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Allwest Reporting Ltd. #1200 - 1125 Howe Street Vancouver, B.C. V6Z 2K8
BRITISH COLUMBIA UTILITIES COMMISSION
IN THE MATTER OF THE UTILITIES COMMISSION ACT R.S.B.C. 1996, CHAPTER 473
And
British Columbia Hydro and Power Authority 2013 Residential Inclining Block (RIB) Rate Re-pricing
Application ~ Project No.3698761
BEFORE:
R. REVEL Panel Chair/Commissioner
VOLUME 1
Streamlined Review Oral Proceeding
Vancouver, B.C. January 29th, 2014
APPEARANCES R. REVEL B.C. Utilities Commission P. MILLER Commission Counsel E. CHENG Commission Staff R. FRASER Commission Staff J. ASHLEY Commission Staff P. NAKONESHNY Commission Staff W.J. ANDREWS Counsel for B.C. Sustainable Energy
Association and Sierra Club of B.C. (BCSEA/SEA)
B. BROWNELL FortisBC B. PERTTULA FortisBC C. CRAIG Counsel for Commercial Energy Consumers
(CEC) E. PRITCHARD Counsel for BCPSO S. KHAN Counsel for BCPSO A. JUBB B.C. Hydro R. REIMANN B.C. Hydro G. DOYLE B.C. Hydro C. GODSOE Counsel for B.C. Hydro
INDEX PAGE
PRESENTATION BY B.C. HYDRO .....................7
SUBMISSIONS BY MR. GODSOE .....................71
SUBMISSIONS BY MS. PRITCHARD ..................78
SUBMISSIONS BY MR. CRAIG ......................79
SUBMISSIONS BY MR. PERTTULA ...................84
SUBMISSIONS BY MR. ANDREWS ....................86
REPLY BY MR. GODSOE ...........................90
INFORMATION REQUESTS For Commissioner Revel: Pages: 70
B.C. Hydro 2013 RIB Re-Pricing January 29, 2014, SRP Page: 1
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CAARS
VANCOUVER, B.C.
January 29, 2014
(PROCEEDINGS RESUMED AT 9:01 A.M.)
THE CHAIRPERSON: Thank you very much. Good morning,
ladies and gentlemen. My name is Richard Revel, and
I’m a Commissioner with the British Columbia Utilities
Commission. I’ve been appointed by the Commission to
address the B.C. Hydro residential inclining block
rate re-pricing application, filed on November the 1st,
2013.
Also with us today from the Commission is
Ms. Eileen Cheng. She is the lead staff for this
application, along with her fellow Commission staff,
Jackie Ashley. And in addition, we have staff
consultant Mr. Jim Fraser.
Mr. Paul Miller of Boughton Law is acting
as Commission counsel for this proceeding. And
Allwest Reporting Limited will be providing
transcripts for the proceeding.
Today’s SRP process will address B.C.
Hydro’s proposed pricing principle for the RIB rate
for the fiscal 2015 and 2016 years. It is important
to note that since the application came in, the
provincial government on November the 26th, 2013,
approved the B.C. Hydro integrated resource plan and
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directed B.C. Hydro that its annual revenue
requirement rate increases will be at 9 percent for
the fiscal 2015 and at 6 percent for the fiscal 2016.
Pursuant to Commission Order G-45-11,
issued on March the 14th, 2011, B.C. Hydro filed its
2013 RIB rate re-pricing application on November the
1st, 2013. In this application, B.C. Hydro is seeking
approval of the pricing principle under which the
fiscal 2015/2016 revenue requirement application rate
increases would apply uniformly to each of the RIB’s
three main elements, which constitute of the basic
charge, the step one energy rate, and the step two
energy rate. This is known as Option 2 in the B.C.
Hydro application.
Proceeding Time 9:03 a.m. T2
B.C. Hydro is not seeking any change to
other aspects of the RIB rate design, other than the
proposed pricing principle for the two-year period of
fiscal 2015 and 2016.
In the application, B.C. Hydro is also
seeking relief from certain elements of Directive 4 of
Order G-45-11, and seeking a determination to dissolve
the RIB control group which was set up for research
purposes.
Prior to filing the application, B.C. Hydro
held two workshops with stakeholders who had
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participated in the 2008 RIB rate application
proceeding and in the 2011 RIB rate re-pricing
application proceeding.
In this hearing, six parties have
registered as interveners: the B.C. Sustainable
Energy Association and the B.C. Sierra Club of British
Columbia, known collectively as the BCSEA; the
Canadian Office of Professional Employees Union Local
378, referred to as COPE 378; the British Columbia
Pensioners’ and Seniors’ Organization, referred to as
the BCPSO; FortisBC Utilities, referred to as FBCU;
the B.C. Ministry of Energy and Mines, referred to as
MEM; and the Commercial Energy Consumers’ Association
of British Columbia, referred to as the CEC.
Commission and Intervener Information
Requests No. 1 were issued to B.C. Hydro on November
the 20th, 2013, and on December the 19th, 2013, B.C.
Hydro submitted its responses to IRs by all parties.
After reviewing the submissions from parties in this
proceeding, on January the 13th, 2014 by Order G-4-14,
the Commission determined that a review process by way
of a streamlined review process would be held on
January the 29th, 2014.
Proceeding Time 9:06 a.m. T03
B.C. Hydro informed the Commission that it
has contacted the BCPSO and the CEC to understand the
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issues they wish to explore at this hearing.
On January the 20th, 2014, the Commission
received a request for late intervener status from the
Association of Major Power Customers of British
Columbia, referred to as the AMPC. That request was
granted. AMPC indicated in its letter that it expects
to be an observer in this proceeding, but may wish to
file comments or final argument, depending on how the
proceeding before us and issues evolve.
That, ladies and gentlemen, brings us to
the task in front of us today. This application is
being dealt with today in accordance with the policy
guidelines and procedures for the streamlined review
process as set out by the Commission in Order G-37-12.
Further, a letter summarizing the process was sent to
participants on January the 24th, 2014. Also in
accordance with that process, after my opening
remarks, we will register appearances, followed by
B.C. Hydro giving a brief overview of the application
and approvals sought. Questions of clarification may
be asked during the B.C. Hydro presentation.
After B.C. Hydro’s presentation, other
hearing participants will have an opportunity to
explain their interests. Participants will then have
an opportunity to ask questions of B.C. Hydro. To
assist Allwest Reporting in keeping the transcript
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clear, I ask that all individuals identify themselves
for the record before asking a question or making a
comment. I also request, and suggest it would help
Allwest, if we are clear in our presentations and
speak clearly and loudly.
At the conclusion of the question period,
we will take a short break, followed by B.C. Hydro
making a final submission on the application. The
interveners will then be invited to provide their
final submissions, followed by an opportunity for B.C.
Hydro to reply.
The streamlined review process is a more
informal process than the standard regulatory written
or oral hearing. Parties have an opportunity to
explore issues of concern to them and B.C. Hydro is
expected to address these issues in an open and
fulsome manner.
Proceeding Time 9:09 a.m. T4
Before we proceed with the B.C. Hydro
presentation, we will register appearances by going
around the table and briefly introduce ourselves and
our affiliation. I will initiate the process and then
we’ll proceed around the table to my right.
I’m Richard Revel, Commissioner with the
British Columbia Utilities Commission.
MR. MILLER: Paul Miller, Boughton Law Corporation,
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Commission Counsel.
MS. CHENG: Eileen Cheng, Commission Staff.
MR. FRASER: Rick Fraser. I’m a consultant working with
Commission Staff.
MS. ASHLEY: Jackie Ashley, Commission Staff.
MR. NAKONESHNY: Philip Nakoneshny, Commission Staff.
MR. ANDREWS: Bill Andrews, counsel for the B.C.
Sustainable Energy Association and Sierra Club B.C.
MR. BROWNELL: Bob Brownell for Fortis.
MR. PERTULLA: Bill Perttula, with FortisBC.
MR. CRAIG: David Craig with the Commercial Energy
Consumers.
MS. PRITCHARD: Erin Pritchard, counsel for BCPSO.
MS. KHAN: Sarah Khan, counsel for BCPSO, but I’m just
here as an observer.
MS. JUBB: Anthea Jubb, B.C. Hydro.
MR. REIMANN: Randy Reimann, B.C. Hydro
MR. DOYLE: Gordon Doyle, B.C. Hydro.
MR. GODSOE: Good morning, Commission Revel, Commission
Staff and registered interveners. My name is Craig
Godsoe. I’m B.C. Hydro’s in-house regulatory counsel.
I just wanted to point out that given this is B.C.
Hydro’s first streamlined review process, we do have
two observers. They wanted me to emphasize they are
not here to answer questions. First is Ms. Janet
Fraser, our Chief Regulatory Officer; and second is
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Mr. Robert Gorder, who’s Senior Regulatory Specialist
with B.C. Hydro.
THE CHAIRPERSON: I welcome them. And I believe we
missed two names at the very back.
MS. HERBST: Good morning, Ludmila Herbst (inaudible).
THE CHAIRPERSON: Welcome.
MS. HERBST: Thank you.
THE CHAIRPERSON: With that, I think now, B.C. Hydro, if
you’d like to proceed with your presentation that
would be well received.
PRESENTATION BY B.C. HYDRO:
Good morning and thank you very much for
everyone’s participation in B.C. Hydro’s 2013 RIB
pricing principle application. We’ve tailored our
presentation today to try and reflect the areas of
interest identified by BCUC Staff and intervener
groups at the January 20th session that we held, to
identify topics that stakeholders were interested in
pursuing further at this streamlined review process.
So as far as an outline of today’s
presentation, I’m going to speak to the application,
what B.C. Hydro is seeking out of the -- in the
application. We’ll then get into a discussion on some
of the key issues in the application, as well as
identify it at the January 20th session. I will speak
to the pricing principles including the identification
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of the options that were considered and evaluated.
Randy Reimann will speak to the long-run marginal cost
and what forms the basis of the long-run marginal cost
and how that compares to previous long-run marginal
costs that B.C. Hydro has developed. And he will
speak to the RIB valuation and control group, which is
primarily Attachment C of B.C. Hydro’s application,
the evaluation report. And then I will speak a little
bit about the F2016 rate design application and the
scope and timing associated with that. And finally
I’ll provide some concluding remarks to our
presentation.
THE CHAIRPERSON: Thank you.
MR. DOYLE: So excuse me if this is a little bit of
rehash from Commissioner Revel’s opening remarks. So
B.C. Hydro is seeking approval of a proposed pricing
principle for two years, that being F2015 and 2016.
And the main reason behind this is that the current
pricing principle that has been in place for the F12
to F14 period will expire on March 31st of this year.
We view this application as a bridge to the F2016 rate
design application.
B.C. Hydro is proposing Option 2, which
would see the application of RRA increases to each of
the three main elements of the residential and
climbing block rate, that being the basic charge, the
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Step 1 energy price as well as the Step 2 energy
price.
Proceeding Time 9:14 a.m. T05
Doing so will maintain the proportional
difference between the Step 1 and Step 2 rate. And it
also -- the result is that all customer bill impacts
will be limited to the class average rate change, or
in this case 9 percent in F2015 and 6 percent in
F2016.
We are also seeking relief from certain
elements of Directive 4 of BCUC Order G-45-11. That’s
further described in Section 1.4 of our application.
But in particular we are seeking relief of the review
of the setting of the Step 1 and Step 2 consumption
thresholds, as well as the interaction of the basic
charge and rate structure.
As mentioned by Commissioner Revel in his
opening remarks, we did hold two consultation sessions
in September and August, in which we discussed -- the
scope was reviewed with our stakeholders, intervener
groups and BCUC staff. We are also seeking to
dissolve the RIB control group with the application.
So as I mentioned, B.C. Hydro has developed
three options for pricing principles for the F15 and
16 period. I think of note is that all of these
options are revenue-neutral. And it’s also important
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to note that in previous Commission decisions in
previous applications, the long-run marginal cost of
energy was above the Step 2 rate. And the pricing
principles reflected the thought, or the mechanism to
try and chase the long-run marginal cost by providing
a greater proportion of the rate increases being
applied to the Step 2 rate, to try and raise that Step
2 rate to meet that sort of -- the efficiency of
meeting the long-run marginal cost.
As discussed in our application, and Ms.
Randi will speak to it shortly, B.C. Hydro’s current
long-run marginal cost forecast is between $85 and
$100, which is even, at the top end of that range, at
$100, is currently below -- or is below B.C. Hydro’s
current Step 2 rate, and would remain below the rate
for -- Step 2 would remain above the rates under all
options considered.
So, going through the options, option 1
would be what we call -- what we have labeled the
status quo, which would continue to see the RA
increases be applied more aggressively to the Step 2.
