BRITISH COLUMBIA UTILITIES COMMISSION · 7/14/2014 · MR. MILLER: B.C. Sierra -- or Sierra Club of British Columbia and B.C. Sustainable Environmental Association. MR. ANDREWS:

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

FortisBC Energy Inc. Application for Approval of a Multi-‐Year Performance Based Ratemaking Plan for the years 2014

through 2018

BEFORE: D.M. Morton, Panel Chair/Commissioner D.A. Cote, Commissioner N.E. MacMurchy, Commissioner

VOLUME 8

ORAL ARGUMENT

Vancouver, B.C. July14th, 2014

APPEARANCES P. MILLER Commission Counsel M. GHIKAS L. HERBST C. BYSTROM

FortisBC Energy Inc. and FortisBC Inc.

C. WEAFER Commercial Energy Consumers Association

British Columbia Municipal Electric Utilities R. HOBBS Industrial Consumers Group F.J. WEISBERG Irrigation Ratepayers Group T. BRAITHWAITE B.C. Pensioners' and Seniors' Organization

Active Support against Poverty, Tenants’ Resource and Advisory Centre, Council of Senior Citizens’ Organizations, and the B.C. Coalition of People with Disabilities

J. QUAIL L. WORTH

COPE Local 378

W. ANDREWS B.C. Sustainable Energy Association

Sierra Club of British Columbia

Fortis Energy Inc./Fortis BC Inc. Multi-year Performance Based Rate-Making Plan July 14, 2014, Volume 8 Page

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Allwest Reporting Ltd., Vancouver, B.C.

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CAARS

VANCOUVER, B.C.

July 14, 2014

(PROCEEDINGS RESUMED AT 8:56 A.M.)

THE CHAIRPERSON: Please be seated. Good morning, ladies

and gentlemen. Also please, if you find it warm in

here, please feel free to take your jackets or your

sweaters off. We’ll try and be informal at least to

that extent.

My name is Dave Morton. With me are

Commissioners Norm MacMurchy and Denis Cote. Welcome

to this morning’s proceeding to hear further oral

arguments related to two applications currently before

the Commission. These applications both seek approval

of multi-year performance-based ratemaking plans for

2014 through 2018. One was submitted on June 17th,

2013 by Fortis Energy, the second on July the 10th,

2013 by FortisBC. For convenience I'll refer to

Fortis Energy as Fortis Gas and FortisBC as Fortis

Electric and, when speaking of them both together,

simply Fortis.

As you are all aware, elements of the two

applications were combined into a single proceeding,

specifically those items related to the PBR formula.

Fortis’s reply arguments, consisting of a

joint reply on PBR methodology and separate reply


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arguments on each of Fortis Electric and Fortis Gas’s

non-PBR elements, were received on July the 12th, 2014.

Subsequent to the receipt of Fortis’s reply arguments,

the Panel issued further Information Requests to

Fortis and to intervener CEC. Responses to these IRs

have been received, and parties are now invited to

provide further submissions on these responses.

Further, the Panel invites parties to

address the following topics. First is that, in the

event the performance-based ratemaking process

continues following the proposed period, what

processes do the parties recommend for transition to

the next phase of PBR? For example, a rebasing

process. What should be the timing of the rebasing

filing? What items should be reviewed in the

proceeding to consider the rebasing application? And

any other process suggestions or issues parties want

to raise with regard to an ongoing PBR regime.

The second issue, or the second question on

which we are inviting submissions, is what process is

recommended for setting rates for the 2014 and 2015 if

Fortis’s performance-based ratemaking application is

turned down?

And thirdly, in this application Fortis

Electric is requesting approval for deferral accounts

for a number of its flow-through items. These same


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deferral accounts were approved for Fortis Gas in the

previous PBR but were not requested by Fortis Electric

in its previous PBR. So the Panel asks whether these

deferral accounts are necessary and/or what other

options are available.

Parties are requested to restrict their

comments to argument only. It’s not the Panel’s

intent that any new evidence be introduced at this

point in the proceeding.

At this stage it’s my pleasure to

acknowledge and introduce a number of individuals.

Suzanne Soo is lead staff for the Fortis Gas

application. Yolanda Domingo is lead staff for the

Electric application. With them are Sarah Walsh and

Philip Nakoneshny and they are seated at the front.

Commission counsel for the proceeding, Paul

Miller from Boughton, is also seated at the front, and

Mr. Hal Bemister is our Hearing Officer, seated at the

side.

Before Mr. Miller takes over, I’d like to

ask you please to make sure your submissions are

directed to the issues that I’ve just outlined,

together with any other issues that you or any other

participants identify, and that the Panel accepts as

appropriate for addition to the agenda.

I’m going to ask for Mr. Miller to call for


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appearances, and as you enter your appearance please

state your name for the record, the party you

represent, and identify any other matter you’d like

the Panel to consider. Please also advise whether you

prefer that the issues be dealt with all together or

if you require or recommend a separate round, and by

that I mean a separate round for Fortis Electric and

Fortis Gas and the joint PBR component.

After appearances, the order of submissions

will begin with Fortis Gas jointly with Fortis

Electric, and then it will follow the order of

appearances. Once each party has had an opportunity

to put forward its submission, Fortis will have the

right to reply if it so chooses.

In the view of the Panel, all of the issues

I previously outlined are most efficiently canvassed

collectively as opposed to issue by issue. However,

as I said, if you feel otherwise, please address that

during your appearance.

Mr. Miller, please go ahead.

Proceeding Time 9:10 a.m. T2

MR. MILLER: The first appearance is by FortisBC Inc. and

FortisBC Energy Inc.

MR. GHIKAS: Good morning, Mr. Chairman, Commissioners.

My name is Matt Ghikas, and I am appearing on behalf

of the FortisBC companies. With me this morning is


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Ludmila Herbst, H-E-R-B-S-T, and Christopher Bystrom,

B-Y-S-T-R-O-M.

In terms of the approach this morning,

Fortis is content to proceed with all of the issues

first together.

THE CHAIRPERSON: Together.

MR. GHIKAS: And there was one additional issue that

Fortis considered that it be useful to address, and

that is that the demand-side measures regulation has

just been passed, and put into effect, and Fortis

would consider it useful to address briefly the

implications of that, if any, on the applications.

THE CHAIRPERSON: Yes, thank you, Mr. Ghikas. The panel

would actually appreciate that if you could address

that at this time. That would give any other parties

an opportunity to address that during their

appearance.

MR. GHIKAS: Thank you. And what -- in terms of the

substance, Ms. Herbst is going to speak to that

directly. We can address that in our initial pass

through. Ms. Herbst has to make a few submissions on

one of the issues that the panel outlined, and she

would do it in conjunction with that, if that was most

efficient.

THE CHAIRPERSON: That is fine.

MR. GHIKAS: Okay, thank you.


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MR. MILLER: Commercial Energy Consumers and B.C.

Municipal Electrical Utilities?

MR. WEAFER: Good morning, Mr. Chairman, members of the

panel, my name is Chris Weafer, W-E-A-F-E-R, appearing

for the Commercial Energy Consumers’ Association of

British Columbia, and the British Columbia Municipal

Electric Utilities. We have no issues to add to the

agenda and we are comfortable dealing with the issues

all in one appearance.

I am going to raise one issue that in terms

of our submissions, I have a written text for

submissions on the key issues in your -- the panel’s

list of questions. There was a general comment in

that list around any comments on the Information

Requests. I don’t have those in writing and they --

as the panel will know from exchange of correspondence

last week, there was some exchange about whether Dr.

Lowry would be available to the panel to answer any

detailed questions. He has provided -- and that was

determined the panel would not deal with Dr. Lowry

directly -- he has provided me some comments on the

Information Requests that I intend to make submissions

on, and I am happy to separate those out from the

other questions, because they may be a point of

contention with Fortis based on the correspondence

last week. So, I am in your hands. I am happy to


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deal with all issues together, or I am happy to carve

off and deal with the comments on the Information

Requests as a separate item.

THE CHAIRPERSON: We’d like to deal with them all

together.

MR. WEAFER: That is fine, thank you.

MR. MILLER: B.C. Sierra -- or Sierra Club of British

Columbia and B.C. Sustainable Environmental

Association.

MR. ANDREWS: William Andrews, representing the B.C.

Sustainable Energy Association and the Sierra Club of

B.C. I have no objection to proceeding in a batch as

Mr. Ghikas suggested, and I have nothing to add to the

agenda.

THE CHAIRPERSON: Thank you, Mr. Andrews.


MR. MILLER: British Columbia Pensioners’ and Seniors’

Organization.

MS. BRAITHWAITE: My name is Tannis Braithwaite, I am

representing the B.C. Old Age Pensioners’

Organization, formerly known as the B.C. Pensioners’

and Seniors’ Organization, the Tenants’ Resource and

Advisory Centre, Council of Senior Citizens’

Organization, Active Support Against Poverty, Together

Against Poverty Society, and the B.C. Coalition of

People With Disabilities. We have no issues to add to


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the agenda and are content to address all of the

issues raised at once.

THE CHAIRPERSON: Thank you, Ms. Braithwaite.

MR. MILLER: Irrigation Ratepayers’ Group.

MR. WEISBERG: Good morning Mr. Chairman, Commissioners.

My name is Fred Weisberg, W-E-I-S-B-E-R-G. I am

appearing on behalf of the Irrigation Ratepayers’

Group, a distinct class of the electrical utility FBC.

We have no other matters to raise, and we are content

to deal with issues collectively as you suggest.

Thank you.

MR. MILLER: Industrial Customers’ Group?

MR. HOBBS: Good morning, Mr. Chair, Commissioners.

Robert Hobbs, H-O-B-B-S. I appear on behalf of the

Industrial Customers’ Group of Fortis Electric. I

have no additions to the agenda to suggest, and I

believe that we can quite efficiently proceed with the

matters together.

THE CHAIRPERSON: Thank you.

MR. MILLER: COPE, Local 378?

MS. WORTH: Good morning, Mr. Chair, members of the

panel. My name is Leigha Worth, W-O-R-T-H, here with

my co-counsel Mr. James Quail, Q-U-A-I-L, representing

COPE 378, the Canadian Office and Professional

Employees’ Union, Local 378, the large part of the

workforce for the two applicant utilities. We have no


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issues that we’d like to add to the agenda today, and

we see no need to deal with the issues for the two

applicant utilities separately. Thank you.

THE CHAIRPERSON: Thank you, Ms. Worth.

MR. MILLER: That concludes the order of appearances, Mr.

Chair.

THE CHAIRPERSON: Thanks, Mr. Miller. Mr. Ghikas or Ms.

Herbst? Are you --

MR. GHIKAS: Thank you, yes. So, this morning what

Fortis proposes to do is to make submissions on three

broad categories, the first one being the items that

the Commission identified in its letter, some brief

comments on the responses that Fortis has provided,

and then some more detailed comments on the responses

that CEC has filed. I will be delivering the bulk of

the submissions, but as I alluded to previously, Ms.

Herbst is going to deal with the issue of the deferral

accounts that was highlighted on the Commission’s

correspondence, and there may be instances where

questions or arguments stray into the area of the base

year costs and we may, in those circumstances -- Ms.

Herbst or Mr. Bystrom may end up speaking to those.

I will move directly then to the first item

on the Commission’s June 27th letter, and that is

dealing with what happens moving into another phase of

PBR beyond the term. And the first initial point that


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I would make is that in fact, while the focus of the

question that the Commission has put forward is on a

rebasing-type process, in fact the PBR could end up

moving beyond the initial term in one of two ways.

One of them would be an extension, and the other would

be one, a new PBR that encompasses rebasing and a more

holistic look at the plan.

Dealing briefly with the extension first,

an extension -- Fortis’ submission is that an

extension would be an option to be considered in the

context where everything is working well, and where

the additional work required to undertake a complete

review of the plan isn't warranted at the time. Now,

the length of any extension, of course, has to

recognize that at some point, after being under PBR,

one does need to rebase. And so any extension that

would occur would be limited in duration. And if we

assume for the moment that we are proceeding under a

five-year PBR plan, Fortis’ position is that rebasing

would have to occur at the outside after a two-year

extension beyond with that, in order to maintain the

credibility of the plan moving forward.


COMMISSIONER COTE: Could I ask a question of you? If

you were to rebase, say, after five years and carry

on, would that be acceptable?


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MR. GHIKAS: It would as well. I’ll move to that as the

second option because I believe that, depending on how

things unfold, either one of those options may end up

being appropriate.

There is, if an extension is to be

considered in terms of the timing of looking at that,

the idea time to look at that would be at the midterm

review, because you’ve had some experience with how

things are unfolding, and it’s not right at the end of

the plan so there’s still time to -- if rebasing -- a

more fulsome application is necessary, there’s still

time to put that together and file it in time for the

beginning of the next period at the end of the PBR

term.

And of course there is precedent for an

extension. It occurred in the FEI’s 1998 to 2000 plan

when a year was added on at the end in order to permit

the company to actually recover its -- to get a

payback on its investments, but more recently the

extension was a two-year extension under FEI’s

previous plan, and that was done on the basis that it

was continuing to deliver benefits.

So with those brief comments on the

potential for an extension --

THE CHAIRPERSON: Mr. Ghikas, excuse me, I just have a

further question also.


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MR. GHIKAS: Certainly.

THE CHAIRPERSON: I’d be interested in your comments on

when a decision about a further period would be made,

and you’ve alluded to that somewhat talking about the

midterm review, and who should make it. Who should -

- who drives the decision? Is that a decision that

Fortis makes about what the post-PBR period is going

to look like, or is it a Commission-driven decision,

or is it something that all the parties agree to, say

during the midterm review?

MR. GHIKAS: Well, my general submission is that there is

a value in maintaining some flexibility to see how

things unfold. But in terms of the Order of what the

Commission makes in the context of this proceeding

with respect to a potential for an extension, in the

spirit of maintaining the flexibility, my submission

would be that the Order that the Commission makes now

should simply say that the Commission will consider

any applications to extend the PBR term at the midterm

review. And the most likely source of such an

application, just in practical terms, is probably

going to be the utility.

