Panel.
EXPERIENCE
Econalysis Consulting Services- Senior Consultant
2000 to present
•
Responsible for supporting client interventions in regulatory proceedings,
including issues analyses & strategic direction, preparation of interrogatories,
participation in settlement conferences, preparation of evidence and appearance as expert
witness (where indicated by an asterix). Some of the more significant proceedings
included:
•
o
o
o
o
o
o
o
o
o
o
Electricity (Ontario)
IMO 2000 Fees (OEB)
Hydro One Remote Communities Rate Application 2002-2004
OEB - Transmission System Code Review (2003)
OEB - Distribution Service Area Amendments (2003)
OEB - Regulated Asset Recovery (2004)
OEB - 2006 Electricity Rate Handbook Proceeding*
OEB - 2006 Rate Applications by Various Electricity Distributors
OEB - 2006 Guidelines for Regulation of Prescribed Generation Assets
OEB -2007 Rate Applications by Various Electricity Distributors
OEB- 2007 Cost of Capital and 2nd Generation Incentive Regulation Proceeding
32
o OEB - Hydro One Networks 2007/2008 Transmission Rate Application
o OEB – 2008 Rate Applications by Various Electricity Distributors
•
Electricity (British Columbia)
o BC Hydro IPP By-Pass Rates
o BC Hydro Heritage Contract Proposals
o BC Hydro’s 2004/05; 2005/06; 2007/09 and 2008/10 Revenue Requirement
Applications
o BC Hydro’s CFT for Vancouver Island Generation – 2004
o BC Hydro’s 2005 Resource Expenditure and Acquisition Plan
o BC Hydro’s 2006 Residential Time of Use Rate Experiment Application
o BC Hydro’s 2006 Integrated Electricity Plan
o BC Hydro’s 2007 Rate Design Application
o BC Hydro’s 2008 Residential Inclining Block Rate Application
o BC Transmission Corporation – Open Access Transmission Tariff Application 2004
o BCTC’s 2005/06; 2006/07 and 2007/09 Revenue Requirement Applications
o BCTC’s – 2005 Vancouver Island Transmission Reinforcement Project
o Fortis BC’s 2005 Revenue Requirement and System Development Application
o Fortis BC’s 2006; 2007 and 2008 Revenue Requirement Applications
o Fortis BC’s 2007/08 and 2009/10 Capital Plan and System Development Plans
o FortisBC’s 2007 Rate Design Application
•
Electricity (Quebec)
o Hydro Québec-Distribution’s 2002-2011 Supply Plan*
o Hydro Quebec-Distribution’s 2002-2003 Cost of Service and Cost Allocation
Methodology*
o Hydro Québec - Distribution’s 2004-2005 Tariffs*
o Hydro Québec - Distribution’s 2005/2006 Tariff Application*
o Hydro Québec - Distribution’s 2005-2014 Supply Plan*
o Hydro Québec - Distribution’s 2006/2007 Tariff Application*
o Hydro Québec - Transmission’s 2005 Tariff Application*
o Hydro Québec - Distribution’s 2006 Interruptible Tariff Application
o Hydro Québec - Distribution’s 2006 Cost Allocation Work Group
o Hydro-Québec - Transmission’s 2007 Tariff Application
o Hydro-Québec - Distribution’s 2007/08 Tariff Application*
o Hydro-Québec - Distribution’s 2008/09 Tariff Application*
•
o
o
o
o
o
o
o
Electricity (Manitoba)
Manitoba Hydro’s Status Update Re: Acquisition of Centra Gas Manitoba Inc.*
Manitoba Hydro’s Diesel 2003/04 Rate Application
Manitoba Hydro’s 2004/05 and 2005/06 Rate Application*
Manitoba Hydro/NCN NFAAT Submission re: Wuskwatim*
Manitoba Hydro’s 2005 Cost of Service Methodology Submission*
Manitoba Hydro’s 2007 Rate Adjustment Application
Manitoba Hydro’s 2008 General Rate Application*
33
•
Electricity (Saskatchewan)
o Saskatchewan Power’s 2008 Cost Allocation Methodology Review
•
o
o
o
o
Natural Gas Distribution
Enbridge Consumers Gas 2001 Rates
BC Centra Gas Rate Design and Proposed 2003-2005 Revenue Requirement
Rate of Return on Common Equity (BCUC)
Terasen Gas (Vancouver Island) LNG Storage Project (2004)
•
Telecommunications Sector
o Access to In-Building Wire (CRTC)
o Extended Area Service (CRTC)
o Regulatory Framework for Small Telecos (CRTC)
•
Other
o Acted as Case Manager in the preparation of Hydro One Networks’ 2001-2003
Distribution Rate Applications
o Supported the implementation of OPG’s Transition Rate Option program prior to
Open Access in Ontario
o Prepared Client Studies on various issues including:
o The implications of the 2000/2001 natural gas price changes on natural
gas use forecasting methodologies.
o The separation of electricity transmission and distribution businesses in
Ontario.
o The business requirements for Ontario transmission owners/operators.
o Various issues associated with electricity supply/distribution in remote
communities
o Member of the OEB’s 2004 Regulated Price Plan Working Group
o Member of the OEB’s 2005/06 Cost Allocation Technical Advisory Team
o Member of the OEB’s 2008 3rd Generation Incentive Regulation Working Group
o Member of the IESO Technical Panel (April 2004 to Present)
Hydro One Networks
Manager - Regulatory Integration, Regulatory and Stakeholder Affairs
(April 1999 to June 2000)
•
Supervised professional and administrative staff with responsibility for:
o providing regulatory research and advice in support of regulatory
applications and business initiatives;
o monitoring and intervening in other regulatory proceedings;
o ensuring regulatory requirements and strategies are integrated into
business planning and other Corporate processes;
o providing case management services in support of specific regulatory
applications.