And that would -- the result of that would be widening
of the differential between Step 1 and Step 2, as well
as providing a greater variance with the Step 2 rate
getting further and further above the long-run
marginal cost.
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This option we view as -- it doesn’t
necessarily meet the criteria of efficiency as
outlined by -- in previous BCUC decisions as having
the Step 2 rate reflect the long-run marginal cost of
energy.
So moving down to option 2, which is our
proposed -- as I mentioned, we are looking to increase
the Step 1 and Step 2 rates by the revenue requirement
increases. So they will move up proportionally
together, and the result of that is that even though
the Step 2 will remain above the long-run marginal
cost, that the rate of growth is slowed and mitigated.
Under option 3, we call it the “flattened”
option, we see -- we would apply a greater proportion
of the revenue requirement increases to Tier 1. So
what that would do is, we would increase Tier 1 more
rapidly than Tier 2, which served to flatten or narrow
the distance between the Step 1 and Step 2 rates, and
also serve to slow the growth of the Step 2 rate above
long-run marginal cost.
Proceeding Time 9:18 a.m. T06
Also of note, I think also important to
look at, when evaluating these options, is the bill
impacts. We know that the revenue requirement
increases will be 9 and 6 percent for ’15 and ’16
respectively. So turning to the bill impact
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associated with the two -- or with the three options,
under option 1, we would see a greater bill impact to
the higher consuming customers, and that’s because we
have applied more of the revenue requirement increases
to Step 2, and as a result those customers who have a
greater exposure to Step 2 would have larger bill
impacts.
Under option 2, we would see bill impacts
consistent at the revenue requirement increased level
for all customers being 9 and 6 percent for ’15 and
’16. And under option 3, we would see a greater
impact to the lower-consuming customers. I think also
important to note under option 3, is that the impact
to low-income customers, as it’s described in Table 2-
5 plus of B.C. Hydro’s supplemental filing that
updated all the tables and the revenue -- in the
application, after the revenue requirement increases
were known, we see that about 72 percent of the
customer -- of low-income customers would experience a
bill impact above the class average rate change, or
the revenue requirement in F15, and about 82 percent
of low-income customers would see a bill impact
greater than the class average rate change in F16.
So B.C. Hydro is recommending going with
option 2, in that it maintains the rate structure
conservation, while not providing for unreasonable
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bill impacts to all customers relative to the other
options.
And I’ll now hand it over to Randy to speak
to the long-run marginal cost of energy.
MR. REIMANN: Thanks, Gordon. So B.C. Hydro’s long-run
marginal cost, as Gordon said, is $85 to $100 to a
BCPSO question. That’s expressed in fiscal 2013
dollars, or real dollars.
It is a levelized firm energy price for
Lower Mainland delivery. And that’s largely driven by
the majority of the DSM savings being in the Lower
Mainland.
The long-run marginal cost was set out in
the approved IRP, and it’s based on the marginal
energy resources needed to drive the right level of
supply. While the IRP did look at a 20-year period,
including the expectation that Site C would be
approved and move forward, and that the long-run
marginal cost would be appropriate for 20 years, I
think for the purposes of this application, in
particular the next two years, the focus is on what
resources might be needed in the next ten years.
And what we see over that period is that
the marginal resources are a combination of DSM
programs and EPA renewals with RIPP.
And so what we came to the realization was
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is that we don’t see a need for any new additional
clean call processes. And so the existing long-run
marginal cost in the $135 range was no longer
required.
So there was some questions about how we
came to that long-run marginal cost, and I’ll just
walk through that quickly. When we started looking at
the integrated resource plan, and what actions were
appropriate in the next few years that we needed to
commit to, and we looked at our load resource
balances, it was clear that additional IPPs weren’t
required, and that some combination of IPP, EPA
renewals and DSM was adequate.
The problem that we faced is that on the
DSM side, it’s very difficult to see the granularity
of what that next light bulb, or the next efficient
clients, might cost. It’s not the way we create the
DSM programs. Rather, we give the DSM folks a price
signal, and they, using that price signal as a sort of
a maximum financial limit, they then look at the level
of effort that they can put out there and the
incentives they can provide, and what that would
provide. And it really gave us three options of DSM
option 1, 2, and 3.
Proceeding Time 9:22 a.m. T7
And so, similarly then with the EPA
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renewals, because these are intended to be negotiated
prices, where we try to get them to what their
opportunity cost is, which at the lower end would be
what they could get for it in the market, up to what
they needed to keep their projects going.
So given that those two were not that clear
but we were still intending to try to drive out a
resource stack, we came about it the other way and
said okay, let’s pick a price level and say, so if
your limit is $100 a megawatt hour, what is it that
you think you can deliver from that? The result of
that at $100 a megawatt hour is that’s pretty much the
price signal that was used for the DSM Option 2, and
it would allow us to renew most of the EPAs that we
have coming due in the next ten years. That is about
75 percent of run of river projects that are coming
due, and we estimated about 50 percent of the biomass
projects that are going to be coming due. And so that
went into the IRP and that was accepted as a
reasonable level of activity.
There was some sense as we went through the
IRP that in fact maybe the $100 could be a little bit
lower, but there’s a lot of uncertainty that we’re
facing over the next ten years, and those
uncertainties are the degree that DSM delivers,
whether or not the Site C project is approved or not.
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THE CHAIRPERSON: May I just interject?
MR. REIMANN: Sure.
THE CHAIRPERSON: How comfortable are you with the upper
limit of your estimate?
MR. REIMANN: I think pretty comfortable.
THE CHAIRPERSON: Okay.
MR. REIMANN: I think it’s a reasonable price signal and
it gets us to a level that -- it shows still a bit of
a surplus of energy in the low resource balance before
Site C comes on.
THE CHAIRPERSON: Thank you very much.
MR. REIMANN: Yes. So the other uncertainties are the
LNG load and how much of that was going to occur, and
how successful we would be on the EPA renewal.
There was another question that was raised,
I think by the BCPSO, about what resources would be at
or near that $100 per megawatt hour price, and there’s
two really that are similar. There’s a standing offer
program and the DSM new home program, but that wasn’t
necessarily the driver of the $100 target.
MR. PERTTULA: It’s Dave Perttula here from FortisBC. I
was trying to find where in the IRP would be the best
place to go to find this discussion and the
background, and I didn’t have that much time to do it
but I couldn’t find it. So do you have some
references as to where to --
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MR. REIMANN: There’s a section in Chapter 9 that talks
about how we arrived at the long-run marginal cost.
MR. PERTTULA: Okay.
MR. REIMANN: The discussion is quite similar to what was
put into the RIB application.
MR. PERTTULA: Thank you.
MR. REIMANN: This slide was created in response to a
BCUC Staff question that wanted to see the comparison
of what was in the 2010 application and how that
compared to this 2013 application. And so what we’ve
shown here is the 2013 application was based on the
marginal resource of Greenfield IPPs and it was based
on our most recent open call for power, the 2009 green
power call plant day price. And then it had
transmission and distribution loss adjustments for
Lower Mainland delivery, and those prices escalated to
fiscal '13 dollars, would be $135 a megawatt hour, and
for fiscal '15 dollars would be 140.
In contrast then, what we’re suggesting for
this application is that the fiscal '13 price, long-
run marginal cost is $100 as an upper bound, and that
would be in fiscal '15 dollars 104, and again it’s
based on incremental DSM and EPA. And we view this as
Lower Mainland delivery, and so the range of 85 to 100
dollars given the uncertainty.
MR. DOYLE: Okay, thanks, Randy.
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So looking at long-run marginal costs for
rate-making, so why is the long-run marginal cost
important to this application? Well, I think that
goes back to the Bonbright criterion of -- that the
rate should provide a price signal that encouraged the
efficient use of energy and discourages the
inefficient use of energy.
As far as how we’ve defined the efficiency
use of energy, B.C. Hydro has been guided by previous
BCUC decisions, in particular the two previous RIB
decisions, that being the 2008 RIB application, the
decision following that, as well as the decision G-45-
11 which was the decision on B.C. Hydro’s December
2010 RIB pricing principle application.
Proceeding Time 9:28 a.m. T08
In all instances, the Commission determined
that LRMC is the appropriate reference for this Step 2
rate for the residential inclining block. The
Commission also made a similar determination in
FortisBC’s 2011 RIB application.
The Commission has also determined that
pricing electricity above long-run marginal cost is
not economically efficient. And that there is also no
legislative requirement to maximize conservation. So
B.C. Hydro has been guided by sort of these principles
in its development and evaluation of the options, and
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how the Step 2 reflects the long-run marginal cost.
So, B.C. Hydro has used the upper end of
the range provided by Randy, $85 to $100 range, I
guess conservatively for this application. And in all
cases, the Step 2 rate exceeds the long-run marginal
cost. And in fact the long-run marginal cost is
currently below the F2014 Step 2 rates.
Anthea will speak to the evaluation and
control group.
MS. JUBB: Thanks, Gordon. So, the RIB evaluation, the
full report is included as Appendix C to the
application. The RIB evaluation covered the time
frame from the introduction of the RIB through to the
end of F12. Highlights from the evaluation include
the finding that the rate is achieving its overall
objective of encouraging conservation. Three
empirically derived statistically valid models
produced a range of Step 2 price elasticities between
negative 0.08 and negative 0.13. And this range
encompasses the negative 0.1 that was used for
planning purposes.
The evaluation also found that half of RIB
customers are aware of the rate and of those, eight in
ten believe that the rate structure serves as an
incentive to conserve energy.
Now, I understand that all of the questions
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from the January 20th session regarding the RIB
evaluation had to do with the control group. So I’ll
spend a bit of time on that issue now.
The control group was created in 2006 for a
purpose unrelated to the RIB. As a result, it has
never been fully representative of the population of
RIB customers. And with the passage of time, a number
of accounts have been lost from the control group.
Therefore, in its current state, it is combined with
its small size and lack of representation of the
general population, it provides little value for the
purpose of evaluating the RIB rate.
As described in the evaluation report, a
model baseline was intended to provide a substitute
for the control group. However, those modeling
attempts were unsuccessful as we were unable to
produce statistically valid models of the baseline.
Now, one of the interveners suggested the
possibility of using consumption data for New
Westminster, and that is an interesting idea. As New
Westminster customers are under a flat rate, it is
possible that using this consumption data, in the
econometric models described in the evaluation, could
produce an estimate of elasticity under the flat rate.
However, there are a number of barriers to
that approach. If B.C. Hydro concludes that a control
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group would be useful, then it would apply to create
one prior to the RDA.
Now, Gordon is going to just --
THE CHAIRPERSON: May I interject, if you don’t mind?
What is it in your view that would provoke B.C. Hydro
to institute such a group?
MS. JUBB: The group has several advantages. The primary
objective of an impact evaluation is to determine the
net impacts of an intervention such as RIB. So
ideally we have an empirically derived estimate of
total conservation, as well as an empirically derived
estimate of natural conservation. And that natural
conservation sets the baseline.
As described in the RIB report, we were
able to get an empirically derived estimate of total
conservation, but not natural conservation. So we
used the planning assumption for the baseline.
So the primary advantage of a control group
is that it would provide an estimate of natural
conservation and if that control group were
representative of the general population of RIB
customers, then the change in their consumption could
be compared to the change of RIB customers, their
consumption, in order to get an estimate of structural
conservation due to the RIB.
THE CHAIRPERSON: So if you concluded it was desirable,
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it could give you a lot of good information, is the --
MS. JUBB: It could.
THE CHAIRPERSON: If you could get a group. Thank you
very much, and sorry for interrupting.
Proceeding Time 9:33 a.m. T9
MR. DOYLE: Thank you. So, as I discussed earlier, B.C.
Hydro has sought relief from certain elements of
directive G-45-11. In particular, the setting of the
threshold, the Step 1, Step 2 threshold, as well as
the basic charge and its interaction with the RIB
rate.
B.C. Hydro has proposed that these form
part of the scope for the F2016 rate design
application. We’ve envisioned that application
encompassing all customer classes, so residential,
commercial as well as the industrial customer classes.
We’re also envisioning and planning for lengthy
consultation given the breadth of issues and the wide
variety of stakeholders who will be impacted by the
rate design application. We expect to have our first
consultation session likely in the next couple of
months where we would solicit input from our
stakeholders on potential scope issues, and we also
envision having a consultation session on cost of
service methodology and cost determination in the near
future.
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So with that, included in the scope of the
RDA we would expect to discuss the cost of service as
well as potential rate rebalancing within the -- to
the customer classes, as well as rate design including
all conservation rates, as well as tackling the
recommendations from the industrial electricity policy
review which was released on November 26th of 2013.