But certainly if parties -- the Commission

has the power to initiate processes on its own, and so

if it was to do so based on letters from other

participants of the midterm review, or the feedback of


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1357

the other participants, there is no reason why a

midterm review examination of an extension could not

occur by that route as well.


MR. GHIKAS: And certainly the last extension that

occurred was done by agreement, and there’s certainly

no reason why the Commission, in my submission, would

want to restrict itself in terms of the process that

would be used for considering an extension at this

time.

THE CHAIRPERSON: Okay, thank you.

MR. GHIKAS: So I’ll move then to the rebasing, which was

the real focus of what the Commission was getting to.

And the history of the PBR for these companies has

been that there has actually been a cost of service

test period or two in between moving from PBR. But as

discussed in the evidence, and it’s been alluded to

and I’ll just make the reference in Volume 3 of the

transcript starting at page 544, there is discussion

about -- that has been the practice, but certainly

there is no pre-condition that that must occur and the

fundamental point is that, at some point, rebasing has

to occur.


MR. GHIKAS: And the rebasing in the past has occurred

through a traditional revenue requirements process.


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1358

But the reality is that the requirement on the

Commission is simply that the rates on an ongoing

basis must be just and reasonable going forward. The

requirement is not on the Commission to do so through

a traditional cost of service hearing.

And so, with that said, it is in Fortis’s

position a very reasonable process to consider that,

if we are to move into a PBR, a new PBR beyond the

term, that it simply occur directly following the

conclusion of this term or any extension of it. And

how that would occur in terms of the timing would be

that the companies would file applications in the last

year of either the term or the extension of the term,

and, as proposed, based on the timing, that would be a

filing in 2018 for a term beginning in 2019.

In terms of the nature of the application,

the Commission has highlighted in its itemized list,

and I have alluded to already, the importance of

rebasing. And certainly then, the nature of that

application must address the base costs and rebasing.

And the application to do that would have to set out

the projected results for, in the example I gave,

2018, the projected results at the time the

application is filed for the remainder of that year,

and then translate those into a base for the next

period. And as was done in this case, that requires


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1359

adjusting some items, just as was done here -- would

have to occur again in that application as part of

that process.

But, it isn't -- and this is a key point,

it isn't possible to simply just rebase and move on

without looking at the other elements of the plan.

And the reason I say that is because what rebasing

entails is taking a hundred percent of the benefits

moving forward of the efficiencies, and flowing them

through to customers. And once you have done that,

those efficiencies aren’t there anymore, for the

companies to capture again. And that affects the

company’s ability to generate ongoing sustained

efficiencies under the next period.

And so, all of that leads to having to

examine the other terms of the plan, and in

particular, examining the X factor and whether it

remains appropriate. The Commission has before it

evidence from both Dr. Lowry and Dr. Overcast that

over-progressive PBR terms as efficiencies -- or low-

hanging fruit as it were, keeps getting eaten away --

that one has to reflect that in a lower X factor. And

indeed, that type of analysis would have to occur.

So, it isn't simply a rebasing application.

It is, in effect, a holistic view of the application

of the PBR that would look in many ways like what has


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been put forward in the present context.


MR. GHIKAS: So as I said, I will wrap that point up

simply by saying that there’s value in retaining

flexibility. And in terms of what the Commission

determines in its Order in this proceeding, as I

mentioned previously, the Commission’s Order should

simply say, in Fortis’s view, that the application for

an -- any application for an extension of the existing

term will be heard at the midterm review, and that the

companies will file an application in the final year

of the PBR, accounting for any extensions, for either

a traditional cost of service term, or sorry, a

traditional cost of service base rate structure, or

rebasing and a new PBR going forward.

The Commission can retain that flexibility

and do as it did in this process, which was to provide

direction down the road. You’ll recall the letter

from the Commission early on prior to the filing

indicating some expectations about what would be in

the filing and there’s no reason why the Commission

couldn’t, down the road, towards the end of the term,

provide similar direction.

So at this time, retaining the flexibility

for the future Commission panel sitting and for all

the stakeholders is desirable.


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1361

So I’ll move onto the next point unless

there is any questions on that.

THE CHAIRPERSON: Go ahead, please.

MR. GHIKAS: Okay. So the second item on the

Commission’s letter is what process is recommended if

the application -- if PBR isn’t pursued at this time.

And obviously it goes without saying that the

companies have articulated why they consider that PBR

should be approved at the given time. And so I will

deal with that scenario based on, as I think it was

intended, which was to deal with it in a hypothetical

sense at this time.

For 2014 I would break my submissions into

two parts. First of all is to deal with the fact that

the evidentiary record in this proceeding is

sufficient for the Commission to make a determination

as to 2014 rates, irrespective of whether PBR is

approved. And the second element is, in terms of what

those rates should be set at in that circumstance,

that the Commission should approve the applied-for

rates. And I’ll explain what I mean by that, because

as you know, there are interim rates in effect right

now and I’ll explain there’s a bit of a nuance to

that. But effectively the applied-for rates should be

the level used in 2014.

So turning to the sufficiency of the


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evidence on the record, I’ll start off by saying it’s

stating the obvious that it would be costly and time-

intensive to redo this process if it wasn’t necessary

to do that. And it is also stating the obvious that,

given the timing of where we find ourselves today,

that there is no prospect of completing a traditional

forward test year cost of service application before

the year is actually done. We’re not dealing with a

forward test year by that point.

And so really, in light of those practical

considerations, the question that the Commission

should be asking itself is is there any reason why the

Commission has to defer setting rates for 2014,

permanent rates for 2014, to another process? And my

submission and Fortis’s submission is that the

Commission has the tools and the evidentiary record,

and the ability to make that determination as part of

this proceeding. And I’ll highlight a few points as

to why I say that is the case.

THE CHAIRPERSON: Mr. Ghikas, excuse me. I just would

like to clarify. Your comments here are regarding

2014 rates only?

MR. GHIKAS: Yes.

THE CHAIRPERSON: Not 2015 rates?

MR. GHIKAS: Yes, that’s correct, and I’ll turn to 2015

in a moment.


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1363

THE CHAIRPERSON: And also for clarification, you are

speaking for both companies?

MR. GHIKAS: Both companies, correct.


MR. GHIKAS: So what we have in terms of the evidence on

the record is -- first of all we’ve got a very

extensive record on the 2013 base costs which already

reflect adjustments for sustained savings.


MR. GHIKAS: And the company in the application has

forecasted 2014 flow-through costs in the same way

that it normally does, and this reflects a significant

portion of the 2014 revenue requirement. And with

respect to the 2014 O&M capital, which would otherwise

be included in a formula under PBR, we note several

things about that for 2014. We know that there will

be inflation on the 2013 base costs, and there is

significant evidence on the record as to expected

inflation. We know that there is growth in the

business and there’s evidence on that. We have high-

level forecasts as a point of comparison, and the

revenue requirement at the existing rate base, the

capital in the ground today, is known.

And so in terms of the impact of capital,

it’s really -- the only thing that’s not known is the

impact of the capital, the revenue requirement impact


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1364

of the capital that is put in the ground in 2014.

That’s the only thing that’s not known when it comes

to capital because the depreciation and return on

everything else is known because it’s already in the

ground. And in fact, that unknown portion is actually

only the return component on the capital going in the

ground in 2014 because the depreciation on that

capital only commences in 2015.

And so really, the only thing in my

submission that we don’t have is a traditional revenue

requirements approach, an application-type approach,

where it’s delving in on a cost centre basis or on a

departmental basis that you’d have in the traditional

sense. And in my submission that is not the

requirement. As I alluded to previously, the

requirement is that rates be set on a just and

reasonable basis. And there is no requirement in the

Act, and there is nothing to suggest that the

Commission could not make that determination based on

the very significant record that is already before you

today.

So in terms of what the rates should be

fixed at for 2014 for both companies, as I indicated,

the Commission should, in Fortis’s submission, approve

the applied-for rates for 2014. Now, I’m using that

terminology because there’s a slight nuance. For the


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1365

electric company, what that means is approving on a

permanent basis the existing interim rates for 2014.

For FEI what it means is approving the interim rates,

but they have to -- sorry. Approving the rates,

interim rates, as adjusted by the evidentiary update

of February 21st, 2014. So those adjustments -- you

can’t just simply approve the interim rates as they

are set today. They should be adjusted based on the

updated information that came in after that time. But

otherwise the applied-for rates are appropriate. And

that -- I won’t repeat why that is the case because I

think the submissions that have been filed today amply

deal with why that rate level was appropriate, and so

I won’t dwell on that.

2015 for both companies. Fortis would

envision that for 2015 there would be a revenue

requirements application put forward for a two-year

test period, as has been the practice, simply because

of the time and effort involved in preparing such an

application. It makes sense to have an application

for 2015 and 2016.


MR. GHIKAS: And due to the timing of preparing that

application, filing it and processing it, it is likely

that 2015 would be on interim rates for some time

before the final decision had been rendered in 2015.


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1366

Those are my submissions on that point.

And before I move to item 3, I’d just field -- if

there are any questions on that come to mind?

THE CHAIRPERSON: No, please go ahead, Mr. Ghikas.

MR. GHIKAS: Okay, so what I will turn to now is actually

hand the microphone to my colleague Ms. Herbst, and

she will speak to the third item on the Commission’s

agenda, and then I will be back for more.


SUBMISSIONS BY MS. HERBST:

MS. HERBST: Thank you, and good morning. I will be

dealing with, as Mr. Ghikas said, the third item on

the list and the Commission’s June 27th correspondence,

and will also take the opportunity while I am standing

to deal with the impact on FortisBC’s application of

the very recent changes that have been made to the DSM

regulation late last week.

So, turning first of all to item 3 on the

Commission’s list, and that had to do with deferral

accounts. And in particular, and just to recap, as

the Chair enunciated earlier, item 3 says that:

“In this application, FortisBC Inc is

seeking -- requesting approval for deferral

accounts for a number of its flow-through

items. These same deferral accounts were

approved for FEI in the previous PBR but


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1367

were not requested by FBC in its previous

PBR. Are these deferral accounts necessary?

What other options are available?”

So, turning to that, firstly, what I would like to do

is just isolate the accounts that we think are the

subject of Item 3.

And what we have done, in order to do so,

is compare the PBR plans that were initiated for

FortisBC Inc. by a decision in 2006 for the 2007

period onward. And that was in Order G-58-06. And

compare those to the FEI PBR plan which was initiated

by a decision in 2003 for the period 2004 onward, and

that was Order G-51-03.

And by our assessment in comparing those,

there are only four, at most, deferral accounts that

fall within the category of permission having been

requested and received by FEI and not FBC. And those

are the -- that FortisBC now seeks. And those are the

proposed tax variance account, the proposed property

tax variance account, the proposed insurance expense

variance account, and possibly -- and I will return to

why I say possibly in a moment -- the proposed

interest expense variance account.

And so, again stepping back to those four,

and our comparison. Each of those four was certainly

in the FEI-side PBR plan, under G-51-03, and that is


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1368

Appendix D9 to the FEI application. And in addition,

all four of those were also approved in the non-PBR

revenue requirements application that FEI made for

2012 and 2013. And just to make a note, that is at

pages 114 to 116 of the FEI decision for that period.

So, that is the FEI side.

For the FBC side, while for the most part,

FortisBC didn’t specifically request deferral

treatment for these items in its 2007 PBR plan, for

the most part also, the treatment that these items

received under that plan is quite close to what is

being sought now. And that is to the point that we

say that one of the accounts that is at issue in item

4, the interest expense deferral account, is actually

a reinstatement of something that in effect was in

place during the 2007 PBR plan.

So, breaking that down just a bit further,

and turning first to the interest expense variance

account, we say -- and I will give a couple of

references to the evidentiary record on this. We say

that this is essentially a restatement of what

happened during the PBR regime. And at Exhibit B-7,

which is FortisBC’s response to a Commission IR, IR

1.189.6, that said. And also in FortisBC’s response

in the same exhibit to BCUC IR 1.189.2, FortisBC said

this as well, that it had a similar interest expense


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1369

deferral account approved during its 2007-2011 PBR

agreement, which saw in excess of six million dollars

flowed back to customers.


MS. HERBST: We deal with this in item three just because

it's not entirely clear, when you're reading through

the actual Order that grounded the 2007 PBR plan. but

what that Order said or what the negotiated settlement

terms that were attached to the Order said is that

there was a term agreed to that positive or negative

variances in the gross annual interest expense and the

interest component of AFUDC will be treated as flow-

through expenses to customers in the same manner as in

2006.

And then the same Order dealt with a

negotiated settlement on the 2006 revenue requirements

and part of that -- part of the terms on that were

that, as to financing costs, FortisBC agreed and it

was generally agreed that there would be an interest

deferral account to capture the difference between the

actual 2006 interest costs and the forecast and to

amortize the difference fully in 2006 and that that

continued.

So certainly in practice we say that while

there may not have been a particularly specific

crystallized request for the 2007 plan, in practice


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1370

the treatment was very much as being sought now by

FortisBC.

Similarly, but not quite as close, was the

situation to do with the tax variance and property tax

variance in the 2007 plan. So in the 2007 plan that

FBC had there was a provision in the negotiated terms

for a Z factor treatment of those items. And the Z

factor treatment permitted recovery or refund of

extraordinary costs outside the steady-state

operations as determined in the PBR formula.

The Z factor circumstances included

directives of the BCUC or other competent regulatory

agencies or Acts of legislation or regulation of

government, and this wording was treated during the

2007 PBR term as encompassing tax and property tax

changes. So for example, in 2010, which by virtue of

an extension fell within the 2007 PBR plan, certain

corporate tax savings and income tax deductions were

treated as a flow-through adjustment to 2011 rates.

