british columbia utilities commission · 1/29/2014 · the b.c. ministry of energy and mines,...

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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Allwest Reporting Ltd., Vancouver, B.C.

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.


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.


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.


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.


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.


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.


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.


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.


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.


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.


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.


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.


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.


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.


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.


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?


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.


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.


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.


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 --


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.


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.


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?


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.


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.


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.


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.


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.


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.


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.


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.


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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(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.)

british columbia utilities commission · 1/29/2014 · the b.c. ministry of energy and mines,...

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