As far as the timing of our application, we
expect to have further consultation throughout 2014
and likely into the early part of 2015, and would
begin our application drafting at the end of 2014 or
early 2015 with the goal of filing our rate design
application by the middle of 2015.
So in conclusion, B.C. Hydro proposes a
pricing principle that will bridge the two-year gap
between now and the comprehensive rate design
application which is being developed, will be
consulted on and ultimately reviewed by the BCUC.
What we know now is that the Step 2 rate exceeds the
upper end of the long-run marginal cost of energy, and
we also know that the current -- that the RRA
increases for that '15-'16 period will be 9 and 6
percent, and as such we need to take into account bill
impacts when evaluating the options. We believe that
Option 2 maintains the objective of the conservation
while limiting bill impacts for all customers to the
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revenue requirement increase levels. We don’t believe
there’s any compelling reason to either increase the
Step 2 rate faster than Step 1, given that we’ve
already exceeded the long-run marginal costs of
energy. Nor do we believe that there is a strong
reason to impose relatively greater bill impacts to
lower consuming customers, including the low income
customers, as would be the result of adopting Option
3.
As such, B.C. Hydro is recommending Option
2 which would see the RA increases applied to each of
the three main elements.
That concludes our presentation today, and
we welcome any questions and comments.
THE CHAIRPERSON: Well, I thank you very much for that
presentation, and we can now proceed to questions from
participants. Is there any particular group that
would like to begin the rounds at the moment? I’m
always happy to receive a volunteer. Please proceed.
MR. CRAIG: Thank you very much. It’s David Craig,
Commercial Energy Consumers.
I’ll start with questions and allow B.C.
Hydro to reserve (inaudible). I want to start with
the residential rate including the Step 1 and Step 2,
are effectively all energy charges to the customer?
There isn’t a demand charge, for instance, as part of
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the rate structure. I just want to confirm that as a
starting point.
MR. DOYLE: We confirm there’s -- yeah.
MR. CRAIG: And the charges to the customer, and in this
case the residential customers, at the end of the day
have to cover not just energy costs but also capacity
costs.
MR. DOYLE: That’s true.
MR. CRAIG: And those are rolled in, effectively, into
the energy charge that’s charged to the residential
customer?
MR. DOYLE: Into the energy charge and the basic charge.
MR. CRAIG: Right. And the next question is that the
LRMC that’s being used as a reference point for the
pricing is just the incremental energy cost. I just
want to confirm that it only includes the energy,
doesn’t include the capacity.
MR. DOYLE: That’s correct, yes.
Proceeding Time 9:39 a.m. T10
MR. CRAIG: And so that’s leading me to a conclusion
which I’ll do when we get to summarizing, that from a
principle point of view, when we deal with the
residential rate, we should include, when we’re
looking at marginal costs, marginal costs for energy
and capacity. And because you’re rolling it into an
energy charge, you’d want to do that on a megawatt-
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hour basis, as opposed to the separate pieces.
MR. DOYLE: Right.
THE CHAIRPERSON: We’ll take a technology break then, Mr.
Craig, if you would for just a moment.
MR. CRAIG: Not a problem.
THE CHAIRPERSON: There we go. Please proceed.
MR. DOYLE: So, I guess, in response to Mr. Craig, I
think what Mr. Craig is getting to is that it’s a
significant rate design issue. The RIB rate is --
provides an energy signal, and it’s -- that’s the way
it was developed as well as approved. I think when
you start getting into -- I think where Mr. Craig is
leading to is sort of capacity benefits of the rate
structure. You start getting to a time of use type
rate structure, rather than what is intended through
the residential inclining block. And I think that
that’s an issue that’s better explored in the -- in a
rate design application rather than as part of what
B.C. Hydro has proposed in this application, which
simply looks at the pricing principles and the manner
in which rate increases are applied to each element of
the rate structure.
THE CHAIRPERSON: Sorry, just wait for another technology
break here. There we go.
These are informal hearings, but they carry
it too far.
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MR. CRAIG: It’s working fine for me.
I am explicitly not trying to get into time
of use rates, and I would agree with B.C. Hydro that
time of use rates is a rate design issue, and is
adequately deferred to B.C. Hydro’s proposed RDA
process.
What I am referring to is that the RIB rate
itself is an energy charge to the customer, but it
must cover costs that include capacity and energy.
And our comparison that’s being used to set it is
LRMC, which is just an energy charge. And it would be
appropriate to have the comparison include comparison
to energy and capacity. The capacity converted to an
energy amount is not a very large amount. It’s in the
range of $5 a megawatt hour to $10 a megawatt hour, if
you have a high capacity factor generation. It’s a
bit higher if you’ve got wind generation.
So I’d like to confirm that aspect of the
discussion, as to what it would amount to as
materiality, and then come back to whether or not it’s
appropriate to have it in the comparative.
MR. DOYLE: So, I think Randy can answer that question,
but I think what is important is that previous LRMCs
used for reference for their Step 2 pricing have
always just included the energy component of the long-
run marginal cost, and not a capacity benefit. So it
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would be a deviation from what’s been done.
MR. CRAIG: It would. And that’s now getting to the
other point. So let’s address them as you’ve raised
them.
This would represent a change, and my
reason for bringing it up is that I think in principle
it’s an appropriate change to be in the comparative.
And I want to raise it on the record now, and to the
extent that it’s relevant here, the amount that it
adds doesn’t move the combined LRMC and capacity above
where your current pricing proposed is going to be.
You’ve already said LRMC is below the pricing. This
would simply raise it a bit closer. And I think it’s
in principle the proper way to go. And whether or not
this process recognizes that, I think it’s an
appropriate principle to be raised now, and I’ll be
raising it again in the RDA as the appropriate way to
go about dealing with the residential rate.
So, maybe I can go back now an just to
confirm that the amount that we are talking about
might be in the $5 to $10 a megawatt hour.
Proceeding Time 9:44 a.m. T11
MR. REIMANN: So Mr. Craig alerted me that he might be
asking this question, so I had a quick calculation
done at the office that I haven’t had a chance to look
at, and it may be more in the order of $15 a megawatt
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hour for a 60 percent load factor load profile.
MR. CRAIG: Okay, so that’s helpful. That’s consistent
with my understanding of the approximate level of the
cost. And that capacity, as a reference, would be
based on the next marginal increment of capacity,
which would be Revelstoke 6?
MR. REIMANN: Right. The next marginal resource, the
next low-cost resource that we have available to us
that is not yet committed is Revelstoke 6.
MR. CRAIG: And that would have an estimated --
MR. REIMANN: Yeah, and Mr. Godsoe is just reminding me
that we actually have two resources available to us.
There’s the capacity upgrades at GMS. My recollection
is that those were more in the $30 per kilowatt year
range versus 50 for Rev 6. So we actually have a
couple of the clean resources, so depending on what
the need was.
MR. CRAIG: Fair enough. So those ones at $30 a kilowatt
year, and the Revelstoke 6 is estimated to be in the
range of about $50 a kilowatt year.
MR. REIMANN: I think that’s right.
MR. CRAIG: And so those would take us into the range of
--
MR. REIMANN: Say ten to fifteen.
MR. CRAIG: Ten to fifteen dollars. So it’s not a huge
change but it does close the gap to where you are
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pricing and where you are proposing to price, and so I
raise it for that purpose, that it’s (a), in principle
the appropriate reference; and (b) it brings us closer
to leaving the pricing where you’re proposing it as
appropriate to an appropriate LRMC.
Any further comments?
MR. GODSOE: I think we’ll respond to that in our final
submissions.
MR. REIMANN: We’ll leave it as part of our --
MR. CRAIG: Okay. When we come to the LRMC, you
reference that that’s a levelized cost.
MR. REIMANN: A real levelized cost, yes.
MR. CRAIG: And a real levelized cost takes the
anticipated cost of the marginal resource and divides
it by the levelized energy over the anticipated time
frame and you get a levelized cost?
MR. REIMANN: Yes, generally. So we started with a price
signal of $100 a megawatt hour as a real levelized
price cap, and then -- yeah, the cost effective
resources or those on a real levelized basis would be
below that.
MR. CRAIG: Right. And in terms of ratepayer interest,
that levelized cost is different than the financial
cost that will appear at the time that a given
resource is added to the B.C. Hydro system and
ratepayers start paying for it?
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MR. REIMANN: I think that might be --
MR. GODSOE: We’re getting into revenue requirement rate
collection issues that I would submit that are a
little bit outside the scope of this proceeding.
That’s what your driving at, whether in fact the LRMC
translates into revenue requirement, and I do think
that’s outside the scope.
MR. CRAIG: I’m looking to deal with what kind of
comparative we should have, and the whole purpose of
the price signal is to deal with ensuring that
ratepayers are receiving an appropriate price signal,
and my contention is going to be that to some extent
what the financial cost picture looks like is relevant
to what a long-run cost is going to be from a customer
perspective.
Proceeding Time 9:49 a.m. T12
And I think that’s clearly in scope as part
of a reference point. From my perspective when I come
to argument, I don’t think that’s going to propose
much in the way of change to what you’re doing. I’m
simply closing from your proposed LRMC references to
other principles that I think are relevant for
comparative purposes as to why the rates should be at
least up where you’re proposing.
Then at this point I think a scope question
has been raised and it’s over to the Commission.
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THE CHAIRPERSON: My inclination is to let you explore a
little bit depending on where you wish to go, but I
think we need to be very cognizant of transgressing
that boundary as you’ve issued. So let’s play this
out a little bit longer and I’ll decide whether we
need to defer it until a later date.
MR. CRAIG: I'll keep the point I’m pursuing very simple.
I’m just pursuing that the typical financial costs
that ratepayers see when a resource comes in, is
usually higher at the beginning and lower later on.
The levelized cost falls somewhere in between.
MR. GODSOE: That assumes there is no rate smoothing, so
that’s correct, but of course with a lumpy resource
there could be rate smoothing.
MR. REIMANN: So I think for the resources that we’re
looking at on the margin, at this point are DSM and
IPP renewals, and IPP contracts tend to be at a level,
real levelizing price as well, maybe half of the CPI.
So those tend to be a constant price over the period.
The other marginal resource being demand-side
management as opposed to a hydro capital project where
all the capital would hit in the first year and you’d
appreciate it. The DSM programs are paid for year by
year, brought into rate base as you go.
So I don’t think you get quite that same
degree of a fund hit as you would with a capital
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project.
THE CHAIRPERSON: Is that helpful, Mr. Craig?
MR. CRAIG: Yes. To the extent that you’re referencing
DSM and renewal of contracts which you’ve referenced
as being related to the ten-year period?
MR. REIMANN: Right, and the marginal resource. We don’t
really have any capital projects.
MR. CRAIG: Those marginal resources, but you’re
reflecting those as more important in the ten-year
period, and you’ve included data and there’s been
questions asked about Site C which would cover the
longer run 20-year period.
MR. REIMANN: Right, and we never did consider that Site
C would be a marginal resource because it wasn’t a
resource that lended itself to being moved around a
lot. It was an opportunity to build it at a certain
point and it was in about -- our view is that the
marginal resource would be DSM and IPP renewals.
MR. CRAIG: And that’s fair enough. That’s an accurate
representation of what you’ve put forward, and the
interest I’m pursuing is that if I look at the long-
term 20-year period and I look at the conservation and
efficiency which will generally be looked at over a
15-year period or longer, it’s not necessarily
inappropriate to consider Site C. You’ve referenced
that it’s in a window.
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MR. GODSOE: Commissioner Revel, this is my concern.
We’re getting into how Site C would be brought into
rate base. I think we’ve been clear that the first
ten years for a two-year bridging application is the
appropriate LRMC. How Site C is brought into rate
base I would submit is irrelevant to this proceeding.
MR. CRAIG: So my submission is --
THE CHAIRPERSON: I think we’ll follow Mr. Godsoe’s
position a little bit and not pursue that too
vigorously, unless you can build a case as to why we
should pursue it more strongly.
Proceeding Time 9:54 a.m. T13
MR. CRAIG: The purpose in setting a conservation rate
and referring to a long-run marginal cost is to refer
to the cost that will be applicable in the long run.
You’ve heard evidence that Hydro has focused on the
ten-year period and is using references for that
purpose. And my argument is going to be that it’s
appropriate to look to at least 15 or 20 years, and
that brings other resources that Hydro is dealing with
into account.
I’m not looking to pursue that argument to
change any of the pricing, but simply to follow on the
other arguments that I’ve used that the appropriate
range for LMRC [sic] may be higher and the appropriate
principles may be to look at other things.