So again we say that while there wasn't a specific

crystallized request in the Order that underpinned the

2007 PBR plan, the treatment was quite similar in

terms of being a flow-through.

Now I note as well that the actual Z factor

provision in the negotiated settlement underneath the

2007 plan talked about the inclusion of these costs in


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1371

revenue requirements where possible or to the

capturing of material variances in a deferral account.

So there was at least an overt reference in that

respect to a deferral account for consideration and

disposition outside of the PBR formula as part of the

annual review. And I'll just give a couple of

references to the evidentiary record in this

proceeding on that.

THE CHAIRPERSON: Ms. Herbst?

MS. HERBST: Yes.

THE CHAIRPERSON: Sorry to interrupt. I just wonder if

we could just back up a little bit please, because

it's not too clear in my mind.

MS. HERBST: Yes, absolutely.

THE CHAIRPERSON: You're saying that there was agreement

that these items, insurance expense and so on, would

be given flow-through treatment, correct? When you

use that term, does that in your mind mean it involves

-- it necessarily involves a deferral account?

MS. HERBST: I don't think it would necessarily but I

think that in practice it did. There was a reference

within the terms of the negotiated settlement to the

possibility of a deferral account where needed and I

gather that as a practical matter that's how it was

approached.

And I should say insurance expense is the


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1372

one item that was not --

THE CHAIRPERSON: Sorry, interest expense, yes.

MS. HERBST: Exactly.

THE CHAIRPERSON: So when you say you gather -- are you

saying that FortisBC's interpretation of being

approved or having those expenses approved as flow-

through expenses, does FortisBC then interpret that as

an approval to establish a deferral account to flow

those expenses through? Is that what you're saying?

MS. HERBST: I'll check. I'm not sure that that would be

the case in all circumstances. I believe that was the

practice within the context of the 2007 plan.

THE CHAIRPERSON: Yes, please.

MS. HERBST: But if I may have a moment I can check that.

THE CHAIRPERSON: Sure, please do. Thank you.


MS. HERBST: Yes, Mr. Chair, and thank you for the

opportunity to consult. That was the mechanism that

was used where there was a variance that needed to be

flowed through a deferral account -- was used. And

I’m not sure that there would be another mechanism

that would be envisioned going forward if that

approval was given.

THE CHAIRPERSON: Thank you. And to your knowledge that

was the case for all five -- or all four of these

flow-through items?


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1373

MS. HERBST: The insurance expense variance account, I

think, is different. So I think in that case there

wasn’t similar treatment in the 2007 PBR plan. The

ones that I think are close was the interest expense.

THE CHAIRPERSON: Yes.

MS. HERBST: That was probably the closest of the

approvals in the 2007 plan, and relatively close but

not quite close -- not quite as close were the tax

variance account and the property tax variance

account. And the insurance expense is a bit of a

different situation.

THE CHAIRPERSON: Yes. Sorry if I’ve distracted you

here, but please continue.

MS. HERBST: No, not at all, and thank you, that was a

helpful question.

And I’ll just -- in terms of a couple of

references in the evidentiary record in this

proceeding to the past treatment of these items, in

Exhibit B-7 which is FortisBC’s response to the

Commission’s IR 1.183.1 and also in the same exhibit,

its response to the Commission’s IR 1.191.3, some of

this background is dealt with as well.

So I say -- so up to this point I’ve been

talking about the context or the premise of the

question. I say that the situation as between FEI and

FBC during their last PBR plans wasn’t that


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1374

dramatically different, and that there’s not really

that a dramatic departure in what FBC is seeking now

as compared to its last PBR plan.

But setting that aside and dealing

specifically with the first of the questions that’s in

item 3 and that’s whether these deferral accounts,

these four deferral accounts that we’ve identified,

are necessary. I say that they are. I say that they

are necessary in the sense of it being the internally

consistent and efficient way of ensuring that

ratepayers pay only for the costs that are actually

incurred, and that the potential for windfall gains or

losses on the part of either the utility or ratepayers

is avoided. And I’ll talk about each of these

elements a bit more in a moment. So that’s internal

consistency, efficiency and avoiding windfall gains or

losses.

But I say as well, and perhaps more

fundamentally, that necessity is too high a test in

terms of whether or not these deferral accounts should

be approved. I say that they are necessary but I say

that we don’t need to go that far in terms of what we

establish. And the reason that I say this is that the

deferral accounts are sought under Sections 59 to 61

of the Utilities Commission Act and the general

parameters for that are what is just and reasonable.


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1375

And if the Commission’s past decision on FBC is non-

PBR revenue requirements, in 2012 and 2013 is one

guide, I think what was said there is useful in terms

of encapsulating the approach to be taken. And there

the Commission said it was considering whether the

creation of certain deferral accounts represents a

reasonable attempt to manage the uncertainty and

unpredictability associated with accounts that are

largely uncontrollable in nature.

So I say that, really, as opposed to

necessity, the test is reasonableness and whether the

accounts that are brought forward are characterized by

that uncertainty and unpredictability that the

Commission mentioned. And just as a reference to

that, the 2012-2013 decision that involved FBC is

attachment 80.3 in Exhibit B-24 and it’s on page 115

that that principle is set out.

So I talked about -- going back to the

necessity threshold and necessity considerations --

that these deferral accounts are necessary because

they are the internally consistent and efficient way

to ensure that payments are made only for what’s

actually incurred and that there aren’t windfall gains

or losses. So in terms of internal consistency --

and when I speak of internal consistency I now mean as

between the gas and electric sides as part of the


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1376

greater Fortis entity.


MS. HERBST: So, notably in this regard, all four of the

deferral accounts -- so insurance expense, interest

expense, property tax, and tax -- were approved for

FEI as part of its 2012-2013 revenue requirements, and

bringing FortisBC into line with what was done on the

FEI side I say is something that has tangible

benefits. It's something that facilitates the

training of accounting staff on both sides of the

organization, or perhaps a single person to deal with

both sides of the organization, who knows, yes, this

is the treatment that these items receive.

And not only is there an internal

efficiency created but also a regulatory efficiency in

the sense that, going forward, the regulatory

treatment could be the same, and the same approach

could be taken in terms of both applications. But I

say even if Fortis on the gas side hadn't already

adopted this deferral approach, it would be a useful,

reasonable and necessary thing for FortisBC on the

electric side to do.

And here there’s another efficiency point

that I want to make as well as the windfall gain and

loss point. Now, in terms of the efficiency point, if

the matters that are at issue here -- so insurance


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1377

expense, interest, property tax, and tax -- are dealt

with simply as Z factors but without a deferral

account attached or potentially attached to them, what

would happen is that FortisBC would have to re-

approach the Commission going forward on specific

occasions where it felt that some sort of relief or

flow-through was required. And I say that as long as

the terms as they are in the application are defined

carefully in terms of what goes into the deferral

account, that’s an unnecessary effort. And that’s not

to say that there wouldn’t be transparency in what

happens to these deferral accounts, because the

balances could be considered each year as part of the

annual review process.

Now, I had talked about as well, of course,

the windfall gain and loss point, and I say that the

types of expenditures that are sought to be captured

within these deferral accounts are predominantly items

that are substantially or completely uncontrollable.

And so that’s very much within the parameters of how

deferral accounts are to be run, and what deferral

accounts are to be established for. They’re to be

established for items that are -- substantially are

completely uncontrollable in the circumstance, and

avoid the potential for windfall gains and losses that

might otherwise happen but where matters can’t be


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1378

properly forecast or accurately forecast necessarily

in advance. And the gain or the loss shouldn’t accrue

to either the utility or to customers. What should

happen is that the proper amounts, the actually

incurred amounts should be paid and the deferral

accounts would ensure that that happened.

So turning to each of the four deferral

accounts and how that fits in, the first one is the

insurance expense variance account, and so about that

I say this. Insurance expense can vary significantly

due to changes in economic factors that are outside

FortisBC's control, and FortisBC's submission at page

78 encapsulates this, the application does at page

263. The sort of factors that make the insurance

expense volatile include global market conditions for

insurance companies, both through investment returns

and loss history, the impact of large losses in the

marketplace, which can have a significant impact of up

to 10 to 100 percent and potentially more on rates,

increased insurer concern over and sensitivity to

catastrophic risk such as earthquake and forest fire

losses, and, as FortisBC says in its materials,

companies that are exposed to these risks, as FortisBC

certainly is, have continued uncertainty as to

premiums.

So when the Commission dealt with insurance


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1379

expense in 2012 and 2013, or for 2012 and 2013, when

it did so for FEI, it approved the insurance expense

variance account that FEI sought, noting the current

economic circumstances where there is considerable

uncertainty on a global scale. And as FortisBC's

materials say, that global market uncertainty remains.

When the Commission dealt with FortisBC's

request, also for 2012 and 2013 for an insurance

expense variance account, it denied the request. And

I say that the circumstances have both changed and

been clarified in respect of FortisBC since then.


MS. HERBST: So when dealing with FortisBC’s request for

2012-2013, the Commission noted that FortisBC had

designated certain insurance expenses being somewhat

controllable. And this earlier description that

FortisBC had put forward was based on the prospect of

achieving some economies of scale within the Fortis

group as a whole.

Now, those prospective economies of scale

have already been embedded into the forecast, and so

the variance over and above, or under that, would not

any longer be within that parameter. It would be

uncontrollable.

The other point that distinguishes

FortisBC’s current situation from 2012 and 2013, when


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1380

its request was denied, was that it is seeking a

narrower band for what the insurance expense variance

account would have folded into it.

Previously, in 2012 and 2013, it had sought

deferral treatment for first- and third-party claims

and asset valuations or appraisal fees, in addition to

insurance premiums. Now it is seeking that the

variance account only extend to insurance premiums.

So, it is along the lines of what FEI and FEI’s

account is comprised of.

So, the second deferral account is the tax

expense variance account, and again, we say that this

falls within the category of uncontrollable items.

FortisBC faces uncontrollable changes in the tax laws

and assessing practices, both federally and

provincially in terms of income tax, sales tax, and

other taxes that may be imposed.

Again, in 2012 and 2013 the treatment was

different here. The Commission approved FEI’s request

for a tax variance account, denied FortisBC’s, and I

say again that the circumstances have either changed

or have been clarified with respect to FortisBC since

then. And what FortisBC had done in terms of its

2012-2013 application was designate tax variance as

being primarily, not entirely, non-controllable. And

it did so based on the fact that if the completely


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1381

uncontrollable changes occurred in tax laws, the

company could potentially have some control over the

costs of compliance. But I think what didn’t come

through when it made its application last time is that

is a potentially only very minor element of the

potential overall costs, and otherwise the variance is

uncontrollable.

The third deferral account within item 3 is

the property tax variance account. And again, we say

this falls within the uncontrollable category. The

property taxes are driven primarily by legislation,

market values of properties, political programs, where

a municipal boundary happens to fall, and tax rates

that are imposed within a particular municipality, all

of which are outside FortisBC’s control.

This is again a situation where the

Commission approved FEI’s property tax variance

account for 2012 and 2013, and there is a bit of a

precedent though, also, for FortisBC having approval.

What FortisBC requested in 2012-2013 was a limited

deferral account related to a valuation review being

undertaken by B.C. Assessment at the time. It is now

simply expanding it to be commensurate with FEI’s.

And the fourth and last deferral account is

the interest expense variance account. And this is a

type of account that we say again falls within the


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1382

parameters of not being controllable. Interest

expense can vary due to global economic factors that

are -- and market conditions beyond the company’s

control.

And again, disparate treatment in 2012-

2013; FEI’s request for an interest expense variance

account was granted, FBC’s was denied. And I say

again that the parameters of the request for FBC has

changed, such as to make approval appropriate in 2012

and 2013 and applying for the deferral account.

FortisBC had designated interest expenses being

somewhat controllable, and why it did so at the time

was that it had some potential to influence the terms

of banking arrangements at the time of renewal. But,

unlike in the 2012-2013 application, FortisBC is no

longer requesting that variances on most financing

fees be included, and it is not requesting that short-

term debt volume variances be included. So, now it is

going to be parallel, or its request is parallel with

what FEI actually has.


MS. HERBST: And a recent example -- at least there’s one

recent example in the materials of FortisBC being

unable to influence interest rates generally, or

unable to have the ability to forecast in full what

happens with interest rates.


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1383

In 2013 a coupon rate increased as a result

in part of foreign investors not investing in Canadian

bonds. Again, very much outside the scope of what FBC

can control. The Commission in its decision in 2012-

2013 referred to the possibility of FortisBC making

best efforts to manage interest expense, but it’s not

been able to make best efforts to, and it can’t, to

control, you know, what foreign investors do, the

spread between bond yield and credit and so on.

Now, the third -- or sorry, the second

question in item 3 relates to whether there are

options to establishing the deferral accounts. I

talked a little bit before about one such option,

which would be simply treating them as Z factors

without an associated deferral account. And part of

FortisBC's materials, and I referred to Exhibit B-24,

its response to Commission IR 2.61.2, talks as well

about the fact that the deferral account treatment

lends itself to greater precision, clarity and

certainty.

And the second possible option, or a second

possible option that was raised in some of the

Commission IRs and I’ll just touch on, would be to

use, instead of a deferral account, an average for the

past five years to determine the costs that should be

recoverable during the PBR period. And FortisBC


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1384

addressed this in Exhibit B-24 in its response to IR

2, BCUC IR 2.54.3. The suggestion that there could be

a five-year average assumes that there is a simple

trend that can be used to forecast costs, and

disregards that many elements in these costs aren’t

predictable.

And so, for example, the capital markets

and economic conditions during 2014 to 2018 are likely

to be very different from 2009 after the global

economic circumstances that occurred in 2008 and so

on. If there’s an average use, the objective that

deferral accounts are intended to further wishes that

there be no windfall gains or losses and that only the

actual costs be paid for just wouldn’t be met. And

so, given all that, FortisBC says that the deferral

accounts it seeks should be approved.