34
•
Acting Manager, Distribution Regulation since September 1999 with
responsibility for:
o coordinating the preparation of applications for OEB approval of changes
to existing rate orders; sales of assets and the acquisition of other
distribution utilities;
o providing input to the Ontario Energy Board’s emerging proposals with
respect to the licences, codes and rate setting practices setting the
regulatory framework for Ontario’s electricity distribution utilities;
o acting as liaison with Board staff on regulatory issues and provide
regulatory input on business decisions affecting Hydro One Networks’
distribution business.
•
Supported the preparation and review before the OEB of Hydro One Networks’
Application for 1999-2000 transmission and distribution rates.
Ontario Hydro
Team Leader, Public Hearings, Executive Services (Apr. 1995 to Apr. 1999)
Supervised professional and admin staff responsible for managing Ontario
•
Hydro’s participation in specific public hearings and review processes.
•
Directly involved in the coordination of Ontario Hydro’s rate submissions to the
Ontario Energy Board in 1995 and 1996, as well as Ontario Hydro’s input to the
Macdonald Committee on Electric Industry Restructuring and the Corporation’s
appearance before Committees of the Ontario Legislature dealing with Industry
Restructuring and Nuclear Performance.
Manager – Rates, Energy Services and Environment (June 1993 to Apr. 95)
Manager – Rate Structures Department, Programs and Support Division
(February 1989 to June 1993)
Supervised a professional staff with responsibility for:
•
o Developing Corporate rate setting policies;
o Designing rates structures for application by retail customers of Ontario
Hydro and the municipal utilities;
o Developing rates for distributors and for the sale of power to Hydro’s
direct industrial customers and supporting their review before the Ontario
Energy Board;
o Maintaining a policy framework for the execution of Hydro’s regulation
of municipal electric utilities;
o Reviewing and recommending for approval, as appropriate, municipal
electric utility submissions regarding rates and other financial matters;
o Collecting and reporting on the annual financial and operating results of
municipal electric utilities.
•
Responsible for the development and implementation of Surplus Power, Real
Time Pricing, and Back Up Power pricing options for large industrial customers.
•
Appeared as an expert witness on rates before the Ontario Energy Board and
other regulatory tribunals.
35
•
Participated in a tariff study for the Ghana Power Sector, which involved the
development of long run marginal cost-based tariffs, together with an
implementation plan.
Section Head – Rate Structures, Rates Department
November 1987 to February 1989
•
With a professional staff of eight responsibilities included:
o Developing rate setting policies and designing rate structures for
application to retail customers of municipal electric utilities and Ontario
Hydro;
o Designing rates for municipal utilities and direct industrial customers and
supporting their review before the Ontario Energy Board.
Participated in the implementation of time of use rates, including the development
•
of retail rate setting guidelines for utilities; training sessions for Hydro staff and
customers presentations.
•
Testified before the OEB on rate-related matters.
Superintendent – Rate Economics, Rates and Strategic Conservation Department
February 1986 to November 1987
Supervised a Section of professional staff with responsibility for:
•
o Developing rate concepts for application to Ontario Hydro’s customers,
including incentive and time of use rates;
o Maintaining the Branch’s Net Revenue analysis capability then used for
screening marketing initiatives;
o Providing support and guidance in the application of Hydro’s existing rate
structures and supporting Hydro’s annual rate hearing.
Power Costing/Senior Power Costing Analyst, Financial Policy Department
April 1980 to February 1986
•
Duties included:
o Conducting studies on various cost allocation issues and preparing
recommendations on revisions to cost of power policies and procedures;
o Providing advice and guidance to Ontario Hydro personnel and external
groups on the interpretation and application of cost of power policies;
o Preparing reports for senior management and presentation to the Ontario
Energy Board.
•
Participated in the development of a new costing and pricing system for Ontario
Hydro. Main area of work included policies for the time differentiation of rates.
36
Ontario Ministry of Energy
Economist, Strategic Planning and Analysis Group
April 1975 to April 1980
•
Participated in the development of energy demand forecasting models for the
province of Ontario, particularly industrial energy demand and Ontario Hydro’s
demand for primary fuels.
•
Assisted in the preparation of Ministry publications and presentations on
Ontario’s energy supply/demand outlook.
•
Acted as an economic and financial advisor in support of Ministry programs,
particularly those concerning Ontario Hydro.
EDUCATION
Master of Applied Science – Management Science
University of Waterloo, 1975
•
•
Major in Applied Economics with a minor in Operations Research
•
Ontario Graduate Scholarship, 1974
Honours Bachelor of Science
•
University of Toronto, 1973
•
Major in Mathematics and Economics
•
Alumni Scholarship in Economics, 1972
37