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These arguments will re-appear in the RDA,
because I’m simply raising them as a matter of
principle. And what Hydro is asking for at this point
is a two-year proposal. And I’m not going to be
opposing their proposed rates.
But I think it’s relevant from a customer
perspective to raise the issue that the appropriate
LRMC references are not ten-year references, but can
be longer.
THE CHAIRPERSON: Mr. Craig, I’d just like to confer with
my counsel for a moment.
MR. MILLER: So, this is Paul Miller. It’s staff’s
understanding that the LRMC was set in the IRP that
was approved. And when we start getting beyond the
ten-year period which this application addresses,
we’re starting to wonder whether or not the concerns
that you’re trying to pursue are really relevant to
this application, or some other proceeding where the
issues can be more fully explored. And given this is
an issue of principle, and the -- I don’t think the
evidentiary record has been fully explored in this
proceeding, we’re wondering how useful this debate is
at this time.
MR. CRAIG: I don’t plan to take it any further than I’ve
taken it, and what’s been raised. And I agree to some
extent the principles are going to be much more
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relevant to the future RDA process, and are not
something that are going to materially affect the
pricing that comes out of this two-year bridging.
MR. MILLER: Yes, but staff’s concern again is the scope
of the SRP. We’re exploring policy issues, which are
arguably beyond what this panel is looking at, and
notice hasn’t been given to other affected parties or
potentially affected parties. So we’re trying to keep
this, at least to our understanding, within the scope
of what’s actually before us.
THE CHAIRPERSON: Well, thank you very much, then. So
would you proceed, Mr. Craig, then?
MR. CRAIG: That’s everything I have for the moment,
thanks.
THE CHAIRPERSON: Thank you very much. Would I -- do I
have a second volunteer?
MS. PRITCHARD: I can go.
THE CHAIRPERSON: Yes, please.
MS. PRITCHARD: This is Erin for BCPSO. There is just a
question about the plant growth of the upcoming RDA.
Currently there are different LRMC values used for the
rate designs for transmission service rates, LDS, NGS
rates, and residential rates.
I’m just wondering, since you’ve noted in
your presentation that the RDA will cover all three
customer classes, if the intent is also to align the
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LRMCs as well.
MR. DOYLE: I’m not sure whether the plan is to align
them, but I think it would be an issue that would need
to be explored through the RDA. Obviously the LRMC
and how it relates to the different rates would be
relevant, and in scope of the rate design application.
MR. GODSOE: And we do have to remember the transition
service rate is a bit of a different animal. It’s not
just the result of Commission proceeding, but Heritage
Special Direction No. 2. So it is slightly different,
but certainly I think the principle of LRMC informing
all three conservation rate structures would be within
scope of the fiscal 2016 RDA.
THE CHAIRPERSON: Sorry. Did you say it would be within
scope?
MR. GODSOE: It would be within scope.
THE CHAIRPERSON: Thank you.
MS. PRITCHARD: And the presentation and also B.C.
Hydro’s response to CEC 1.6.6 suggests that the
stakeholder engagement for the RDA will be beyond the
normal approach. I’m just wondering if this
understanding is correct.
MR. GODSOE: Sorry, can you repeat the reference?
MS. PRITCHARD: Yeah, sorry. CEC 1.6.6.
MR. GODSOE: Sorry, Erin. Do you mind repeating the
question?
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MS. PRITCHARD: Yeah, sure. Just the presentation and
both that reference, CEC 1.6.6, suggests the
stakeholder consultation for the RDA will be beyond
what would normally be expected. And just wanted to
confirm that that’s correct.
MR. DOYLE: I’m not sure what sort of -- would normally
be expected. But I think, as I said, we are planning
on numerous stakeholder engagement sessions, with all
the customer groups and stakeholders and staff. And
beginning probably much earlier, maybe, than we have
in the past. So --
MR. GODSOE: And I guess to state the obvious, it would
be much more fulsome than the two workshops we had for
the 2013 RIB application.
MS. PRITCHARD: Do you have any idea of your timeline for
that, or how long it would be, that would be expected
to --
MR. DOYLE: Sorry. Well, I think our -- we’re expecting
our first consultation session to probably be in the
next couple of months. And that would talk to --
sorry, soliciting input on the proposed scope of the
application. And then shortly
MR. DOYLE: Shortly thereafter we envisioned a workshop
that would talk about the cost of service methodology
as it sort of forms the foundation of the rate design.
And that would be shortly thereafter.
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And then there would be consultation. I
envision consultation sessions throughout the process,
and they may be customer group specific or specific
interest. I’m just not sure at this time.
Proceeding Time 10:00 a.m. T14
MS. PRITCHARD: All right, and on the LRMC again, B.C.
Hydro’s confirmed that the LRMC of the range of 85 to
100 dollars per megawatt hour is expressed in fiscal
2013 dollars. And CEC 1.41.2 indicates that if that
was expressed in 2016 dollars the range would be 90 to
106 dollars per megawatt hour. Sorry, again that’s
the CEC 1.41.2.
MR. GODSOE: It’s confirmed.
MS. PRITCHARD: Okay, so since we’re setting rates for
2015 and ultimately 2016, we’re wondering if there was
any consideration of expressing the range in the years
dollars that the rate will be set for?
MR. DOYLE: No, I think we didn’t consider adjusting the
LRMC for those years, we used the LRMC that was --
that came out of the IRP.
And the calculation, even adjusted, the
calculation for the rate in both ’15 and ’16 would
exceed the rate even if we used the 106 per megawatt
hour as provided in CEC response 1.41.2.
MS. PRITCHARD: Thank you. Just a question about the
implications of using a range for the LRMC for the PPA
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with FortisBC as set out in the preamble to BCPSO
1.10.1. The new PPA utilizes the proxy for LRMC
accepted by BCUC as the value for the step two energy
price in the contract.
We’d just like to ask if the contract is
based on the LRMC, and there’s no LRMC specified,
meaning just a range is used, then what LRMC would be
used for that contract? Would it be in the upper
range, the lower or a midpoint?
MR. DOYLE: So I think as I’ve described in what I
believe was slide 7 of the presentation, what we
evaluated the options against was the hundred dollars,
so the upper end of the range. I think, as is
typical, during the decisions the Commission will
often make a finding of fact around the long-run
marginal cost, and I think that would guide what we
would use with respect to the long-run marginal cost
for this, this tier 2 pricing in the PPA.
MS. PRITCHARD: Okay, and just one final question on rate
structure TRC. It might be helpful to turn to CEC
1.9.1. And that reference reports the total resource
caused for various DSM activities and the value for
rate structure is very low compared to other
activities. I believe it’s at $7 per megawatt hour.
Can you confirm that TRC values are
supposed to capture costs to both B.C. Hydro and to
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customers participating in the DSM.
MR. REIMANN: Yes.
MS. PRITCHARD: And in the case of rate structures, the
reported TRC, the $7 per megawatt hour only includes
B.C. Hydro’s cost of implementing and maintaining the
rate structure?
MR. REIMANN: Right. I think the rationale for the low
cost of that component relates to the savings that are
actually believed to be targetted or achieved with the
rate structure, and those are likely assumed to be
behavioural or low-cost capital as the initial step,
and it’s programs and codes and standards that take
beyond that. So the cost does jump up.
MS. PRITCHARD: Right. But it doesn’t include the cost
of customers purchasing insulation or more efficient
appliances or anything like that.
MR. REIMANN: Right. It would include customer costs, or
it does include customer costs, but it’s assumed that
the savings are related to more behaviour, as opposed
to more capital investments. And those would be
driven the by the programs then, and the codes and
standards.
Proceeding Time 10:06 a.m. T15
MS. PRITCHARD: Okay, I think those are all my questions.
And we’d just also like to acknowledge B.C. Hydro for
incorporating a lot of the outstanding questions we
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had into their presentation following our January 20th
session, so thank you.
MR. GODSOE: Thank you.
THE CHAIRPERSON: Thank you very much, Ms. Pritchard. Do
I have another volunteer?
MR. ANDREWS: Yes, I’ll go next. My questions will focus
on --
THE CHAIRPERSON: Sorry, would you please state your name
and organization again.
MR. ANDREWS: Bill Andrews.
THE CHAIRPERSON: Thank you.
MR. ANDREWS: And I’m counsel for the B.C. Sustainable
Energy Association and the Sierra Club. I thank you
for the presentation and my clients will address the
Option 2 aspect of this in the final argument. Right
now my questions will focus on the control group
proposal.
BCSEA and Sierra Club strongly supported
the creation of this particular control group
acknowledgedly for a completely different purpose when
it was proposed. I guess my -- first of all maybe you
can confirm that the purpose of a control group in the
RIB situation is to help distinguish quantitatively
between the effect of natural conservative that is due
to the class average rate increase, and the effect of
the stepped rate component, the differential between
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Tier 1 and Tier 2.
MS. JUBB: Yes, I can confirm that.
MR. ANDREWS: And what would be the lead time for setting
up a new control group if Hydro did decide to do that
for the purpose of examining the effect of the RIB
rate?
MS. JUBB: We’d expect to need at least two to three
years for the impact of previous exposure to the RIB
rate to be washed out. Because these new control
accounts would be transitioning from being under the
RIB to a flat rate, that is why a period of time would
be needed before they could be used to evaluate the
structural impact of the RIB.
MR. ANDREWS: So it would be too late, in a sense, to use
the results of a control group that was started today
to inform the F16 RDA application?
MS. JUBB: So another alternative that we’re exploring is
the use of the New Westminster consumption data, as
those customers are under a flat rate. If that
approach is successful, then we may be able to use it
in time for the RDA.
MR. ANDREWS: And what -- just let me put it in an open-
ended way. What’s stopping B.C. Hydro from deciding
now to initiate a new control group that would produce
useful results whenever they become available, even if
it is beyond the 2016 RDA?
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MS. JUBB: A new control group would come with potential
costs as well as impacts to customers.
MR. ANDREWS: Let me ask then, what would be the pros and
cons to B.C. Hydro if the Commission were to approve
Hydro’s request to terminate the existing control
group and add a direction or suggestion that Hydro
proceed to establish a new one? What would be the
pros and cons of that caveat being in a decision
regarding this application?
MS. JUBB: That would depend on the design of the control
group that was put forward.
MR. ANDREWS: If the Commission were to say that they
look forward to Hydro addressing the possibility of
establishing a control group, would that be a problem
for B.C. Hydro?
Proceeding Time 10:11 a.m. T16
MR. GODSOE: So I think a comment in the reasons for
decision wouldn’t be a problem. I think there’s not
enough evidence to inform a direction. I think as
Anthea has described, we don’t know what the control
group would be, we’re not sure of the timeline, we’re
not sure of the costs or impacts to customers. So I
think we would be concerned with a direction.
MR. ANDREWS: Thank you. Those are my questions.
THE CHAIRPERSON: Thank you very much. I believe that
doesn’t leave us too many more choices. I believe
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FortisBC, Mr. Perttula and Mr. Brownell.
MR. BROWNELL: Brown el.
THE CHAIRPERSON: Brown el, thank you.
MR. PERTTULA: Yes, we don’t have any questions at this
time.
THE CHAIRPERSON: Mr. Craig, I believe you said that
those are all your questions for the time. Do you
have further questions? I noted that.
MR. CRAIG: I’d ask leave just to explore one further
question.
THE CHAIRPERSON: Please do.
MR. CRAIG: Around the LRMC. I just wanted to obtain
Hydro’s view that the Commission in its rate-setting
capacity is free to determine the -- both the rate and
the references it looks at for the LRMC, and that the
IRP in its use of LRMC is not determinative in
directing the Commission as to what LRMC is.
MR. GODSOE: I would agree that the integrated resource
plan is not determinative. The test of “consider and
be guided by” applies to CPCN applications under
Section 46, EPA fines under Section 71, and
expenditure determination under Section 44.2.
However, I think it is of significant evidence that
the Commission should consider, given in fact that the
province has, through order in council, approved the
integrated resource plan and it does -- it is our
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evidence concerning the LRMC.
So I agree it’s an evidentiary issue. I
would submit it should be afforded significant weight.
THE CHAIRPERSON: Thank you. Mr. Craig?
MR. CRAIG: That’s everything.
THE CHAIRPERSON: Ms. Pritchard, I see your hand up.
MS. PRITCHARD: Yes. Just one further question based on
the discussion about the control group. I just wanted
to clarify what would be the impact to customers just
in broad terms of setting up the control group, and
the costs.
MS. JUBB: An involuntary control group would involve
transitioning some low consuming customers into a flat
rate which could have bill impacts.
THE CHAIRPERSON: Did you wish to pursue that more, Ms.
Pritchard?
MS. PRITCHARD: I don’t think so, thank you.