And subject to questions on that, I’ll just

touch briefly on the DSM regulation if I could as

well, before sitting.

Sorry, Mr. Chair. And Mr. Bystrom -- I’ll

deal with the DSM regulation if I may from the

FortisBC Inc. perspective, and Mr. Bystrom has a few

points to make on the gas side perspective on this as

well.

So very recently -- sorry.

THE CHAIRPERSON: Sure. We have no questions. Please go


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1385

ahead, yes.

MS. HERBST: Thank you. So very recently, late last

week, the government released amendments to the DSM

regulation, and of course a chunk of both applications

on the electric side and the gas side relates to DSM.

So I just wanted to briefly address what might flow

from that or what we say flows from that, at least on

the electric side.

So there are two categories of amendments,

very broadly speaking, to the regulation. Some take

effect immediately and from our perspective those are

relatively limited, and so those include a more

detailed definition for low-income households and so

on. There’s a second category of amendments that

takes effect, starting on January 1st of 2015, which

are more significant from our perspective on the

electric side.

So in the application that FortisBC Inc.

filed, it sought approval for DSM expenditures for

2014 to 2018 in specified amounts for each of those

years. And much as the time categories that I alluded

to earlier are important, that’s how the impact

divides itself in terms of our application. So for

the amendments that take effect in 2014, so take

effect immediately, there is no effect, we say, on

FortisBC Inc.’s application. So for 2014 and the


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1386

request for 2014 for approval for 2014 DSM expenditure

schedules, that request from FortisBC Inc.’s

perspective stands and is unaltered. The submissions

that were made with respect to 2014 are still

pertinent. And from FortisBC Inc.’s perspective we

remain compliant with the new terms that take effect

now.


MS. HERBST: There is also -- because there is no change

to the proposed DSM schedule for 2014, there is also

no change for revenue requirements for 2014 and so in

that respect the application is intact.

The changes taking effect starting on

January 1st, 2015 are potentially more significant from

the electric side's perspective. They include a

change to the impact or the extent to which avoided

electricity cost is calculated with reference to the

long-run marginal cost of acquiring electricity

generated from clean or renewable resources in B.C.

And so while I believe the Ministry's interpretation

guide, which is pending on the regulation, still

hasn't been finalized, there is something for FortisBC

to explore and look at for the 2015 period going

forward.

And so while FortisBC continues to request

approval for the 2014 expenditure schedule, it is


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1387

going to be withdrawing its requests for approval for

the 2015, 2016, 2017 and 2018 DSM expenditure

schedules and it plans on filing correspondence to

that effect -- just to formalize that withdrawal in

the next couple of days. So the only effect on the

decision to be made here would be that, in effect, no

decision would be need to be made on the 2015-2018

expenditure schedule request.

In terms of how FortisBC is going to deal

with this going forward, it's working on quantifying

the impact of the regulatory changes on its DSM

portfolio and it thinks it will be able to accomplish

this fairly quickly. It intends to file a revised DSM

plan for 2015 and possibly for one or more future

years and likely that will be by the end of August of

2014. This is a bit of breaking news. When I spoke

with Mr. Miller earlier today we were thinking perhaps

by the end of July of this year, but FortisBC has

decided to leave a bit of a longer period for

consultation with interveners with the Ministry in

terms of how its new approach will take shape. And of

course the goal of all this is to ensure that the

revised plan will be compliant with the changes to the

regulation going forward from January 1st, 2015 onward.

The DSM expenditures don't affect the

structure of the PBR plan because the expenditures


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1388

aren't determined under the PBR formula and so again,

from that perspective the application is intact. But

there will be a withdrawal of the request for approval

on the electricity side of the 2015 to 2018

expenditure schedules and Mr. Bystrom will address the

gas side's perspective on the regulation.


MS. HERBST: Thank you.

SUBMISSIONS BY MR. BYSTROM:

MR. BYSTROM: Good morning, Mr. Chair, Commissioners.

Yeah, I just thought it would be helpful if I took the

time to explain, very briefly, the changes that are

relevant on the gas side, the changes to the DSM

regulation that are relevant to the gas side and why

there's no change to the EEC plan put forward by FEI.

And so there are two amendments to the DSM

regulation that are relevant to FEI's or the FEU's EEC

plan. The first is a change to the definition of low-

income programs. And that broadens the market for

FEI's proposed low-income programs. and the second

change is the removal of the 50 percent factor for the

zero emission energy alternative. That's a component

of the MTRC, modified total resource cost test. And

so that means for those programs that require the MTRC

to be cost-effective, they're now more cost-effective.

So both these changes are positive -- I can


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1389

put it that way -- for the EEC program. However there

is no changes proposed because there's a 33 percent

cap on programs that require the MTRC to be cost-

effective. And FEI's -- or the FEU's EEC plan is

already bumping up against that 33 percent cap. And

to see that I would just refer you to Exhibit B-43.

And in that exhibit there's an amendment to the FEU's

EEC plan and Exhibit 3 of the plan has that MTRC

percentage and it shows that we are right up against

the 33 percent cap. So there's no room to expand

those programs.


THE CHAIRPERSON: Okay.

MR. BYSTROM: And those are my submissions.

THE CHAIRPERSON: Thank you very much. Mr. Ghikas, I

assume you are going to -- you are now going to make

submissions on the panel IRs, is that correct?

MR. GHIKAS: I am, yes.

THE CHAIRPERSON: Do you have a rough estimate of how

long you will be?

MR. GHIKAS: I think I will be probably 10 minutes on

Fortis’s IRs.

THE CHAIRPERSON: Yes.

MR. GHIKAS: A little bit longer -- I think I will be a

half-hour speaking to Dr. Lowry’s.

THE CHAIRPERSON: I’d like to take a short break then,


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1390

please.

MR. GHIKAS: Thank you.

THE CHAIRPERSON: We’ll return at 10:20.


(PROCEEDINGS ADJOURNED AT 10:11 A.M.)

(PROCEEDINGS RESUMED AT 10:22 A.M.)

THE CHAIRPERSON: Please be seated. Please go ahead, Mr.

Ghikas, thank you.

SUBMISSIONS BY MR. GHIKAS:

MR. GHIKAS: Thank you. In terms of the submissions,

further submissions on FortisBC’s responses to IRs, I

will be brief, because I think the responses are

largely self-explanatory, but I did want to make

further comment on the second series of IRs.

And that is, the questions that were asking

about what happens if you apply the old formula and

the new formula, and so on. And what I would draw to

the Commission’s attention -- and again, Fortis is not

entirely sure where the question was coming from, but

what I would say is that what you see in those

responses is entirely expected, and what it does

highlight, first of all, is the importance of rebasing

after a PBR. And how significant, when you look at

the difference between the trajectory of the old

formula, extending beyond that -- how significant the

difference is between that trajectory and the rebased


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1391

amount does emphasize that, at some point, you do have

to rebase.

The second point is that is underscored by

that response is that you have to start with an

appropriate base. And if you were to look at the

formula extended out for the 2009, 2011 for O&M for

example for both companies, that would be too high.

And it would be too high to use as a base going

forward for a future PBR. The actuals were lower,

obviously, due to the savings, and the savings have

been explained. For capital, which applies to FEI

only, because FBC didn’t have a capital formula last

time, the formula amounts would be too low to use as a

base, simply based on the fact that -- the capital

requirements that occurred afterwards. And the base

that Fortis has put forward really takes into account

all of the changes that have occurred since the past

-- the conclusion of the past PBR, and that is really

the appropriate base to start with.

The third point is that when you compare

the spending envelope, if I can put it that way,

between what the old formula would give, and what the

new formula would give, the envelope that is created

by the new one is larger. And that in fact makes

perfect sense, because what you’ve done is rebased or

flowed entirely the benefits to customers from both


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1392

the prior PBR term, and those that have accrued since

the PBR term, to customers. They are no longer

available to the utility to seek out, and hence, there

has to be more dollars available than would otherwise

be the case under the older formula in order to

adequately provide service.


MR. GHIKAS: And to that point really it would be

illogical in my submission to extend the X factors

from the prior plan and apply them holus-bolus to the

current plan after, when you have re-based the savings

that came out of the prior plan and since that.

I will move now -- and anything further on

Fortis’s IRs I’ll address in reply, but I will move

now to Dr. Lowry’s responses to IRs. And I will spend

a little more time on this because I think some points

in his responses have made a few points clear and they

need to be addressed. And the first -- I’ll focus on

five points. The first one arises out of his response

in IR 1.3, and that’s the IR that asks him effectively

to explain why he moved from X factor ranges to

pinpoint values. And my point there is that the

explanation that he provides is avoiding stating the

obvious, which is simply that he made an error and

that he corrected the error after it was pointed out.

The second point that I’ll touch on is that


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1393

in his responses he has mischaracterized, in my

submission, Fortis’s proposal as a double-arm PBR when

it is in fact a building block plan and those two

things are different in the way that Dr. Lowry is

using that term “double-arm”.

The third point is that, although Dr.

Lowry’s evidence includes recommendations on separate

X factors, his response to an IR in the Panel IRs is

making it clear that the approach lacks the empirical

basis to be used and to be useful to the Commission in

practice, and I’ll point to that.

The fourth point is that the responses that

he has provided in terms of how the capital trackers

affect his recommendations are still premised, his

discussion is still premised on a proposal or on the

Alberta-type model and not -- and a tracker, and the

tracker that he’s addressing is based on what had been

the original Alberta tracker and doesn’t account for

the fact that Alberta has actually moved away from

that factor. And finally there is an inconsistency, I

submit, in the capital X factors that he has put

forward, and I want to highlight that.

So dealing with the first point, this is

the discussion in IR 1 -- about 1.3 in particular --

about why he moved from ranges to pinpoint references.

And if you look at his response to IR 1.3, he says


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1394

that in the second sentence, he removed the upper

bound of the recommended X factor ranges for single

arms, which were intended to address the presence of

broad capital cost trackers in the plans proposed by

Fortis due to the speculative nature -- character of

these adjustments. There is no established way to

make these adjustments. Fortis has made the

calculations more difficult by being vague about his

CAP-X intentions. Additionally, in response to

Commission data requests, Dr. Lowry provided X factors

for CAP-X instead of X factors for capital cost.

These are clearly more pertinent to the PBR plans

proposed by Fortis.

So what I want to zero in on, what really

is prompting the response in these oral submissions is

the fact that Dr. Lowry is seeking to deflect the

change that he made and attributing it to something

that Fortis has done.


MR. GHIKAS: And in my submission what is left unsaid in

that response is if -- is that the reason he made the

change is simply that he recognized after Dr. Overcast

had pointed out that simply taking 10 percent out

isn't a valid approach, that he needed to change his

approach. And that happens. Things need to change.

But the response in saying that Fortis has somehow


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1395

been making it difficult for him is, in my respectful

submission, not the real issue.

Dr. Lowry's initial recommendation said

nothing about his ranges being speculative. They said

nothing about there being no established formulaic

means of extracting -- quantifying a capital

exclusion, and they certainly said nothing about his

calculations being illustrative because Fortis has

somehow made it difficult to do this. His

recommendations only changed after Dr. Overcast had

pointed out in his rebuttal evidence, at page 31, that

you couldn't do that.

And there is a significant amount of

evidence on the record about the capital plans of both

companies. So, at the end of the day, what the

Commission has is simply evidence from Dr. Overcast

with respect to a judgment-based adjustment and it's

comprised as part of the difference between his TFP

values and the X factor recommendation of zero that he

put forward. That's the evidence that the Commission

has. And in my submission it would simply be easier

to just accept the change for what it is and move on.

But this -- it doesn't -- the change is not

attributable to something that Fortis has done.

THE CHAIRPERSON: Excuse me, Mr. Ghikas, but when you say

"accept the change for what it is" you're saying that


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1396

you agree with Dr. Lowry's change and we should accept

that? Is that --

MR. GHIKAS: Thank you for asking that. I just -- what I

was really saying was, it's an error and that we

should just call it what it was. He put it in, it was

a mistake and he corrected it. And so the range, we

should just set aside. And pinpoint.

THE CHAIRPERSON: And consider only the number that he --

MR. GHIKAS: Yes.


MR. GHIKAS: Yes, that's really it and that there is in

fact no evidence about any adjustment from Dr. Lowry

about how to quantify any adjustment from Dr. Lowry,

and that's simply the point.


MR. GHIKAS: Now the second point that I wanted to make

is that it appears that Dr. Overcast has

mischaracterized Fortis' plan -- sorry, Dr. Lowry has

mischaracterized Fortis' plan. And if you look at the

response to 2.2, you'll the question at 2.2 asks about

Fortis' proposed building-block approach and in

response he says, "The single arm would be applied to

all revenue that is not Y factored." Or as treated a

flow-through, in other words. "This would presumable

include all the downward trending costs of older plant

that is subject to separate rate-making treatment


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1397

under the Fortis double-arm proposals."

Now as Fortis understands it, the double-

arm that he's referring to is actually -- what he's

referring to is an approach that has one X factor for

capital and one X factor for O&M, and that is not what

is being proposed. What is being proposed is a

building block model which, although the costs are

looked at separately to allow more appropriate cost

drivers to be assessed from each side, to have a

single X factor applied to them. And that is indeed

having a single X factor or what Dr. Lowry refers to

as a single-arm approach is what has been done here

and what is done in all of the other plans that the

Commission has evidence before it on. And so this is

not a double-arm and so the Commission should just be

aware of the fact that he has misstated what the plan

is.


MR. GHIKAS: The third point is that, although Dr.

Lowry’s evidence includes recommendations for separate

X factors for capital and O&M, that his responses,

which I will take you to, really underscore that in

his view, that type of approach lacks the empirical

foundation to be useful in practice. And if you see

in the -- you’ll see in the preamble to IR 1, there is

a reference to Dr. Lowry’s view that the single-arm


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1398

approach has a more solid empirical foundation

provided that the capital cost tracker is redesigned

along more conventional lines. And the Commission’s

IRs go into that. Let me just find the -- 1.4, thank

you.