THE CHAIRPERSON: Let me follow on with that for a
question. When you said “involuntary” that probably
has some ethics approval implication from a research
standpoint, but presumably it wouldn’t be involuntary
if you got cooperation from New Westminster, would
that be correct?
MS. JUBB: New Westminster is not representative of the
general population of B.C. Hydro customers.
THE CHAIRPERSON: It is not?
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MS. JUBB: It is not representative of the general
population of B.C. Hydro customers. Therefore, if New
Westminster consumption data was use, it would be used
as an input to the econometric values described in the
RIB evaluation report to derive an estimate of
elasticity under the flat rate, controlling for the
explanatory variables that are in that model, such as
region and weather, income, for example.
So under that alternative approach, there
would be no customers impacts to New Westminster
customers. It would simply be -- require access to
their consumption data, which may present a barrier.
THE CHAIRPERSON: And that would need to be negotiated
with New Westminster, I presume.
MS. JUBB: Yes.
THE CHAIRPERSON: Are there any further questions? Mr.
Andrews, have you --
MR. ANDREWS: Nothing further.
THE CHAIRPERSON: We do have time. Do you two have any
further questions?
Okay, we’ll return to staff and ask staff
to pursue those lines that they wish to pursue, and I
think we can plan at taking a break at 10:30.
MS. CHENG: I am Eileen Cheng from the Commission staff,
and with me are Jim Fraser and Jackie Ashley, and our
questions will fall into three major groupings. I
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will ask questions by way of clarifications of the
application and the responses to IR, and then I will
pass onto Jim who will speak to the specific reliefs
that B.C. Hydro is requesting in this application.
Proceeding Time 10:16 a.m. T17
And Jim will pass on to Jackie, who will speak to
option 2 versus option -- the other options.
My first question is by way of
clarification in Appendix A, in Exhibit B-1, the
application. In paragraph 2 of the draft order, it
says that B.C. Hydro shall file a RIB application in
fiscal 2016. And I’m wondering that if it -- if B.C.
Hydro means an FDA, as opposed to a RIB? Because I
don’t see the intention of filing a RIB elsewhere in
the application.
MR. GODSOE: Agreed.
MS. CHENG: Okay. And my next question is the response
to BCUC IR 1.25.4. B.C. Hydro responded that it is
currently not collecting the customer level economic
data. The question is, if it is not, what kind of
data -- new data is B.C. Hydro collecting, in addition
to what it is already collecting. Has B.C. Hydro made
plans?
MS. JUBB: The value of collecting customer level
economic data would be to explore research questions
such as elasticity by income, or elasticity by the
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year that a home was built. However, those data
collection efforts are costly, and resource intensive.
So we’re not pursuing them at this time.
MS. CHENG: Right. Will you be planning on filing, like,
an updated RIB evaluation report in the next RDA
application?
MR. DOYLE: That’s not currently in our plan. It’s not
currently in the plan to file an updated RIB
evaluation report in the 2016 RDA.
MS. CHENG: Sorry?
MR. DOYLE: It’s not -- it wasn’t our plan to file an
updated RIB evaluation in 2016.
MR. GODSOE: I think there may be timing issues, but we
could take it under advisement.
MS. CHENG: Okay. What is the ongoing research in
relation to RIB evaluation? It’s just more years of
data that you will be --
MS. JUBB: Subsequent evaluations would be informed by
additional years of billing data, as well as
additional customer surveys. We do have periodic
surveys to the residential customer class that occur
every second year. As well as specific ones for -- to
inform evaluations. So those would be the primary
data sources unless we’re also able to leverage New
Westminster data.
MS. CHENG: So you’re referring to the residential end
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use study?
MS. JUBB: That’s correct. That’s correct. And we also
do surveys specifically for evaluations, and in the
RIB evaluation, included in Appendix C, we drew from
the residential end use survey as well as a specific
survey for RIB.
MS. CHENG: Mm-hmm. And in the Appendix C, the
recommendations on page 42 of 110.
MS. JUBB: Yes.
MS. CHENG: You mentioned the various action plan, if I
can describe them. The recommendations that you
continue to attempt to estimates that one -- the
future RIB rate evaluation, may benefit from
complementary economic -- econometric analysis. Do
you need more data for -- in order to achieve these
actions?
MS. JUBB: It’s not clear that more data would assist
with the estimation of a Step 1 price elasticity. The
primary barrier to that estimation is that there has
been little variation in Step 1 price over time. So
because elasticity is an estimate of a response to
change, we do need to see some change to have a
successful model. So, for the Step 1 elasticity, it
might simply just be a matter of more time before we
can produce an estimate.
MS. CHENG: So while on this topic of research, I think I
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would pass on to Jim, who has questions for you.
Proceeding Time 10:22 a.m. T18
MR. FRASER: It’s Jim Fraser. Eileen indicated I would
speak to the evidence which Hydro is asking for
relief.
On two of the issues, one on the Step 1
Step 2 energy threshold issue, I have no questions on
that issue nor on the basic charge. On the RIB
evaluation report, Hydro had asked sort of partial
relief on that, partial relief on that, and I have no
questions that bear directly on whether the Commission
grants it or not. But to follow up on one of Eileen’s
questions, I think you said that there was no plans to
update it. So there is no plan to add 2013 data to
that prior to its evaluation on either the RDA or the
filing of the 2014-2016 DSM expenditure schedule then.
Is that right?
MS. JUBB: Can I just confer?
MR. DOYLE: So the current plan for the next RIB
evaluation report would be for F17, so that would be
after the -- would be likely too late for the F16 RDA.
So I think, as Craig alluded to earlier, there is a
bit of a timing issue there.
MR. FRASER: Okay. And I guess the other question is I
think that in one of its -- either in the application
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or one of the responses, and I forget which, B.C.
Hydro said that, you know, it thought the appropriate
time to evaluate the RIB evaluation report more fully
or to review it more fully was in the context of a
2014-2016 DSM expenditure schedule when that was
filed. And can you confirm that you will be filing a
2014-2016 DSM expenditure schedule with the
Commission?
MR. GODSOE: I cannot confirm that. We do not know the
breadth of the direction that will be issued to the
Commission with respect to the setting of rates for
fiscal 2015 and fiscal 2016 pursuant to a revenue
requirement application. So if there is in fact no
Section 44.2 filing in the broad sense that there
might be a mechanical filing that flows out of that
direction, then I would submit the interreaction
between the RIB rate structure and MGS and LGS, TSR
and perhaps more broadly DSM could be an issue for the
fiscal 2016 RDA.
I think our real point was, what the
Commission was getting at was how does the RIB nest
within the broader DSM suite and elasticities? And I
think that could be explored in the fiscal 2016 RDA.
MR. FRASER: So if there was no DSM expenditure schedule
filed, then it would be filed or could be filed in the
RDA application.
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And then I had a few questions, I think
they’ve probably been mostly beaten to death, about
the control group, and so I may take a minute or two
going through these to see which ones I can eliminate
and which are still left.
One of them, and it’s a fairly minor point,
was that in response to BCUC IR 1.12.1, and I don’t
think you need to go to it, you can if you want, but
you just committed to providing the Commission with
any letters of comment from RIB control group members
that are received before the end of the evidentiary
portion. We’re kind of at that and I haven’t seen
anything filed.
Is it fair to conclude from that that you
haven’t received any letters of comment from --
MR. DOYLE: Yeah, in fact I checked with our customer
care group and we haven’t received any letters in
regards to the -- from any participants of the control
group with respect to dissolving it.
MR. FRASER: Okay. Following up on a question on the
control group by Bill Andrews earlier, I thought I
heard a response that a control group, if it was
established now, actually might be able to -- could
provide some useful information in time for the filing
of the RDA. And I'm not sure, I may have misheard
because that seems awfully quick. Did I hear that
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right?
MS. JUBB: The use of the New Westminster data, if it is
successful -- and there are a number of barriers to
that approach -- but if that approach is successful it
could potentially provide some information in time for
the RDA, because it is primarily just a modelling
exercise. However, the creation of a new control
group, drawn from B.C. Hydro customers, that would not
provide information in time for the RDA.
Proceeding Time 10:27 a.m. T19
MR. FRASER: And just following on the panel chair’s
question earlier when he talked about voluntary or
involuntary control groups, if one was going to create
a new control group, then would -- I don’t know if you
have an answer to this yet, but I am wondering whether
or not you would be thinking of sending out
invitations to residential customers asking them if
they wanted to join a control group or whether or not
you would be involuntarily placing a random sample on
a control group. Or have you thought about that at
this point?
MS. JUBB: There are various approaches that could be
used, and we would need to carefully consider any
customer impacts, as well as the merits of the
different approaches before we would put forward a
proposal.
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MR. FRASER: Okay, thank you.
MS. CHENG: Can I have a follow-up question on Jim’s? Is
that all?
MR. FRASER: Yes, go ahead.
MS. CHENG: I understand that the medium general service
and the large general service currently have control
groups to assist B.C. Hydro in evaluating the
conservation savings. Are you familiar with them?
MS. JUBB: Yes.
MS. CHENG: Do you think that can be replicated for the
residential inclining block rate customers?
MS. JUBB: Potentially.
MS. CHENG: Is it a fair description to say they are
working well for the MGS and LGS evaluation?
MS. JUBB: They are working well for MGS on the basis of
various statistical tests, and they are working, I
would describe fair, for LGS on the basis of those
same tests.
MS. CHENG: And so potentially – back to your original
answer – it may also work well for the RIB rate.
MS. JUBB: The LGS/MGS control group were established
prior to the introduction of those rates, so that does
provide an advantage versus attempting to establish a
control group now for RIB which has already been in
place for a number of years.
MS. CHENG: Because of the rate impact and --
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MS. JUBB: That’s right. Because customers who would be
going into a new RIB control group have already been
exposed to RIB.
MS. CHENG: Mm-hmm, thanks.
MR. FRASER: Actually, Eileen just asked the question I
had as well. So that’s good. That’s eliminated one
of my questions.
And I guess the final one on this area is
whether or not you can comment on whether you think
B.C. Hydro can do as good a job evaluating the RIB
rate without a control group as with one. In other
words, once you come to a full RDA in a couple of
years, will the filing be as robust with respect to
the residential rate as it would be -- without a
control group as it would be with one?
MS. JUBB: The current control group does not provide
useful information for the purpose of evaluating the
RIB.
MR. GODSOE: So I guess your question is academic. I
mean, our relief is with respect to the current
control group, which I think the evidence establishes
is not useful. Academically, of course, a control
group would be good to have in place, but I think
we’ve got timing issues.
MR. FRASER: That’s what I’m trying to get at. I
understand the relief is with the existing control
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group, what I’m -- and in its responses to IRs Hydro
has kind of suggested it’s not adverse to creating a
new control group, but at the same time hasn’t said,
“We will do one.”
And sort of following up on your earlier
comment, Craig, that a suggestion from the Commission
might be apropos, or appropriate, but a direction
might not be.
And so what I’m trying to get at is,
whether or not the Commission and/or B.C. Hydro will
end up two years down the road, or a year and a bit
down the road, saying it would have been better with a
control group, but we -- you know, we didn’t have one.
And --
Proceeding Time 10:32 a.m. T20
MR. GODSOE: I guess, Jim, I’d answer it this way. There
is a lot of competing pressures in terms of timing for
the fiscal 2016 rate design application, as you can
appreciate, I’m sure. So, I would submit a control
group for the RIB is a subset. We’ve got -- AMC’s not
here today, but we clearly have pressure to act on
some of the industrial electricity policy review task
force recommendations sooner rather than later. We’re
going to need to have rates for fiscal 2017.
So I think we’re juggling a lot of balls in
that broad application. I don’t think we’re going to
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show up at the door and say we can’t discuss the RIB
because we don’t have a control group. But I did want
to get the message across that there is a lot of
competing interests, a lot of timing pressures on the
RDA, and if we can’t have a control group in place, I
think we still need to file by about mid-2015.
MR. FRASER: Okay. Thanks. I’ll leave that -- the issue
of the control group there, then. And then I have a
couple of questions about the long-run marginal --
THE CHAIRPERSON: Perhaps we could, thanks to all of
Hal’s good coffee, we could take a five-minute break
and resume very promptly, and then questioning period
is over, we’ll take a longer break and can take care
of things in that. So we’ll reconvene in five
minutes.
(PROCEEDINGS ADJOURNED AT 10:34 A.M.)
(PROCEEDINGS RESUMED AT 10:42 A.M.) T21
THE CHAIRPERSON: Well, let us -- now we’re all
refreshed, let us reconvene and perhaps, Mr. Fraser,
you’d like to continue with your questioning.