And so, in 1.4, the Commission is asking

about that. Now, I will leave aside the proviso, for

the moment, about provided the capital cost tracker is

redesigned along more conventional lines, and I will

deal with that in my next point, my next broad point.

But, leaving that aside, and the merits of that

proviso, what the statement is saying, and what he is

expanding upon in 1.4, is really that there is a more

solid empirical foundation to looking at an X factor

based on total factor productivity.

And the only -- what flows from that is

that the only issue that the Commission needs to

determine is to focus on the design of the capital

tracker. It doesn’t need to look at separate, less

empirically sound X factors for O&M and capital. What

it needs to do, as is done in every plan that is on

the record in this proceeding, have a single X factor,

and have some sort of mechanism to address capital

outside the formula. And provided the Commission

turns its analysis to that, there is no reason to even

entertain a separate X factor for O&M and capital, and


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1399

it renders the discussion effectively academic in the

current context.

And in fact, there are other reasons why we

should set that aside. The building-block approach is

what has been done previously here. And CEC --

although Dr. Lowry is explaining this, CEC has said in

paragraph 180 and paragraph 234 of its argument that

the single X factor approach should be used. So, when

you have that context, it really makes no sense to

consider -- to keep going down the road of exploring

this idea of having two X factors.

The fourth point, as I alluded to, would

deal with the questions related to how the capital

trackers affect his recommendations. And, in my point

is that, if in his discussion in IR 1.5, that asked

him about how the capital trackers or his proviso on

capital trackers affected his recommendation, what you

see is that the discussion he is providing is premised

on a plan such as that that exists in Alberta. And

even then, on the type of capital tracker that the AUC

has moved away from, recognizing that it is unworkable

in practice.


MR. GHIKAS: So let’s look at his response here and I’ll

explain what I mean as I go through. If you look at

his first bullet in the response, it says:


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1400

“A PBR with a single arm provides

considerable funding for CAP-X. In addition

to the funding provided by the escalation of

the revenue requirement …”

The escalation of the revenue requirement on capital,

okay?

“… the initial revenue requirement includes

an allowance for the cost of older plant

that is fixed even though this cost declines

due to depreciation. The recent surge in

CAP-X of Fortis during its PBR holiday will

place extra downward pressure on its capital

cost growth going forward in addition to

possibly reducing the need for further CAP-

X.”

Now, he defines -- he’s distinguishing

between the revenue requirement of CAP-X and of

capital and capital expenditures in his responses.

He’s defined them differently in 1.1. But what he’s

saying here is that, under the Alberta model, when

growth -- when plant, existing plant is depreciating,

that depreciation isn’t flowing to customers, it’s

creating an additional envelope of spending that’s

subject to the escalation under the formula. And so

if you have that type of model, if you spend a lot of

money before the PBR and have a lot of rate base


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1401

that’s going to be depreciating, the more you spend,

the bigger the envelope is going to be as that

declines. And what he’s referring to here in Fortis,

I assume it’s Fortis Electric in this case because

they’re the only ones that have had a surge of

expenditure prior to PBR. But that circumstance only

arises under an Alberta-type plan.

And if you look at the second bullet, the

same is true. It’s talking about in the last -- if

you look, the last sentence there:

“Full compensation for the occasional surge

without corresponding adjustments to the arm

when capital growth cost is slow will then

result in overcompensation.”

And that’s that same general point, and if you go on

the next paragraph talks about why capital trackers

are designed the way they are typically. But the last

paragraph is very interesting because he effectively

acknowledges that the Fortis plan is different. He

says: “In single-arm PBR plans the problem of inter-

temporal compensation,” that depreciation that’s

occurring,

“can also be solved by continuing to address

tracked CAP-X costs via a tracker in

subsequent PBR plans, rather than adding

them to the revenue requirement that is


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1402

subject to indexing. Should the Commission

be interested in a single-arm plan, this is

a good opportunity to implement this

sensible measure. This concept is similar

in spirit to what Fortis has proposed, since

under its plans the cost of all plant is

essentially accorded tracker treatment.”

And what he’s essentially saying here, Mr. Chairman,

is that he’s acknowledging the benefit of flowing

through the envelope associated with declining rate

base to customers. And that is what Fortis is

proposing. And so it’s important to understand the

context that this discussion isn’t directly related to

the plan that’s before you.

And finally, if you go up one paragraph, he

talks about the conventional cost trackers and is

suggesting that they are limited to the things that

they can apply, and that growth-related CAP-X is

rarely accorded tracker treatment because they are

partially self-financing and coincide with the

realization of outsized scale economies.

Now, if one looks at the AUC decision 2014-

235, which is the capital tracker decision, if you

look at that -- and he’s holding up the Alberta as

sort of conventional -- if you look at that, there is

no question that the AUC has moved away from what he’s


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1403

talking about.


MR. GHIKAS: And in particular, this topic was discussed

at transcript 4, page 636 and 637. And the -- I would

refer you to a list of growth-related approved

projects from that decision at paragraph 942, and that

discussion where the Commission agrees that Atcor’s

proposed capital tracker projects and programs are

either for asset replacement or refurbishment, and are

driven by external parties or are growth-related.

Accordingly, the Commission finds that these projects

satisfy the requirements of criterion 2.

So, if I would direct your attention, Mr.

Chairman, to 942, 943, and also in the context of

Fortis similar comments in paragraph 1002. And those

make it abundantly clear, that the Commission is, in

Alberta, approving growth-related projects, and is not

pursuing the type of model that he is addressing here.

Now, the final point that I wish to address

is that there is, in my submission, an internal

inconsistency in what you would intuitively expect in

the capital X factor numbers. So, if you see -- if

you look at IR 1.1, and look at his response carefully

here. So, what we have is in his explanation about

the change in his recommendations in 1.1 here, the

full paragraph at the very bottom of the page. So, he


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1404

is explaining here, that part of the change is due to

a change in how he is interpreting what the formula is

being applied to. What the base is that he is

applying it to. And he says,

“Please note that Dr. Lowry’s X factor

recommendations for capital in our direct

testimony …”

So that is the top line in the box in the table above.

“… pertain to a revenue requirement for

capital cost, e.g., depreciation and return

on rate base, not the revenue requirement

for capital spending.”

Now, what he is saying there is that he applied it

based on it being an Alberta model, not the model that

is being proposed. Because he is applying it to the

revenue requirement associated with all capital,

depreciation and return on rate base, not the revenue

requirement for spending that is actually occurring

now, which he is calling CAP-X. And then, he says

there is a change.

“Our X factor recommendations for capital in

the subsequent data request response pertain

to a revenue requirement for CAP-X, not

capital cost. Should the Commission still

have an interest in an X factor for capital

cost, Dr. Lowry recommends the lower bound


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1405

of the range presented in his direct

testimony.”

So, what he is saying is, if you are going

to use an Alberta approach, use the lower bounds of

the ranges presented in his direct testimony. These

were 1.18 for gas, and 0.81 for electric. And then he

expands on this slightly. It is just in the last

sentence of 1.3, when he is explaining the changes.

He says,

“Additionally, in response to Commission

data requests, Dr. Lowry provided X factors

for CAP-X, instead of X factors for capital

cost. These are clearly more pertinent to

the PBR plans proposed by Fortis.”

Now, here is the rub here. And this is why I say it

is counterintuitive. If you go back to 1.1, and you

say, should the Commission -- where he says, should

the Commission still have an interest in an x-factor

for capital cost, that I attribute to the Alberta

approach which he initially used, Dr. Lowry recommends

the lower bound of the ranges presented in his direct

testimony. 1.18 for gas, and 0.81 for electric. Now,

both of those values -- 1.18 if you look at the table

above, 1.18, and 0.81 -- those are lower than his

revised capital numbers.



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1406

MR. GHIKAS: And that he prepared on the premise that

this is -- on the premise that Fortis is actually

proposing. And intuitively one would expect, in my

submission, that if you're going to do an X factor

based on the spending envelope where all of the money

is flowing to customers and not creating a large

envelope of spending for the utility, which is what

we're proposing here, that the X factor would be

higher.

So let me say that again, is under an

Alberta approach where the utility is getting the

benefit of depreciating plant, one would expect the

challenge imposed by the X factor to be higher than

the challenge imposed by one where the utility is not

getting the benefit of the declining rate base.

And so if we accept Dr. Lowry's statement

that under an Alberta model 1.18 and 0.81 would be

appropriate, but that would suggest that under this

model the capital X factor has to be lower, in my

submission.

THE CHAIRPERSON: Mr. Ghikas?

MR. GHIKAS: Yes.

THE CHAIRPERSON: I have a question, please.

MR. GHIKAS: Yes.

THE CHAIRPERSON: This discussion concerning the last

paragraph of 1.1, is it your understanding that for


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1407

example when the first -- when it opens up by saying

"Please note that Dr. Lowry's X factor recommendation

for capital …" Is it your understanding that that

refers to a double-arm model?

MR. GHIKAS: I was interpreting that as referring to the

column capital. So that would be a double-arm model,

yes.

THE CHAIRPERSON: And it was your earlier submission that

you don't feel that that applies in any event, is that

correct?

MR. GHIKAS: That is absolutely correct, yes.


MR. GHIKAS: Absolutely correct. So -- but if the

Commission is going to be looking at those, it's

important that the context here is understood.

THE CHAIRPERSON: Okay. Understood. I guess my question

would be does any of your -- the argument that you

just presented concerning this issue, does any of that

apply to the single-arm number or is it -- or are you

focused at this point only on the double-arm number?

MR. GHIKAS: I am focused only on the capital double-arm

number at the current point because I can't say, based

on what is here --

THE CHAIRPERSON: Right, okay.

MR. GHIKAS: -- anything about the single-arm approach.

THE CHAIRPERSON: Sure, fair enough.


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1408

MR. GHIKAS: Just that my comments on the inconsistency

are only pointed out based on what is explicitly on

the page, and so that confines to capital.

THE CHAIRPERSON: I appreciate that, thank you.

MR. GHIKAS: Thank you. So ultimately those are my

submissions and -- on this point but effectively the

evidence that he has put forward, Dr. Lowry's put

forward in these responses, asks as many questions as

it does answer them, in my respectful submission. And

the companies would urge the Commission to consider

the points that I've just made in applying its overall

weight to the evidence given to Dr. Lowry.

That concludes my submissions on that

point. I will say one thing before my friend Mr.

Weafer gets up, and it relates to the procedural

matter that he alluded to about his feedback from Dr.

Lowry and how that comes before the Commission.

Just as a general statement, in my

submission there would be no difference between Dr.

Lowry speaking to the Commission directly and words

attributed to Dr. Lowry being transmitted to you via a

third party as argument. There is simply -- the

problem -- and I appreciate my friend's -- and I've

told him this, but I appreciate his consideration in

suggesting that what Dr. Lowry was going to say he's

segregated so we can deal with it but in fact, in my


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1409

submission it's the segregation that's the problem.

It's -- because this is argument and not evidence,

stuff that Dr. Lowry says, whether it's in an e-mail

to Mr. Weafer and attributed to Dr. Lowry or Dr. Lowry

speaking directly to you, the problem is that it's

being fed to the Commission as being something that

Dr. Lowry is saying rather than something that Mr.

Weafer is saying as counsel.

And so in my submission it would certainly

be expected that Mr. Weafer's submissions would be

informed by consultation with experts and to the

extent that Mr. Weafer -- and so Dr. Lowry's evidence

is in the record and it's in his responses.


MR. GHIKAS: And to the extent that Mr. Weafer speaks to

those responses, he should be speaking to them, in my

submission, as if they are his own words about those

submissions, and not attributing it to an expert.

Because the concern is that as soon as it is

identified as an expert, the only reason you would be

doing that, segregating it out and saying, “And this

is now from Dr. Lowry and not from Mr. Weafer,” is

because you would be urging the Commission to give

weight to it. That’s the underlying -- whether it’s

for the convenience or however you want to

characterize it, the difficulty is that there is some


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1410

suggestion that this is coming from an expert now, and

you should give more weight to it. And in my

submission the time for doing that is done.

And so when the submissions come before you

today they should be spoken as words from counsel

based on what is on the record. And those are my

submissions on that point.

THE CHAIRPERSON: Thank you, Mr. Ghikas. Mr. Weafer, do

you need any further time to prepare? You’re fine?

Okay. And Mr. Weafer, are you comfortable with what

Mr. Ghikas has just --

SUBMISSIONS BY MR. WEAFER:

MR. WEAFER: I would address that, Mr. Chairman. I will

address Mr. Ghikas’s comments. Maybe let’s just start

with that at a high level.


MR. WEAFER: The objective of these proceedings is to

ensure that the Panel has the best information that it

can have about the evidence on the record. The Panel

has asked some Information Requests of Dr. Lowry that

he’s responded to, and I can reply to questions you

have as best I can in terms of that expert testimony.

But if it’s beyond my level of expertise, I would

reserve the right to consult with Dr. Lowry and be

able to make sure that the Panel is satisfied and

understands the evidence correctly. And I think


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1411

that’s fair and I don’t think Mr. Ghikas would have

issue with that.

MR. GHIKAS: I do. So if you’re concluded I’ll stand up

and --

MR. WEAFER: The Commission controls its own procedure.

The Commission needs to be satisfied that it is

comfortable that it understands the evidence that is

before it. The Commission asked a series of written

Information Requests ten days ago. If it needs

further information that Dr. Lowry can assist with,

that can be done by another set of Information

Requests or it can be done efficiently in this

process.

The company has taken issue with extensions

to the term of this process because it wants to get a

decision. We’re empathetic to that. All we’re trying

to do here is make sure the Commission can move to

making a decision in a timely manner. So when you’re

looking at your process to ensure we can get through

this proceeding quickly, we’d say that that is a fair

and reasonable thing to do.

Mr. Ghikas, if he has a concern with

anything that’s stated as not being evidence that’s on

the record, can object to that if it’s a reaffirmation

of what Dr. Lowry has said. We’re not talking about

putting in additional new evidence from Dr. Lowry but


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1412

rather confirming that the Commission has a correct

and accurate portrayal of his evidence, and/or Dr.

Overcast’s evidence which Mr. Ghikas has relied on in

terms of his response to Dr. Lowry’s Information

Requests.

So I’ll sit down if Mr. Ghikas has further

comment.

THE CHAIRPERSON: Please go ahead.

SUBMISSIONS BY MR. GHIKAS:

MR. GHIKAS: Thank you, Mr. Chairman. There is no issue

with the concept that the Commission should have a

solid evidentiary record before it when it makes a

decision. But that record has to be taken by the

Commission with regard to the rules of procedural

fairness. And fundamentally, if the Commission has

closed the hearing and it -- at that point, the only

references that should be made are to evidence that’s

on the record. Now, to the extent that my friend is

pointing out existing evidence from Dr. Lowry, he can

do that by saying: “I, counsel for CEC, are directing

you, Commission, to evidence that Dr. Lowry has said

in response to your question or in response to

anything that needs to be clarified.” To the extent

that that cannot be done, there should be no further

explanation that is attributed to an expert.



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1413

MR. GHIKAS: We are here today, and without Dr. Overcast,

because this is oral argument, and there is a point in

which the Commission is entitled, and should, close

the hearing. And so it is really a matter of -- if my

friend is going to be referring to evidence, he should

be taking ownership of it, and not attributing it to

Dr. Lowry pointing it out to him. And that is really

the fundamental point.

THE CHAIRPERSON: Mr. Weafer?

MR. WEAFER: I think we should proceed. If Mr. Ghikas

has any -- unless other counsel have comments, Mr.

Ghikas can object to anything I say.

THE CHAIRPERSON: It looks like Mr. Miller has a comment.

MR. MILLER: So, Mr. Chair, I think we are at the point

where both sides have laid out their position, so as

Mr. Weafer suggests, we let it play and see where we

go. And if Mr. Weafer crosses a line, I believe Mr.

Ghikas will probably beat me to my feet. So.

THE CHAIRPERSON: Very well. Please begin, Mr. Weafer.

SUBMISSIONS BY MR. WEAFER:

MR. WEAFER: Mr. Chairman, I will start with the -- I

will deal with the IRs at the end of my submissions,

comments on the IRs, and deal firstly with the

response to your Exhibit A-44, and A-38, and the

questions put to participants in the proceeding. And

I’d like to preface the direct responses with a moment


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1414

of context.

So, the CEC is a ratepayer group which

seeks to promote fair rates and reliable safe and

secure energy supply, for those paying the cost of

service and the rewards to the utility. The CEC filed

written submissions which convey the strongly-held

view that the PBR proposal filed by the company is not

aligned with ratepayer interests. The CEC takes

exception to the utility’s extremely aggressive

response in its reply submissions, and in particular

its characterization of the CEC as being unprincipled

in its opposition to the proposal. The CEC has been

intervening in BCUC processes for over 10 years and,

on many occasions, has supported the applications of

FortisBC and FEI. The deep concerns with the PBR are

shared by all ratepayer groups, and many endorse the

submissions of the CEC.

The CEC submits that the Commission should

give significant rate to the position of the

ratepayers who are funding this proposal and funding

the utility. In the CEC’s submissions, they

identified 178 examples of where they saw a

misalignment between ratepayer and company interests.

The company dismissed those as hyperbole, and then

chose to respond to about 103 of those items, clearly

identifying that there was something to respond to.


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1415

The response was to ratepayers’ submissions was

extremely aggressive, and shows no intent to

acknowledge, much less resolve, the customer concerns

with this PBR proposal.

With that said, we’ll deal directly with

the Commission’s submissions -- the Commission’s

questions. Question 1(a), what process do the parties

recommend for transition to the next phase of PBR, a

rebasing process? As noted, the CEC is deeply

concerned with the potential impact of the PBR

proposal, and equally concerned with how the next

phase of PBR will be implemented. It is the

anticipation of the CEC that if this PBR is approved,

the concerns which have been highlighted by the CEC

will be borne out.

The CEC does not agree with the premise

that it is necessary for a transition to the next

phase of PBR, that by this the Commission means either

rebasing into a period of cost of service regulation,

or rebasing into an extension of the sort of PBR

process contained in the utilities’ application. In

terms of a transition to PBR, the CEC submits that an

improved and ongoing PBR could serve to mitigate

customer concerns. And therefore, the CEC recommends

that the Commission immediately initiate a BCUC-

supervised process to capitalize on the existing


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1416

evidentiary base, and develop a PBR process that is

more aligned with customer interests.

The CEC recommends that such a process

would include the following: a Commission supervision

of the process, a joint customer Fortis design of an

ongoing PBR. Submissions permitted from all parties

for key design principles, and a Commission-defined

context to create convergence, including utility

reward for demonstrated improved performance,

accountability performance and cost-effectiveness,

alignment of customer and shareholder interest, as

defined by customers and the utilities.


MR. WEAFER: The CEC would take this process -- see this

process taking approximately one year, with --

resulting in an implementation plan that could result

in a longer-term PBR or a PBR term the length the

company is proposing.

The CEC submits that that process can

inform and form the basis of an ongoing PBR that

rewards the utility for achieving genuine efficiencies

and cost-effectiveness for the customer's benefit.

That's my submission on question 1(a) of your

questions.

Turning to 1(b), what should be the timing

of the rebasing filing? The CEC is concerned with


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1417

issues arising as a result of alternative PBR with

cost of service regulation. The CEC submits that

significant potential for embedding error as well as

many opportunities for manipulation are engendered by

this format as well as added expense. As a result of

alternating between cost of service regulation and

PBR, the utility's long-term rewards are maximized by

over-forecasting and overspending in the cost of

service period and then under-spending the formula

generated allowances in the PBR period rather than

through consistent development of ongoing and

sustained efficiencies.

Spending under cost of service prior to the

PBR period affords the double value of an inflated

base for formulaic increases plus the equivalent of

advancing expenditures to enable reduced spending

during PBR. Spending post-PBR under cost of service

enables the utility to make up deferrals with

substantial benefit to the utility shareholder.

The CEC submits that improved ongoing

performance-based regulation that provides for

continuous accountability while offering financial

opportunity to the shareholder could alleviate the

overriding problem of rewarding variation and spending

and focus the reward on achieving genuine

efficiencies.


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1418

Again, the CEC recommends the Commission go

directly to requesting the parties to develop a

revised and ongoing PBR and then implementing it as

soon as practicable.

In the event that rebasing is undertaken,

assuming the utility's proposed PBR is implemented,

the CEC submits that the revenue requirement

application and rebasing filing should be undertaken

January 1st of the final year of the approved PBR.

This would occur in January, 2016, if a three-year

term is approved or January, 2018 if a five-year term

is approved. The CEC remains concerned with a

proposed efficiency carry-over mechanism which it

considers to be fundamentally flawed, and this concern

would be eliminated at an ongoing PBR.

That's the end of my comments on question

1(b). On question 1(c), what items should be reviewed

in the proceeding to consider the rebasing

application? The CEC submits that all regulatory

accounts of the company should be maintained so that

they can be reviewed and tracked against the prior PBR

as well as the period leading into the PBR. Absent

historical financial evidence, it becomes impossible

to measure the failures and/or benefits, if any, of a

PBR proposal.

The CEC submits that the current


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1419

determination of success does not evaluate

efficiencies achieved but is instead defined by

rewards achieved by the utility. This is not an

appropriate measure.

The CEC submits that a full analysis of

efficiencies gained during the PBR must be undertaken

to assess the effectiveness of the PBR to assess the

state of the utility and to determine if there have

been inappropriate levels of spending and to establish

its spending needs for the future.

That's the response to question 1(c).

Question 1(d) -- any other process, suggestions or

issues parties want to raise with regard to an ongoing

PBR regime? As we've highlighted throughout this

process, the CEC believes that the company has not

satisfactorily aligned ratepayer interest with that of

the shareholder. The aggressive position taken by the

utility and its unwillingness to have further

discussion on the PBR model is of significant concern

to the CEC.

The unwillingness to seek to improve upon

this flawed application is problematic and the CEC

requests that the Commission direct the company to

meet with stakeholder groups to develop a mutually

acceptable model for an ongoing PBR that is better

aligned with customer interests.


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1420


MR. WEAFER: With respect to your question 2, what

process is recommended for setting rates for 2014 and

2015 if performance-based ratemaking is turned down?

The CEC recommends that the Commission approve interim

rates until a revised PBR is developed to the mutual

satisfaction of ratepayers and the utility for ongoing

implementation. The CEC submits that this should not

require more than a one-year duration. The CEC

recommends that the revised PBR resolve the wide

difference in customer and utility interests and

provide for measurement of efficiencies, and

justification of rewards as discussed in response to

the questions above.

Now, we recognize that utilizing interims

rates for 2014 -- we recognize that there hasn’t been

a full review of the filing, but we agree with the

company that there is a sufficient record in this

proceeding to set rates for 2014 with some confidence.

What we’re saying is that we’re prepared to take a

certain amount of risk and not necessarily having as

full a review on the 2014 rates, with a view to truly

establishing a mutually acceptable between ratepayers

and the company PBR model that could sustain for the

long term.

Those are my responses to question 2. In


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1421

terms of question 3 we have some good news for the

company. This is the deferral account request by FBC.

These deferral accounts were approved for FEI in the

previous PBR but were not requested by FBC in its

previous PBR. Are these deferral accounts necessary?

What other options were available?

The CEC submits that the deferral accounts

requested by FBC represent a shift in risk from the

utility to the ratepayer which was denied by the

utilities in their reply submission. FBC was able to

work successfully in the prior PBR period without use

of deferral accounts and still generally managed to

achieve in excess of its approved rate of return in

equity through the PBR model while still bearing the

risks related to the accounts.

Nevertheless the CEC does not believe that

there was a significant benefit to be made by refusing

deferral account treatment for these items,

particularly because these accounts are available to

FEI. The CEC believes there is some value in

consistency. The CEC recommends the deferral account

treatment be approved but be accompanied by tighter

review of the actions undertaken by the company to

mitigate customer risk. The CEC submits that ensuring

the company undertakes to manage these accounts as

well as possible to the benefit of the customer will


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1422

improve the alignment between customer and the utility

interests. Thank you.

Those are my submissions on the questions.

I’m going to move to the discussion on the Information

Requests.


MR. WEAFER: Dealing firstly with Mr. Ghikas’s comments

on Dr. Lowry’s IR responses, the CEC submits that

there was no error in any calculation on the concern

of the capital tracker adjustments made by Dr. Lowry

in his Information Request responses or his evidence

in this proceeding. He first removed -- contrary to

the statement of Mr. Ghikas, Dr. Lowry first removed

the X factor adjustments for capital trackers in

January 30th responding to BCUC Information Request

1.22, long before Dr. Overcast -- excuse me. Dr.

Lowry identified the issue and dealt with it prior to

any rebuttal evidence being filed by the company. He

wasn’t blaming Fortis for the entirety of the problem.

CEC does acknowledge the capital tracker

issue is premised on the Alberta total revenue

approach and simply in this proceeding will seek to

work to give information and value to this Commission

on the use of that approach as an expert.


MR. WEAFER: The CEC submits, consistent with Dr. Lowry’s


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1423

evidence, that there is a multiple-arm approach being

put forward by Fortis. There are two approaches to

capital, and an approach to RNM, O&M, which Dr. Lowry

identifies as a multi-arm approach, and we think

correctly so.

Dealing specifically with the Fortis IR

responses to the Commission’s Information Requests,

the CEC takes issue with the calculations put forward

by the company, and submits that Fortis has

exaggerated any under-compensation for CAP-X by

somewhere between 85 and 90 percent, and that it

computes by comparing its CAP-X forecast to the

revenue generated by the index.

The issue in each year of the PBR plan is

the accumulating annual cost of the CAP-X, and not the

total CAP-X. Further, any underfunding will last for

only a few years before the remaining un-depreciated

value of assets resulting from the CAP-X is built into

rates. Any underfunding would be especially small in

the later years of the PBR plan.

There are other areas that the CEC takes

issues with the Fortis calculations, and find they are

flawed or controversial in a number of respects. For

both FBC and FEI, the hypothetical revenues generated

by the “I minus X” are calculated using the x-factors

Dr. Lowry designed for a total revenue cap, rather


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1424

that the recommendations for two-part revenue caps.

Further, Fortis, in their calculations,

uses X factors that were chosen, calculated assuming

that 10 percent of CAP-X is recovered via trackers.

These X factors were not part of Dr. Lowry’s evidence,

and they were on the high point of the range proposed

by the CEC in its final submission.

The final X factors recommended by Dr.

Lowry for total revenue caps were 1.16 percent for

FEI, and 1.13 percent for FBC. as discussed in CEC’s

response to BCUC IR 2.4.2.

In response to question 2 of the company --

or, sorry, page 2 of the response to the Panel,

Fortis, in its calculation, uses the 2008 to 2012

average annual growth grate, AAGR in the B.C. GDP-IPI

FDD, even though a forecast of same was available as

of May, 2014. The board forecast in the AAGR over the

five years of the PBR plan of 1.54 percent, not the

1.47 percent used by Fortis. The use of the

historical growth rate in the B.C. GDP-IPI FDD is

especially ill-considered in the fact of FEI’s high

construction cost scenario. It is hard to imagine

that the B.C. GDP-IPI FDD would not rise faster in an

environment of higher construction costs.

Another point to make here, I think, Mr.