MR. FRASER: Sure. I just have a couple of questions
that are related to the LRMC. And actually it’s
specifically back to a response to David Perttula
earlier. In the IRP discusses the estimate of the
LRMC kind of generally, and in chapter 9, and sets out
the range. But then it refers back to chapters 4 and
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6, and maybe I missed it, but when I looked back to
chapters 4 and 6 to sort of find how those precise
numbers fell out, I had difficulty doing that.
And then there was a response earlier, and
that is getting the sense that sort of -- the upper
limit of $100 is kind of a little bit of a soft
number, if I can call it that. That sort of it’s
equivalent roughly to the standing offer program to
the -- I think in one of the slides it said to the new
home -- the DSM new home program. That there is a
sense that the EPA renewals will come in somewhere at
that or below.
Is that sort of the -- is that the way it
was developed, is you kind of looked at the EPA
renewals and said, well, it’s somewhere between their
opportunity cost and the operating cost is where we
want to get the kind of negotiated renewals, and we
can probably do an amount that’s going to -- you know,
get enough -- get as much as we need at or below $100
a megawatt hour, and the standing offer program is
about $100. So that’s sort of how you came up with
that?
MR. REIMANN: So, the -- I guess the reference to
Chapters 4 and 6 -- yeah, probably aren’t exactly
linear in terms of step 1, step 2, and here’s the
LRMC. But they were intended to say that we have to
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go through a process in developing the IRP in Chapter
4 to understand sort of what were we going to do in
the near term for the next three years to minimize
costs. But then at the same time still understand
what the longer-term cost effect of supply was.
MR. FRASER: Right.
MR. REIMANN: And so that, given the needs, it really
meant looking at demand-side management, and saying
how much would -- we had a certain rate of expenditure
growth that we were anticipating. It was to moderate
that, and then to say how could we recover. And then
there was a process of looking at the IPP contracts,
of those that have been awarded and those that are
already built. And saying, so how do we address all
of those?
And so we went through that exercise and
that’s kind of where that $100 price signal came and
said what would be produced underneath that. And then
we looked at what DSM activities and what IPP
activities would be happening, and whether or not that
was an appropriate level in the short term.
Then Chapter 6 then takes it from there,
and then says, here’s the longer-term questions and
here is what the analysis looks like. And kind of
when you put that all together with the recommended
actions, and most of that is done with a portfolio,
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present value analysis. But when you take a look at
all of that, about what’s more cost-effective, in or
out, and where the marginal resources come from,
that’s when we then -- okay, so we’ve concluded that
it is DSM and IPP renewals that are on the margin
through most of that period. And the price signal was
$100.
So we felt pretty comfortable with that
$100. But then noted that we do have still a bit of a
surplus of energy before Site C would be anticipated
to come on. And so we made the observation that $100
is what we’ve set this at. It could potentially be a
little bit lower than that. And just to bring the
energy number down lower, but you then almost need to
go through another -- this is a bit of a long answer.
MR. FRASER: No, it’s good.
MR. REIMANN: We need to go through another IRP update
process to say, okay, there is uncertainties coming
down the pike. Are we -- and we’re not 100 percent
sure what we’re needing to target. And I imagine the
uncertainties earlier. So when is the right time to
propose or look at maybe some further reductions in
that price signal? And so our feeling was is, no,
it’s too early to go there. But internally as we look
at things, we kind of use that threshold of, if you’re
below 85 in a renewal or program, you’re good. If
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you’re 85 to 100, it’s got to be a pretty good project
or program, and if you’re above that, it’s pretty much
a no-go zone. And so that kind of concluded that
whole process, and here is the range.
Proceeding Time 10:47 a.m. T22
MR. FRASER: Right, okay. And then the final thing.
It’s just a bit of a formality, but it’s okay with
Hydro that we adopt the IRP by reference, then there’s
no objection to that as evidence in this proceeding?
MR. GODSOE: No objection.
MR. FRASER: Just wanted to refer to the IRP. Okay.
Those are all the questions I have. So I’ll turn it
over to you.
THE CHAIRPERSON: Thank you very much, Mr. Fraser. Ms.
Ashley?
MS. ASHLEY: Hi, Jackie Ashley. The RIB pricing
principles proposed by B.C. Hydro in this application
are for fiscal 2015 and 2016 only. And B.C. Hydro
expects to file a general rate design application in
fiscal 2016, which would include recommended pricing
principles for the RIB rate beyond fiscal 2016. Is
this correct?
MR. DOYLE: Yes.
MS. ASHLEY: For the purposes of this two-year
application, Hydro hasn’t undertaken a comprehensive
review to determine how each Bonbright principle
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should be defined. It hasn’t taken a full analysis of
each of the options against the eight Bonbright
principles. Does B.C. Hydro consider that such a
comprehensive review is best suited for the fiscal
2016 general rate design application?
MR. DOYLE: Sorry. I’m not sure -- so I think, first, I
think we agree that during the 2016 RDA a more fulsome
examination is appropriate. Although I’m not sure
that we’d agree that we didn’t undertake a substantive
evaluation of the Bonbright criteria with respect to
this application. I think we did -- we were guided by
previous Commission decisions which indicated that the
Bonbright principle of efficiency and bill impacts are
the primary criteria to consider in the RIB re-pricing
applications. However, we did speak to the various
other Bonbright criteria in our application.
MS. ASHLEY: Okay, but you didn’t test whether those
previous Commission decision regarding specifically
how the efficiency Bonbright criteria should be
determined. You didn’t test to see whether those
determinations were still appropriate?
MR. DOYLE: We didn’t test beyond looking at what the --
being guided by previous Commission decisions.
MS. ASHLEY: Okay. So Commission staff are asking B.C.
Hydro’s assurance that it’s not seeking regulatory
policy in the decision from this process with regard
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to the interpretation of Bonbright principles when
evaluating the RIB rate design for fiscal 2016 and
beyond.
MR. GODSOE: I think that’s fair. For fiscal 2015 and
fiscal 2016 we are seeking confirmation that, in fact,
the Commission’s prior decisions, recognizing they are
not bound by precedent, are appropriate and that
efficiency equals LRMC. We will agree that a debate
beyond that is appropriate for the fiscal 2016 RDA.
MS. ASHLEY: So Order G-45-11 laid out three pricing
principles B.C. Hydro was to follow for the fiscal
2012 to 2014 period. Back to the option 1. Can B.C.
Hydro please explain what changes have occurred since
these pricing principles were developed which now
raises uncertainty over whether these principles are
still appropriate?
MR. GODSOE: Sorry, could you repeat your question.
MS. ASHLEY: The Order G-45-11 laid out the three pricing
principles Hydro was to follow, and this is
effectively option 1. So that was already a
Commission decision that laid out that there should be
further changes to the rate structure design. And now
we’re saying we don’t want to make those further
changes to the rate design -- or sorry, Hydro’s
application states that. And what I would just like
is Hydro to summarize, I guess, the key changes that
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have happened from the date of the decision till now,
that had they been known previously could have
resulted in a recommendation of option 2 at that time.
As in no further changes to the rate design.
MR. DOYLE: So I guess just for clarity. So what you are
asking is what has changed from in previous decisions
B.C. Hydro was pursuing the long-run margin, pursuing
step two, increasing at a more rapid rate.
MS. ASHLEY: Yes.
MR. DOYLE: And now what we’ve said is we need to slow
that rate of growth --
MS. ASHLEY: Well, you say option 1 is the status quo.
MR. DOYLE: Okay.
MS. ASHLEY: So what has changed to now to make the
status quo not look optimal?
MR. DOYLE: I think the primary thing that’s change is
that B.C. Hydro’s long-run marginal cost of energy is
now below the step two energy price and will continue
to be under all the options. In the past, we were
always chasing that long-run marginal cost by
increasing -- applying a greater percentage of
increase to the step two rate. Now that’s no longer
necessary because our long-run marginal cost is
actually below the step two energy rate.
So I think that is the change that has
resulted in Hydro re-looking at the pricing principles
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and whether that rapid pursuit of increasing step two
is still appropriate, and determined at this time that
we don’t think it is.
MR. GODSOE: And I would add, just for the record, and
ease of reference in the transcript, I think Section
1.4 of the application clearly lays out what we see as
the changes. One of them was, of course, the
uncertainty at the time of the filing on the RRA
increases and their magnitude. That issue has been
addressed. But it really does come back down to the
long-run marginal cost. It’s significantly below what
new greenfill IPPs would be. They’re simply not as
cost-effective as renewing existing electricity
purchase agreements or pursuing the DSM target.
Proceeding Time 10:53 a.m. T23
MS. ASHLEY: Those are my questions.
THE CHAIRPERSON: Thank you very much, Ms. Ashley.
Now, I’d like to open the floor back up
again now and ask the interveners if, on the basis of
Staff’s questions, whether they would like to pursue
further questions.
MR. ANDREWS: I have none.
THE CHAIRPERSON: You have none?
MR. PERTTULA: We have none, FortisBC.
MR. CRAIG: I have one, just one question that I’d like
to get confirmation on.
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THE CHAIRPERSON: Please proceed.
MR. CRAIG: When there’s a price signal and that’s
considered part of a DSM measure, the DSM savings that
are achieved usually involve both energy and capacity.
I’m just looking for confirmation that that’s in fact
the case.
MR. GODSOE: So at a high level I think that’s confirmed.
I am going to put on the record that generally
speaking for DSM programs, we track actions and then
translate into energy savings. There’s been to date
little evaluation of anticipated capacity savings. So
I’m certainly not going as far as saying the
aggressive 1,400 megawatts anticipated to be delivered
by DSM is a made-up number, but it’s certainly an
uncertain number. But at high level I agree with you.
MR. CRAIG: Thank you. That’s it.
MS. PRITCHARD: Nothing further from us either.
THE CHAIRPERSON: No further questions, Ms. Pritchard?
So I think that brings us to the conclusion of this
phase here. I would, before we take a break, like to
ask a couple of things, and I’m wondering if perhaps I
might request those of you making submissions to
declare your position with regards to the application
and whether you support it or do not support it, and I
would appreciate some thoughts on the control group
from each one of the interveners. And before we take
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a break, I would like to pursue a couple of questions
on the control group myself.
Now, I find it interest -- sorry, that’s
clear, you will address those issues, I trust.
I find it interesting that the issue of the
control group has been raised, and obviously B.C.
Hydro is quite supportive of the idea of a control
group if you can find a satisfactory research design,
a satisfactory number of clients, and/or victims or
whatever you wish to call them. And I’m also very
cognizant of the difficult of doing research designs
from an ethical standpoint, from a legal standpoint,
and certainly in my earlier life we used to have a
term, I don’t know if it’s used out here, of being
foiped as an expression. So those issues are a
concern.
But laying those aside, perhaps B.C. Hydro
would be willing to sort of give us an idea of if --
and you have said you are going to look at this as a
possibility. What sort of timeframe do you visualize
needing in order to decide whether to get a control
group established, and whether that is an area that
you would pursue vigorously given some of the benefits
of it?
MS. JUBB: Our first line of inquiry will be to
investigate the use of the New Westminster data, as
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that is low cost and has no customer impacts. And we
should have a sense of whether or not that line of
inquiry will be successful by the fall.
THE CHAIRPERSON: And would you be looking at a better
group? I think your evidence was that that was not
representative of your customer base, as I recall.
MS. JUBB: That is correct. However, the approach taken
if we use New Westminster customer data would be to
input the consumption into the existing econometric
models, and those models would control for the lack of
representativeness.
THE CHAIRPERSON: Mm-hmm. So in terms of -- you’ve
raised the issue of costs. In any of these types of
matters, it’s a case of diminishing returns in my
experience. So you can get a reasonable handle of
things at a relatively low cost and in a relatively
short time span. But to get the final three or four
levels of precision, the costs escalate substantially.
Is that it?
Proceeding Time 10:58 a.m. T24
MS. JUBB: I think in the case of the RIB evaluation with
the Step 2 elasticity estimates, we have very strong
statistical significance on those estimates. And that
is not what I would consider to be an overly costly
exercise, because we were able to make use of existing
data.
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THE CHAIRPERSON: So you would see no problems -- or you
would be able to have reached a decision by the coming
autumn, and do you visualize any particular
difficulties in getting permission to use the New
Westminster data, as you suggest?
MS. JUBB: Customer privacy is always a concern, and data
sharing is always a concern due to customer privacy.
There may also be issues with respect to the
information in the New West billing system. And
whether or not it’s compatible with the econometric
models. So there could be a number of barriers to
that approach that B.C. Hydro would need to
investigate.
THE CHAIRPERSON: If the fall is a reasonable time frame,
would you be willing to inform the Commission of your
decision in a letter, and perhaps the reasons for
reaching the decision that you did?