Chair, members of the panel, is the selection of --


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1425

the CEC took a great deal of criticism in its

submission for looking at what occurred in prior

periods, in terms of coming up with what we thought

were reasonable numbers, in looking into what we

should expect from the company. And we were

criticized for going outside of the test year of 2013,

and not using forecasts. Here is an example where it

suits the company where they use a four-year look-

back, as opposed to an available forecast, to the

detriment of ratepayers.


MR. WEAFER: Another concern with the calculations of

Fortis is that Fortis reports cumulative unfunded

expenditures rather than unfunded expenditures as a

percentage of cost, which were a better gauge of

reasonableness. Furthermore, the Fortis PBR plan

affords dollar-for-dollar recovery of the cost of

older plant and many O&M expenses. If percentages

unrecovered were to factor into these full recoveries,

they would be materially diminished.

Those are my submissions on the IR

responses, Mr. Chairman. That completes my

submissions.

THE CHAIRPERSON: Thank you, Mr. Weafer. Mr. Andrews?

SUBMISSIONS BY MR. ANDREWS:

MR. ANDREWS: Thank you, Mr. Chairman, members of the


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1426

Commission Panel.

Regarding the first topic and the PBR

process and what process may follow an improved PBR

period, my first and main comment really here is to

confirm that the DSM expenditure schedules are not

connected in this discussion with the follow-up to an

approved PBR process; that is, that we should be clear

that there are -- although the filings came together,

there are two DSM expenditure schedules, one for each

of the utilities, and their length of time is defined

on their own terms and so the issues about extending

the PBR period or rebasing going to cost of service,

whatever, do not apply, in my submission, to the DSM

expenditure periods.

In terms of the substance of the request,

my submission is that after the mid-period review or

during the mid-period review is the time to consider

whether the PBR process is working in a way that can

-- that is satisfactory or can be made satisfactory

with changes as compared to a conclusion that there

are serious fundamental problems. And that at that

point the decision should be made by the various

parties about their approaches to what should happen

to follow up the PBR period.

And as Mr. Ghikas has pointed out, it would

be at the option of the company to make an application


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1427

at that point, or there may be some agreement, but in

overall my submission is that that is the time, rather

than now, to address the transition between the end of

an approved initial PBR period and the continuation of

another PBR period whether by rebasing cost of service

or extension. And so I’ll leave that as my

submissions on the first point.

On point number 2, the process in the event

that the PBR is turned down, my clients would be

content with the proposal, as I understood it from the

utilities, that if the PBR application is turned down

they would do a cost of service application for a 2015

to 2016 period and they’ve made proposals regarding

the rates, finalization of rates for 2014 that I won’t

make any submissions on specifically.


MR. ANDREWS: Regarding the FortisBC Electric deferral

accounts, my clients don't oppose FortisBC’s request

for those deferral accounts for the reasons that Ms.

Herbst set out.

I won't make submissions regarding the

responses by Dr. Overcast and Dr. Lowry to the panel's

Information Request. I'll turn to the submissions

made concerning the effect of the amendment to the DSM

regulation. In terms of Fortis Electric, my first

comment is that the BCSEA and the Sierra Club BC


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1428

commend the amendment of the regulation and commend

FortisBC for re-examining its DSM expenditure schedule

for 2015 to 2018 on a going-forward basis. My clients

expect to see substantial restoration of DSM spending

by FortisBC Electric and substantial energy savings as

a result of re-examining based on the amendment to the

regulation.

And my clients would also commend FortisBC

Electric for indicating that they would consult with

stakeholders and staff prior to finalizing a revised

application for an expenditure schedule for 2015 to

2018 by the end of August. So the extra time -- extra

few weeks that it takes to have stakeholders involved

may be very useful and there are a lot of details and

important aspects that would help for all parties to

at least understand each other's perspectives on

before that filing is made.

Regarding the Fortis Gas DSM response to

the DSM regulation amendment, the main impact, in my

submission, is through the broadening of the

definition of low-income programs. It's my client's

understanding that Fortis Gas has had difficulty

getting robust participation in the low-income

programs. The effect of these amendments should be to

make it easier for the utility to get participation in

these programs and that would allow higher spending


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1429

and higher savings as well. But particularly it would

allow higher spending within the expenditure schedule

that's been requested and so for that reason my

clients are not at this point clamouring for Fortis

Gas to revise its DSM expenditure schedule.

They take comfort in Fortis' conformation

that, in the event that it sees opportunities for

expanded energy savings that require spending above

what has been approved in their requested expenditure

schedule, they would make a stand-alone application to

the Utilities Commission for that purpose.

Subject to any questions, those are my

submissions.

THE CHAIRPERSON: Thank you, Mr. Andrews. No questions,

thanks. Ms. Braithwaite?

SUBMISSIONS BY MS. BRAITHWAITE:

MS. BRAITHWAITE: Thank you, Commissioners. With respect

to the first question, what process the parties

recommend for transition to the next phase of PBR, we

say that there is four options for moving forward

then. One option is to undertake a cost of service

analysis and set rates for a test period based on

that; to undertake a cost of service analysis and use

the rates determined to set the going-in rates for a

new PBR; to simply roll over the existing PBR with

whatever the existing PBR is at that time with


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1430

whatever tweaks are found to be necessary to the X

factor, the I-factor or the other formula factors as

needed.


MS. BRAITHWAITE: And the fourth option is the one

proposed this morning by the CEC of going straight

into a jointly-managed process now, and with the

possibility that that will carry on -- whatever is

decided upon during that process would carry on past

the end of 2018. We agree with the submissions made

by Mr. Andrews that the first -- issues with respect

to the first three of those proposals are probably

premature. We don’t know yet what the PBR that is

approved, if any is approved, will look like, or what

issues will arise with that and so it becomes

difficult for us to take a position on what we would

like to see happen at the end of that PBR period. We

do submit that tweaking a PBR formula, if a formula is

approved, at the end of 2018, without a cost of

service type rebasing process would deny the customers

some of the benefits of the PBR, assuming there are

benefits.

With respect to the second question, “What

should be the timing of the rebasing?”, we submit that

sometime between after the midterm review, and a

significant period of time before the end of the


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1431

process would be an appropriate time to look at that.

With respect to question 1(c), “What items

should be reviewed in the proceeding to consider the

rebasing application?”, in our view, this question is

also premature. Any list of issues developed at the

start of the PBR can be only suggestive and not

conclusive of the issues to be addressed. It is

impossible to say at this point what issues will arise

during the PBR.

With respect to question 1(d), “Other

process suggestions”, we note simply that rates become

increasingly disconnected from costs over time, so

there does need to be some kind of process, or

periodic process for realigning costs and rates. We

are particularly concerned, however, that costs are

not deferred during the PBR process, and then added at

the end of the PBR process when we go back into a cost

of service application, if the cost of service is

reinstated. And also that sustainable savings

achieved under any PBR are actually incorporated into

rates.

With respect to question 2, “What process

is recommended for setting rates for 2014 and 2015 if

PBR is turned down?”, the BCOAPO expert witness, Russ

Bell, was asked this question in BCUC IR 1.1. In

response -- his response to that question was -- Mr.


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1432

Bell suggested that the BCUC could approve a shorter

term building block approach, such as for a one- or

possibly two-year period, which would allow the

utilities to file a new revenue requirements

application. Mr. Bell did oppose approving the PBR as

filed, even for a single year, but recommended a one-

year PBR as proposed, modified by the following

recommendations.

He objected to the inclusion of the growth

factor in the O&M formula. He said -- his evidence

was that that was not supported by the history of

costs for either FBC or FEI. He said the history of

FBC capital also did not support the inclusion of a

growth factor for the FBC capital, and consequently he

recommended that that be removed from the formula. He

indicated that, in his view, the ECM component was

inconsistent with a plan where customers were already

paying for the costs of investment in the rates that

they were paying, and so he recommended that the ECM

be removed from the formula, and BCOAPO supports the

use of the X factor as recommended by Dr. Lowry. So,

a potential one-year PBR as proposed, but with those

modifications.

Mr. Bell also indicated that a two-year PBR

process to allow the utilities time to file a new

revenue requirement application may be appropriate.


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1433

However, BCOAPO submits that a one-year approval is

more appropriate, because it should allow the utility

sufficient time to re-file, while not unduly extending

the PBR. Alternatively a two-year timeframe could be

implemented to allow the utilities and interveners

time to workshop a new PBR regime, or a new PBR

mechanism.

With respect to question 3, we submit that

deferral accounts generally have the effect of

transferring risk from shareholders to ratepayers.

And if the shareholder continues to bear risks, they

are better incented to find ways to mitigate those

risks or to offset their uncontrollable costs with

efficiencies in other areas.


MS. BRAITHWAITE: In our view it's not appropriate to

implement changes to deferral account regimes right at

the start of a PBR process because that's shifting the

risk from historical right at a time when we're trying

to tie improvements and efficiency to profits for the

company.

We heard this morning that that doesn't

really apply to three of the proposed four deferral

accounts that were addressed because they actually

have already been subject to deferral account

treatment but it sounds like it still applies to the


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1434

insurance deferral account.

And those are all of my submissions.

THE CHAIRPERSON: Thanks, Ms. Braithwaite.

MS. BRAITHWAITE: Thank you.

THE CHAIRPERSON: No questions. Okay. Mr. Weisberg?

SUBMISSIONS BY MR. WEISBERG:

MR. WEISBERG: Mr. Chairman, Commissioners. I'll begin

with some very brief comments regarding some passages

within the -- specifically the Fortis responses to the

panel's IR number 1, having to do only with the

additional, and I think useful, context regarding the

efficiencies that should underpin a PBR plan.

The reference, and I'll just give it once

because it will cover it, but it's Exhibit B-53. The

few quotes that I'll make are found beginning on page

5 and then onto page 7.

There is the statement made there, and I'm

quoting,

"That Drs. Overcast and Lowry agree that the

efficiencies that can be expected to be

achieved under PBR decline over successive

PBR terms."

The proposed PRB -- FBC PBR that's noted also comes

close on the heels of FBC's five-year PBR plan and

that ran from 2007 through 2011 and it's included in

the IR response. FBC has acknowledged that,


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1435

"FBC has already realized significant

efficiencies under its previous PBR."

And if FBC's characterization of "the past success of

PBR" is accurate, then we would submit that there must

necessarily be fewer and/or smaller efficiencies

remaining available to be achieved. As the

expectation of achievable efficiencies for FBC has

already been significantly diminished, we submit, that

rational for implementing a further five-year term of

PBR has similarly been diminished.

A reasonable expectation of achievable

efficiencies is not an incidental consideration. The

companies have noted that expanding the potential pool

of incremental savings from efficiencies is one of the

two most commonly cited benefits of PBR relative to

the traditional cost of service. So as I said, I

believe that puts the entire application in some

additional context.

I move on, then, to the specific list of

questions that the panel provided beginning with those

that deal with the rebasing process or other process

considerations.

I want to begin by reiterating that the

Irrigation Ratepayers’ group does support Mr. Weafer's

comments on behalf of CEC earlier this morning

regarding his suggestion for initiating a Commission-


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1436

supervised -- it's called a revised PBR process.

In terms of question 1(A), “What process do

the parties recommend for transition to the next phase

of PBR?” We would suggest that if we find ourselves

in that situation that PBR has been approved and

there's a need to move in to a rebasing phase, that a

workshop to examine that issue be held no later than

September, 2018. We suggest it be in the context of a

workshop because I think it will be a dynamic process,

as Ms. Braithwaite has noted. Many of the questions

now seem premature. There's a lot of water yet to go

under the bridge between now and 2018.


MR. WEISBERG: Such a workshop could outline the expected

rebasing, both from the perspective of the utilities,

but also that seen by the ratepayers. And it would of

course be eventually have to be subject to the 2018

actuals.

We think it would be appropriate for a

decision to be made at that point, at the completion

of such a workshop, whether to proceed with a sort of

a stand-alone rebasing application, or to include that

in a cost of service application or an extension of a

PBR plan, and an application in that regard.

COMMISSIONER MACMURCHY: Excuse me, Mr. Weisberg, did I

hear you correctly, you are talking September, 2018?


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1437

MR. WEISBERG: Yes.

COMMISSIONER MACMURCHY: Why would you wait so late? I

mean, by the time whatever decision is made, and

applications put forward, aren’t you well into the

next period and whether it is cost of service or a PBR

plan?

MR. WEISBERG: I guess I am -- a good question I guess.

I was trying to balance the need to have the data

available, to see what has actually taken place under

PBR, and where we are, and still move forward and not

delay that process. So, I don’t think there is magic

in the September 2018, I think it needs to be a

balancing of how much information do we have available

to take that measure, and does it move the process.

COMMISSIONER MACMURCHY: And I was looking for magic.

MR. WEISBERG: August 23rd, I just pulled that out of a

hat, but perhaps that sounds more magical. Does that

respond though?

COMMISSIONER MACMURCHY: That is good, thank you.

MR. WEISBERG: Thank you. So, for 1(b), what should be

the timing of the rebasing filing, I think I have just

addressed that and the need to balance the two

considerations. Data on one hand, moving forward.

For 1(c), I’d just endorse Mr. Weafer’s

comments regarding the need for regulatory accounts to

be maintained to ensure that there is a proper and


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1438

complete historical comparison, the ability to make

that.

For 1(d), again, I’d just circle back and

say that the preferred process from the Irrigation

Ratepayers Group point of view, is that described by

Mr. Weafer in pursuing a revised and hopefully

improved PBR plan.

Moving then to the process for setting 2014

and 2015 rates, if a PBR is denied, some grounds for

agreement here. Mr. Weafer supported or agreed with

counsel for the utilities’ submission that there is a

sufficient record now available for the Commission to

determine rates for 2014. We would agree with that.

We don’t think it is necessary to enter into some

other process for that.

In respect to 2015 rates, we are optimistic

that the process to pursue a revised and improved PBR

would be successful if it is permitted to go ahead,

and then that would provide the basis for setting 2015

rates. And other than that, we are not prepared to

advise today of what might be better.