MR. DOYLE: Yeah, we could commit to informing the
Commission of our decision on the --
Information Request
THE CHAIRPERSON: Well, thank you very much. Well, I
have no additional questions.
Going once, going twice? If there are no
further questions, I would ask the interveners and
counsel to be mindful of my requests, and I would
suggest we take a 15-minute break. But before we do,
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is that adequate time, Mr. Godsoe, to be able to be
prepared to --
MR. GODSOE: It is for my purposes.
THE CHAIRPERSON: It is for your -- how much time will
the various interveners need? Mr. Andrews?
MR. ANDREWS: That would be fine.
THE CHAIRPERSON: Ms. Pritchard?
MS. PRITCHARD: Yeah, that’s fine.
THE CHAIRPERSON: That’s fine? That’s fine. Thank you
very much. We’ll reconvene at 11:15.
(PROCEEDING ADJOURNED AT 11:00 A.M.)
(PROCEEDINGS RESUMED AT 11:18 A.M.) T25/26
THE CHAIRPERSON: If you’re not, speak up, please.
With that, Mr. Godsoe, I will invite you to
begin your final submissions.
SUBMISSIONS BY MR. GODSOE:
MR. GODSOE: Thank you. B.C. Hydro’s requested Order is
found at Appendix A of the application. We take
staff’s point that paragraph 2 could be modified to
delete the reference to a separate RIB application,
and refer instead to the fiscal 2016 rate design
application.
For purposes of when you come to decide, I
thought I’d highlight certain aspects of the
application. I think Hydro’s final submission is
frankly framed in Sections 1.1, 1.2.2, 1.3, 1.4, and
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2.4 of the application. Those contain legal
principles and our conclusions.
In my final submissions, I want to
emphasize two points. First, briefly, the legal test
and the selection of option 2 is B.C. Hydro’s
preferred pricing principle. And then second I want
to come to the scope of the application and the fiscal
2016 rate design application.
So B.C. Hydro filed this application
pursuant to the Utilities Commission Act, Sections
58(1)(a), Section 60(1), and Section 61(1). The legal
test under those Sections is that the RIB rate to be
set by the Commission must be fair, just, and not
unduly discriminatory. And I think we can all agree
that’s a very broad test. And B.C. Hydro’s
submissions concerning the scope of those sections is
found at page 1-7 of the application.
As with prior RIB decisions, B.C. Hydro
used two Bonbright principles as the main criteria.
And we have discussed those today, which are
efficiency and bill impacts. We submit this
application is consistent with three past BCUC
decisions concerning B.C. Hydro’s RIB in 2008, and
2011, and FortisBC’s RIB in 2012. And further details
are found in Section 1.2.2 of the application.
In those prior decisions, and we would urge
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the Commission to do so again, the Commission found
that pricing above LRMC is not economically efficient.
This is clear in both the BCUC decision on B.C.
Hydro’s 2012 RIB and on Fortis’s 2012 RIB.
We have no objection to having efficiency
debated in terms of parameters as part of the fiscal
2016 rate design application. However, we would
submit that for procedural fairness reasons, having
that debate at the end of a process on a two-year
application would neither be efficient nor effective.
And so we would urge deferral of that to the fiscal
2016 RDA.
We submit that option 2 should be adopted
by the BCUC for several reasons. First, the evidence
firmly establishes that RIB tier 2 is already slightly
exceeding the upper end of the LRMC range of $100 per
megawatt hour. Second, the estimated conservation of
all three options doesn’t differ much, particularly if
you factor into that analysis forecast uncertainties.
We sometimes get caught up in false precision on these
issues.
We therefore submit that bill impacts
should be the main criterion, and there are
differences in the three options. Option 1 would
impact higher energy consumers. Option 3 would have
larger bill impacts on low energy consumers. Low
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income customers have a distribution fairly similar to
the broad class, but are more clustered in tier 1, and
therefore low energy consumers would be more adversely
affected by option 3, and this was given serious
consideration as reflected in Section 2.3.4 of the
application.
Lastly, we would submit option 2 is
understandable. It’s simple. The RRA increases are
applied to all three elements.
I want to turn now briefly to the scope of
the application. I think we have emphasized this is a
two-year bridging application for fiscal 2015 and
fiscal 2016. We also emphasize the scope of the
application was the subject of two pre-filing
workshops in August and September, and I think those
are described in Chapter 3 of the application. The
major reason for the scope of the application is the
significant uncertainty concerning the LRMC.
You heard from Mr. Randy Reimann, who is
B.C. Hydro’s director of resource planning, that the
LRMC will be the subject of a fall 2015 IRP update, as
set out in Section 9.5.4 of the approved 2013 IRP. As
set out in our response to BCUC IR 1.3.1, the IRP was
approved on 26 November, 2013, pursuant to Order in
Council 514. And we would urge the Commission to give
that significant weight.
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In 2015, B.C. Hydro expects to have more
information on several elements that would inform the
LRMC. First, the performance of the aggressive DSM
target of 7,800 gigawatt hours per year of anticipated
energy savings, and 1,400 megawatts of associated
capacity savings.
Proceeding Time 11:23 a.m. T27
This is an aggressive target and we must monitor
whether in fact it is delivering the anticipated
savings.
Second is the price informed volume of
electricity purchase agreement renewals. They will be
more under our belt in 2015.
Third is whether Site C will proceed, and
if it does not, that will impact our LMRC.
Last, we expect LNG final investment
decisions and service requests to be made at the end
of this year and in 2015.
The LRMC would also be revisited as part of
the fiscal 2016 RDA. As you’ve heard today, the
essential elements of the 2016 RDA will be examining
RIB pricing from fiscal 2017 onward, addressing the
remaining issues found in Directive 4 of BCUC Order G-
45-11, such as the tier 1/tier 2 threshold and the
interaction of the basic charge and the RIB rate
structure.
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Also, we anticipate other conservation rate
structures such as the large general service and
medium general service classes to be examined, and
finally, and most importantly I think for an RDA, is
the cost of service, and perhaps some potential rate
rebalancing within the contours of Section 58.1 of the
Utilities Commission Act.
And that concludes B.C. Hydro’s final
submission.
THE CHAIRPERSON: Thanks very much, Mr. Godsoe. Ms.
Pritchard?
SUBMISSIONS BY MS. PRITCHARD:
BCPSO is generally not opposed to the
Commission approving B.C. Hydro’s proposed pricing
principle. That is, applying the 2015/16 RRA to each
of the three elements of the RIB.
That said, it’s my understanding that the
application was a placeholder to enable B.C. Hydro to
direct its attention to a fiscal 2015/16 revenue
requirement application which would be followed by a
full hearing on DSM and rate design. There’s no
longer need, of course, for the 2015/16 RRA following
the significant rate increases announced in November.
And we are of the view that none of the three options
suggested by B.C. Hydro can fully address the needs of
B.C.’s most vulnerable ratepayers. And they need
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protection from rate increases they will be unable to
afford, and we submit that our client’s interests can
only fully be addressed through a comprehensive
hearing on rate design and DSM. And we would like to
see that conducted as soon as possible.
We submit that the issue of DSM must be
considered as part of a rate design application as
B.C. Hydro’s low income DSM programs may otherwise be
used to deflect concerns about rate impact on low
income ratepayers. And with the 9 percent increase on
April 1st fast approaching, the possible mitigants for
the rate increases must be thoroughly canvassed in a
public hearing where it will be possible to examine
both rate design and terms and conditions of service
in B.C. Hydro’s electric tariff from a low-income
standpoint, and to conduct a full examination of the
effectiveness of B.C. Hydro’s low income DSM programs.
And for this application we do see the
proposed option, that is option 2, as the best of
those available. While option 1 would affect fewer
low income ratepayers overall, as a low percentage of
these customers regularly fall into step 2, those that
are impacted will have to pay a significant dollar
amount for their energy use in step 2. Some high
energy users may be able to lease -- or sorry. Some
high energy users may be least able to modify their
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use, and so electricity becomes increasingly
unaffordable for those customers.
Option 3, on the other hand, impacts the
largest number of customers and this option offers
very little to our client group as it really only
benefits the high energy users.
We do have one comment on the application.
Since we are setting rates for 2015 and 2016, BCPSO is
of the view that the range should be expressed in the
year’s dollars for which the rate will be set.
With respect to the planned rate design
application, BCPSO supports an RDA based on all
classes of customers, so we are pleased to see that
that’s Hydro’s intention. And as I’ve already said,
we’d like to see a hearing on DSM expenditures
combined with the RDA as the issues are inter-related.
On the timeline of that, we’ve heard that
B.C. Hydro intends to do significant stakeholder
consultation prior to the planned 2015 filing.
Proceeding Time 11:28 a.m. T28
And while we welcome that broad and
meaningful stakeholder consultation prior to filing,
we are not in favour of dragging out that process to
the extent of timely filing of the RDA, and we would
prefer to see the application filed by the end of this
year.
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With respect to the control group, BCPSO
does not oppose the Commission approving its
dissolution. In terms of replacing it, we would
support instituting a control group if it can be done
in a way that’s useful for analyzing power usage by
residential customers in the two steps. However, we
do have concerns about a control group being
involuntary because of potential negative rate impact
for those customers. If B.C. Hydro cannot design a
control group that will address those concerns, then
we would encourage Hydro to look into other potential
means of gathering residential customer data about end
use that could be useful in the upcoming RDA or in the
next RIB application.
Pending any questions from the Chair, those
are our submissions.
THE CHAIRPERSON: Are there any questions for Ms.
Pritchard? If that’s the case, thank you very much,
Ms. Pritchard.
Just to summarize it, I think I heard it
correctly. Did I understand you to say BCPSO has no
opposition to the application at the moment?
MS. PRITCHARD: Yes, that’s correct.
THE CHAIRPERSON: Thank you very much. Mr. Craig?
SUBMISSIONS BY MR. CRAIG:
Commercial Energy Consumers will support
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the B.C. Hydro application, including supporting their
choice of Option 2, and the pricing differences are
not significant as pointed out by B.C. Hydro, and the
bill impact issues are significant. The CEC would
recommend to the Commission that any decision in
regard to this have significant weight placed on B.C.
Hydro’s repeated view that this is a two-year bridging
and that the Commission decision should be confined to
this two-year period and not create principles or data
that would be carried over into the RDA, which will be
a more fulsome process and that all the issues of
principle and practice should be open in the RDA and
it’s -- I don’t think it’s Hydro’s intent to do that
in this case, but I think it’s important for the
Commission to put those confining words around the
decision, and it’s important to my agreeing to do this
that that would be part of the decision.
To the extent that the Commission in the
decision makes assessments or comments with regard to
what the LRMC is, the CEC’s position would be that
it’s important that the Commission emphasize that in
its ratemaking it has the duty and responsibility to
make the determinations about the data that go into
the rate, and the information in the integrated
resource plan is one of the pieces of evidence and
certainly is to be given some significant weight.
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The CEC’s view of the LRMC as it sits in
the IRP is that it is in an assessment of just the
energy charge, and we have raised in information
requests, in particular CEC 1.35.2 and CEC 1.14.2, the
questions of capacity. And the discussions that we’ve
had today I think have elucidated the issue. From the
CEC’s point of view they serve to raise the LRMC as it
sits in the IRP and the other information around it up
closer to where Hydro has recommended the rates be,
and I think it’s important that there are appropriate
principles that support that being up much closer to
where the recommended rates are.
That being said, I’m not looking for the
Commission to establish that as a principle either in
this process, but simply to acknowledge that that
information has been put on the record.
Proceeding Time 11:33 a.m. T29
And maybe an appropriate set of information
and principles to be addressed in the RDA when Hydro
gets to dealing with it.
The reason for that is the evidence
elicited today that the price signal is all related as
an energy charge to the customer, but it delivers both
energy savings and capacity savings. And the price
signal must carry the costs related to both energy and
capacity as a price signal, as that’s the preferred
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mechanism for pricing to residential customers. And
it’s done across most utilities in that way.
And I’ll leave more of the specifics in
terms of what we may talk about till later. But I
think it’s important if the Commission, in doing that,
any determination at least pass those issues over to
the RDA. And I would support the BCPSO in dealing
with the 2015/2016 definition of LRMC in CEC 1.41.2,
the responses that the range for 2016 would be $90 to
$106. You have other information presented today that
Hydro’s view of the 2015 is 104 in the presentation.
And then some of these outstanding questions of
principle that might leave some uncertainty as to
where that may be set in a future RDA. And I think
suffice it to say that you would lead to a conclusion
that the proposal from B.C. Hydro is an appropriate
price, and there are enough uncertainties with regard
to the LRMC that the fact that it’s lower is not a
problem for the Commission in setting the rate.
Specifically, you asked us to address the
control group. And my view is that B.C. Hydro’s
proposal to dissolve the previous control group is an
appropriate proposal. The Commission should accept
that.
THE CHAIRPERSON: Sorry. Did you say appropriate, or
inappropriate?
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MR. CRAIG: Appropriate.
THE CHAIRPERSON: Thank you very much.
MR. CRAIG: That the CEC was involved in all the
processes that were engaged in in the set-up of that
control group and its purposes. There are lots of
issues with regard to those control groups, the
information Hydro has put on the table with regard to
why it should be resolved, and in the CEC’s view is
correct and it’s appropriate.
And in CEC 1.22.4, the fact that New
Westminster has a flat rate, and may be a reasonable
proxy referencing the Commissioner’s view about
diminishing returns, I think this is a really useful
area to explore, and I would encourage the Commission
not to go beyond that in trying to order some other
form of control group, and wait for the information
from B.C. Hydro as to what they are able to do. And
what other concerns they may be able to deal with.
And I’m also cognizant of B.C. Hydro’s view
with respect to time frames. Between now and the next
RDA to properly set up a control group, run data, and
get results that may be useful, I think, will be
beyond the scope of what would be meaningful and add
value. So, I think we’re in a position where the
CEC’s view is that the control group should be
dissolved. The Commission should encourage B.C. Hydro
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to make every effort to work with New Westminster. I
think privacy concerns can easily be dealt with
because B.C. Hydro doesn’t need individual customer
data. It can get data that’s cleansed of specific
customer information.
Proceeding Time 11:38 a.m. T30
I’m sure with Privacy Commissioner assistance all of
those issues can be dealt with, and I agree with B.C.
Hydro’s information that there are ways to adjust the
relevance of the data to its purposes, and I think we
can get 80 percent for 10 percent of the money, and I
think it’s worth encouraging Hydro to go there.
And those are my submissions.
THE CHAIRPERSON: Thank you very much, Mr. Craig. Are
there any participants who would like to ask questions
for clarification of the CEC’s position?
Hearing none, I’ll turn it over to Mr.
Perttula or Mr. Brownell, whichever one of you intends
to make the final submissions.
MR. PERTTULA: I will make the comments. Dave Perttula
from FortisBC.
SUBMISSIONS BY MR. PERTTULA:
We are supportive of B.C. Hydro’s requests
in this application. I won’t speak in detail to any
except the selection of the -- among the three pricing
options.
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The last RIB repricing application that
gave the decision in 2011, FortisBC supported that
pricing -- the same pricing option as option 2 in that
particular situation, and we had various reasons for
doing that. And so we continue to support that
solution, option 2, and what’s changed between the
last pricing application and this one, as we’ve heard
this morning and seen in the presentation is the
reduction in the -- or moderation in the outlook for
the LRMC. And so I think that -- or we think that the
price transparency in that rate structure, the fact
that all customers will get whatever the RRA increase
is applied uniformly is a strong reason to support it
The other two pricing structures have bill
impacts on different customer groups as we’ve been
hearing this morning. But the other aspect of that is
that there’s really no one that can calculate those
other pricing structures other than B.C. Hydro. They
are -- I don’t know if I should use this word, but
it’s effectively a black-box calculation where no one
else really can determine whether the rate increases
or the Step 1 Step rates have been applied
appropriately.
Proceeding Time 11:41 a.m. T31
I’m sure they have, but it’s just that no
one can actually confirm that. And so we believe that
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the Option 2 approach is fair in terms of its
application to all customers, and in effect that’s the
rationale for our support of it.
Yeah, and I don’t have any specific
comments on the other requests for relief or
Commission determinations, so I’ll leave it just at
that.
THE CHAIRPERSON: Thank you very much. So let me just
clarify. As I understand your submission, you have no
difficulties with matters as applied for, and you have
no objections to the additional requests. Is that
correct?
MR. PERTTULA: That’s correct.
THE CHAIRPERSON: Mr. Perttula, thank you very much. Are
there any participants that would seek clarification
on Mr. Perttula’s presentation?
I suppose that leaves you, Mr. Andrews.
SUBMISSIONS BY MR. ANDREWS:
Yes. Well, the Sustainable Energy
Association of the Sierra Club support the requests
for relief that Hydro has asked for in this
application. I won’t go through in detail all the
criteria. The organizations have been involved in the
Commission’s proceedings to do with the development of
the RIB rate since its beginning, and they
participated in the consultations that B.C. Hydro had
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regarding this particular application.
In brief, their conclusion is that now is
not the time to go into a careful examination of
principles, that a two-year bridging process is
appropriate, that the Option 2 is the one which is the
simplest and most easily understood, that the rate
itself presumably took some time to be understood by
ratepayers in general. And therefore it’s our
submission that especially now, and the one additional
thing that has changed perhaps in addition to the LRMC
is the government’s imposition of the 9 percent plus 6
percent rate increases starting in the next fiscal
year.
In our submission, that makes it even more
important to keep simple communications in terms of
the RIB rate. That is, for example, that it is not
any change in the RIB rate that’s causing a bill
impact for customers.
Proceeding Time 11:44 a.m. T32
The RIB rate is as it’s always been. The
impacts, if people experience them, are to do with the
9 percent and the 6 percent.
In terms of the conservation impacts
between the three options, I think I would agree with
Mr. Godsoe’s term to do with the numbers. While there
are numbers that, if you look at them, with precision
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indicate some differences. In reality, they are
actually all quite similar and in my submission they
get swamped by the impact of the 9 percent and the 6
percent coming up in April
Regarding the control group, like CEC, my
clients were involved in the original time-of-use
proceeding that led to the formation of that control
group and strongly supported it. They are persuaded
that now the time has come to end it. The group
support the concept of a control group but acknowledge
that there are pros and cons and potential
difficulties in a number of respects, cost being one,
and cost effectiveness, how much bang for your buck
you get. The other being the regulatory issues,
particularly if one is contemplating an involuntary
control group. And just to be clear, the time-of-use
control group that’s proposed to be abolished was a
voluntary control group. So we have not yet, in B.C.,
crossed the bridge of any involuntary control group.
So in my submission it would be useful for
the Commission to ask B.C. Hydro to provide a letter
informing the Commission and parties regarding the
decision that they’ve made about how to do a control
group, whether it’s New Westminster or something else
when they make that decision. But I do accept that
the Commission should not anticipate that it’s an
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automatic that more -- that a control group
specifically focussed on the RIB is necessarily the
outcome that ought to be preferred. I mean, it
certainly ought to be considered, but --.
And I may say that in a larger sense, the
Sustainable Energy Association and the Sierra Club are
very interested in B.C. Hydro improving its research
ability and results in terms of understanding how
consumers use energy and why at a larger level, and
that’s another reason why a control group specifically
focussed on the residential inclining block rate
process may not be the most cost effective way to
improve research about energy usage more broadly.
So with that, those are my submissions.
Proceeding Time 11:47 a.m. T33
THE CHAIRPERSON: Thank you very much, Mr. Andrews. Are
there are any participants who would like to ask
questions for clarification with regard to the
BCSEA/SEA presentation?
If not, we can either proceed directly, Mr.
Godsoe, into your reply argument, or if you would like
a short break, we could take one.
MR. GODSOE: I would prefer a short break, just so I can
be effective and efficient in my reply.
THE CHAIRPERSON: Would five minutes be sufficient?
MR. GODSOE: Five minutes is sufficient.
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THE CHAIRPERSON: Thank you very much.
(PROCEEDINGS ADJOURNED AT 11:48 A.M.)
(PROCEEDINGS RESUMED AT 11:56 A.M.) T34/35
THE CHAIRPERSON: Mr. Godsoe, would you like to have a
reply argument on behalf of B.C. Hydro?
REPLY BY MR. GODSOE:
MR. GODSOE: I would, and I’m going to confine myself to
five points.
First, I think it is significant that two
of our intervenor groups that represent residential
ratepayers, that being BCPSO on behalf of low income
residential ratepayers, and B.C. Sierra, on
environmentally-minded ratepayers support the
application.
That being said, while BCPSO’s views matter
greatly to B.C. Hydro, given this is a residential
rate application, we do not agree that a fiscal 2016
rate design application can be done by the fall of
2014. As we have stated, there is a lot of competing
interests and we would urge the Commission to refrain
from setting or hard-wiring a date for that
application in any decision.
Secondly, we also urge the Commission to
refrain from directing whether demand-side management
in particular, and expenditure schedule, should or
should not be part of the 2016 RDA. As I said, we
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need to look at the scope of the direction setting the
revenue requirement for fiscal 2015 and fiscal 2016,
and that might well take care of any Section 44.2
filing.
That being said, we do agree with BCPSO
that DSM is a background issue on the 2016 RDA is
appropriate and in particular how rate structures,
which are involuntary, would play with programs that
are voluntary particularly with respect to our low
income groups.
Third point would be on -- sorry, fourth
point, would be on the control group. I wanted to
clarify that we believe our letter informing the
Commission would be confined to how we think the New
Westminster would play out as an effective control
group or not. I don’t think we can bind ourselves
into whether, in fact, we think a control is
appropriate for the entire class or how that would
look. So I wanted to down expectations in that
letter. That being said, we agree completely that
that issue should issue on New Westminster as soon as
it can. I think we’ve been clear, that would be
around the fall of 2014.
Lastly, we strongly agree with CEC that
this is a two-year bridging application and that
principles -- sorry, and that points decided upon by
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the Commission don’t necessarily bind us in the fiscal
2016 RDA. I think that I would take the opportunity
to urge to say as little as possible, if you can, on
what the fiscal 2016 RDA should look like. We
sincerely mean that it should be informed by customer
engagement. We think that is going to take some time.
But we are committed to filing that in mid-2015.
And those conclude my comments.
THE CHAIRPERSON: Thank you very much, Mr. Godsoe. Are
there any participants who would like to ask questions
for clarification of B.C. Hydro’s final submission?
That being said, it would appear as though
we are bringing this portion of the hearing together,
the process together. If you would, I would like to
have probably five minutes to consider what I have
heard this morning, and we’ll reconvene in five --
perhaps seven or ten and no more, and I’ll inform you
of how I intend to proceed.
Thank you very much.
(PROCEEDINGS ADJOURNED AT 12:00 P.M.)
(PROCEEDINGS RESUMED AT 12:07 P.M.) T36/37
THE CHAIRPERSON: Well, I am prepared to make a ruling
today from the bench. And I’d like to give you the
substance of my ruling with a more formal one that
will follow later.
After reading over the last couple of
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months, and considering the evidence and arguments
from all parties to this application, and based on
what I have heard and considered this morning, as the
Commissioner appointed by the Commission to address
the B.C. Hydro residential inclining block rate re-
pricing application before us -- that’s a bit of a
tongue-twister, actually -- and in consideration of
the statements from interveners that they are
supportive of the application, I am prepared to make
the following ruling with the recognition that a
formal one will follow.
The Panel approves B.C. Hydro’s proposed
RIB rate pricing principle for fiscal 2015 and 2016,
by increasing each of the three components of the RIB
rate, namely step 1 energy rate, step 2 energy rate,
and the basic charge by the provincial government
directed rate increases of 9 percent and 6 percent,
respectively, for the fiscal 2015 and 2016.
Furthermore, the Panel also approves
dissolution of the RIB rate -- sorry, pardon me. The
RIB rate control group. Thank you for that
clarification. I think that might have been perhaps
more latitude than I have.
I found the discussion on the control group
very interesting. And I’d very much appreciate the
panel -- or the suggestion of B.C. Hydro, that they
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will look into it.
So therefore to wrap up my -- the substance
of my thing, I would request -- the Panel requests
that B.C. Hydro file a report with the Commission
concerning its decision with regard to the control
group re-establishment by or before the autumn of
2014. And that this report provides reasons for B.C.
Hydro’s course of action. Furthermore, the Commission
requests that B.C. Hydro copy all interveners with
this report.
MR. GODSOE: Copy all interveners to this proceeding?
THE CHAIRPERSON: To this proceeding, thank you very
much. Yes. And with that, I would ask if any of you
wish clarification on matters of my ruling.
MR. GODSOE: Only that -- have you also approved B.C.
Hydro’s request for relief from certain elements of
Directive 4 of the prior RIB order?
THE CHAIRPERSON: Yes. I believe, yes, we do. Pardon
me. Are there further questions of clarification?
That being said, ladies and gentlemen, I
thank you very much for coming this morning, for your
attention, and all of your hard work, and submissions.
And that constitutes the end of our SRP process. So,
thank you very much and good day.
(PROCEEDINGS CONCLUDED AT 12:11 P.M.)