That brings me to the last topic, the FBC

deferral account. A couple of observations in terms

of context for those. The Industrial Customers group

final submissions included the helpful, I think,

observation that the growing number of deferral


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1439

accounts leaves approximately 18 percent of the total

FBC revenue requirement to be determined by PBR. ICG

also noted that approval of the PBR plan would

effectively lock in deferral accounts and remove some

regulatory flexibility that might otherwise exist.

The IRG is not persuaded that the four

deferral accounts that have been identified by Ms.

Herbst earlier, are necessary or appropriate in the

circumstances.


MR. WEISBERG: We note that the previous FBC PBR plan was

successfully completed without those in place. Didn't

seem to cause a problem. The attempt to introduce

them now appears to have more to do with the mutual

interests of the utilities and how easy it for their

operations to mesh with each other, rather than the

more important consideration of does it appropriately

balance the interests of FBC and its ratepayers.

Ms. Herbst identified two options -- two

deferral accounts. The first of those would be to

treat those topics as Z factors and the second, which

was to establish a five-year average. We don't think

that a five-year average is a good idea, I think

largely for the reasons that she identified. Of the

three, whether it's deferral accounts, treating it as

Z factor or a five-year average, our preference, I


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1440

think, would be to go with treating those topics as a

Z factor.

I'll qualify though, that, with my

anticipation that Mr. Hobbs after me may be proposing

a different treatment of those and as I understand

that, it may be to take the 2013 actuals for each of

those four accounts to adjust them for inflation and

add them into the revenue requirement. That, if I've

understood it correctly, seems to me to be the best

approach, but I would leave it to Mr. Hobbs to

elaborate any further or to correct me if I've

misunderstood what I understand him to intend.

Subject to any questions, those are my

submissions. Thank you.

THE CHAIRPERSON: Thank you, Mr. Weisberg. Thank you.

SUBMISSIONS BY MR. HOBBS:

MR. HOBBS: Mr. Chair, Commissioners.

THE CHAIRPERSON: Mr. Hobbs.

MR. HOBBS: I will, as well, follow your letter of June

27th, 2014 with the three items identified. Let me --

before I do that, let me simply make the point that

Mr. Weafer made, and I think it flags the very unusual

circumstances of this application, and that is that

all the customer groups are opposed to this

application and I think you need to give that

considerable weight.


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1441

There's been significant argument with

respect to that and why that is true. I won't do

anything more at this point than commend the

importance of that to you.

Let me turn now to item number 1, with

respect to rebasing. Once again I agree with CEC's

position with respect to this but I do want to put

some emphasis and it's in response to Mr. Ghikas'

comment with respect to low-hanging fruit and the X

factor.

I was surprised to hear Mr. Ghikas talk

about low-hanging fruit because I thought that had

been an issue that had been completely discredited but

here we have it again.

There needs to be support for PRB that's

related to the utilities operating efficiently and

efficiency measures. In answer to your question, how

best to go about rebasing? Well when we get there,

and I'm sympathetic to Ms. Braithwaite's comments with

respect to being a bit premature, but when we get

there there should be evidence with respect to whether

or not the utility is operating efficiently and there

should be some connection between the PBR mechanism

and efficiency measures that the evidence just isn't

there for right now.

So when we get to rebasing, let's at least


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1442

have that evidence so that you -- so that the panel

when they're considering rebasing can consider base

costs in the context of whether or not the utility is

operating efficiently.


THE CHAIRPERSON: Mr. Hobbs, do you have any specific

suggestions of what kind of evidence would be required

to determine whether the utilities are operating

efficiently, or how efficiently they are operating?

MR. HOBBS: I do, and I think it begins with

benchmarking. There needs to be some benchmarking

evidence that has the involvement of customers to

develop it and in the execution of it. But there

needs to be some benchmarking evidence, and in the

case of Fortis Electric there needs to be benchmarking

evidence that’s specific to this jurisdiction. So it

needs to be broader than just B.C. Hydro but it needs

to at least include B.C. Hydro. We should not be in a

situation very much longer when we have two electric

utilities in the province and we have no idea how they

perform one against the other.

THE CHAIRPERSON: When you say “broader than B.C. Hydro”

can you explain what you mean by that, please?

MR. HOBBS: Well, you would have a sample size of 10-15

utilities -- benchmarking is a challenge.

THE CHAIRPERSON: So it would be outside -- benchmarked


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1443

outside the province.

MR. HOBBS: Outside the province, yeah. Other utilities

that were -- I think you’d have to -- you would pick a

different sample size for FEI than you would for FBC,

but you would pick a utility or group of utilities

that had similar characteristics as best you could in

terms of their operating requirements.

THE CHAIRPERSON: And when would you propose a

benchmarking study arrive before the Commission and

before the parties? When in the next five years do

you think that would -- it would be appropriate to

have that prepared?

MR. HOBBS: I heard Mr. Ghikas speak to the midterm

review. That strikes me, at least at this point, as

having some merit. There would need to be some time

to develop the benchmarking study and the parameters

for the benchmarking study that, as I say, would

involve customers. And if you did it at the midterm

then it ought to be made available, easily made

available with the filing of the application.

THE CHAIRPERSON: Thank you. Sorry to interrupt.

MR. HOBBS: And I guess if I may add to that, through the

-- if you approve, and this is the assumption of

question number 1, but if you approve a PBR plan, I

think it should also not only just include a direction

with respect to benchmarking, but it should include,


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1444

which is a different matter, direction with respect to

identifying efficiency gains that can be attributed to

the PBR mechanism that would not have been made

available under traditional cost of service

regulation. We haven’t seen those.

And there needs to be, and this hearkens

back for me to Commissioner MacMurchy’s comments, that

if you were to invest a million dollars on a forecast

of savings of $500,000, then let’s at the outset

identify those two numbers -- the initial investment

and the expected savings -- and then compare, after

you’ve made that investment, compare how you’ve

performed against those two numbers. And there needs

to be consequences, I think, and I’ve mentioned this

in my submissions to you, there need to be

consequences that flow both positive or negative,

which the utility refuses to do, but there need to be

both negative outcomes and positive outcomes for the

utility against those measures.

I’ll turn, unless there are further

questions, I’ll turn to the second question now.

THE CHAIRPERSON: Please do.


MR. HOBBS: On this one, I’m inclined to agree with Mr.

Ghikas, that for 2014 that there be no further change

with respect to the rates for Fortis Electric, and


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1445

that the next application for a two-year test period,

2015 and 2016, has considerable merit as well. So, I

am inclined to support Mr. Ghikas on those two points.

I would probably do so for different reasons, and I

will mention them, because I think they are important.

For 2014, the rate increase for Fortis

Electric, in the absence of the rate smoothing

mechanism, was approximately minus 6 percent. There

needs to be some recognition of that when you approve

the interim rate, because the interim rate is based on

the rate smoothing mechanism. So, we ought not to

lose the advantage of that by just firming up, if you

will, the interim rates for 2014, and there is, I

think, ways to do that.

When we get to 2015, and this distinguishes

in my mind FEI from FBC. The rate increase and the

absence of the rate smoothing mechanism for FBC

Electric, or for Fortis Electric, is about 16.3

percent. And it is 16.3 percent, whether you look at

it form a cost of service perspective, whether you

look at it from the PBR perspective. The variances

are very small, and I will give you references to

that, for that in a moment.

The huge advantage to what Mr. Ghikas is

proposing, is that we will have a review of that

number. That is a huge number. And as I say, I think


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1446

that distinguishes FEI from FBC. FBC is just not a

utility that should now have PBR rolled into it,

because the rates are moving so dramatically from year

to year that it is critically important that we have a

traditional cost of service review of what is

happening in 2015 particularly, but also 2016. So, I

do commend to you, although for different reasons, Mr.

Ghikas’ proposal with respect to item number 2.

With respect to the deferral accounts, you

know, it feels a little bit like, “Well, it is just a

few more deferral accounts, why does it matter?” And

I think at some point we have to stand up and say,

“enough” and whether it is on this application,

although we are just about -- I can't imagine there

being any more after this application. But whether it

is this application or a restructuring of how we

conduct regulation in British Columbia, there is going

to have to come a time when we say “Enough”. Even

though these four deferral accounts are only just four

on top of 57. But there has to become a time when we

say, “No, this is enough.” And I think and encourage

you to do this, make that time now.

The point Ms. Herbst makes to you with

respect to what should the threshold test be for

deferral accounts, is an important point of

discussion, and again, I would encourage you to


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1447

comment on this in your decision. Ms. Herbst says

that your question is worded inappropriately, that the

test should not be whether or not the deferral account

is necessary. In my view, that is absolutely the

correct test. You should not approve deferral

accounts unless they are necessary.

Now, Ms. Herbst turns to Section 59 and

Section 60 of the Utilities Commission Act for support

for her argument that the test isn't necessary.


MR. HOBBS: That’s a red herring if I’ve ever heard one.

You have the discretion under Section 59 and Section

60 to establish regulatory parameters that in your

opinion meet the reasonableness test. But that does

not in any way prevent you from deciding what those

regulatory parameters are going to be, and

establishing regulatory parameters that need to meet

that necessary test. And I think deferral accounts

are in that category.

Before you approve deferral accounts, they

need to be necessary, there needs to be overwhelming

evidence that they are necessary, and then you turn to

the second test within the context of that decision,

are their rates reasonable. That is how Section 59

and Section 60 operates. It does not operate like Ms.

Herbst would have you think. And you know, with all


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1448

due respect to my learned colleague, she is just wrong

on that point.

Let me -- this is an important issue. Let

me talk to the issue of internal consistency. Ms.

Herbst would have you believe that this should be an

issue for your consideration with respects to

establishing deferral accounts. She would have you

believe that when you determine whether or not there

should be deferral accounts, you should consider the

ownership of the utilities. Well, that can't be.

That is trivializing the significance of deferral

accounts. Deferral accounts need to be established on

their merits, not because it might be a little easier,

from an administrative point of view, for the

utilities to administer them if they were the same.

That really is trivializing the significance of

deferral accounts. So, I’d encourage you to give

absolutely no weight to that consideration.

Now, Ms. Herbst goes on to say that we will

avoid windfall gains and losses if we established

deferral accounts. Let me parse that, if you will,

for the moment, from the notion of being avoided, from

the notion of windfall gains and losses. For

circumstances that may or may not be in control of the

utility, and I will get to that for the moment, there

may be windfall gains and losses with respect to


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1449

certain costs. Our forecasts are not perfect,

sometimes things change. When they change, there may

be a windfall gain or loss. Whether you establish a

deferral account or not, does not change -- it doesn’t

in any way connected to whether or not there is going

to be windfall gain or loss. You forecast a number,

things change, there may be a windfall gain or loss.

Yeah. The important point is, who is going to bear

the risk of that? And Ms. Herbst says, you should

avoid the windfall gain or loss by establishing the

deferral account. Well, you see, that is just

nonsensical if you will. There will be windfall gains

and losses against forecasts. We have variances off

of forecasts, it goes without saying. It is a

question of, is the utility going to avoid those

windfall gains or losses by transferring that risk to

the customer, or is it going to be borne by the

utility?

A certain situation that we find ourselves

in now, where almost all of the revenue requirement

risk has been transferred to customers, I say it is

time for that trend to change.

Now, Ms. Herbst was correct with respect to

how you framed question number 3. And that is,

comparing FEI and FBC to see which deferral accounts

FEI had and FBC had. The question could equally --


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1450

and you would have got to exactly the same answer.

What is FBC seeking from you in this proceeding? They

are seeking approval from you for those very same

deferral accounts that Ms. Herbst discussed.


MR. HOBBS: And I can bring you to -- I won't bring you

to it, I'll just refer to it for the record. In

Exhibit B-24, BCUC IR number 2, 54.0. There's a list

provided from the 2012-2013 RRA application which

identities those deferral accounts and then at 54.1

the deferral accounts are subject to further comment

from Fortis. And I flagged that for you and Ms.

Herbst did this morning as well.

Their view of whether or not each of those

deferral accounts has changed, at least with respect

to the interest expensed variance deferral account and

the insurance expense variance deferral account which

in 2012-2013 they said were somewhat controllable and

now Ms. Herbst says they're substantially or

completely uncontrollable.

There's a huge judgment call that's made

here with respect to whether something in controllable

or non-controllable. In my view that ought not to be

the test in any case, whether it's controllable or

non-controllable but it's really difficult to

distinguish the two.


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1451

The more important test for you, an easier

one for you to apply is who should bear the risk and

what kind of regulatory paradigm do we want to have in

British Columbia. Do we want to have one where we

have a heading as lengthy as this about 17 or 18

percent of the revenue requirement or do we want to

really establish costs in a way that we're comfortable

with forecasts and the utility in order to avoid, if

you will, the deferral accounts, the utility bears the

risk. That's a much better regulatory paradigm for us

in British Columbia than the one we have now with

deferral accounts that in some cases are overwhelming.

I will make a few comments now -- oh, no.

I will make a few comments and then I'll close. With

respect to DSM and the new DSM regulation, like Mr.

Andrews this is an important issue to the ICG. We

made, I thought, significant submissions with respect

to the DSM plan and encouraged you to deny the DSM

plan. I'm delighted that Fortis Electric has decided

that they are not going to seek approval of the DSM

plan. It was riddled with all kinds of problems. It

needed to be revisited. We said it needed to be

revisited. Sounds like we're going to have it

revisited.

The point that I would strongly encourage

you to -- what I would strongly encourage you to do is


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1452

to give further direction to Fortis with respect to

their DSM programs and I think the record in this

proceeding is adequate for you to do that. So I

wouldn't simply approve their numbers for 2014 and

leave the many important issues about DSM to them for

them to address for the first time in their

application.

I would encourage you to take this

opportunity to establish directions for Fortis so that

when they do re-file their DSM plan they will do that

with the benefit of your directions.


MR. HOBBS: And I have one to bring to your attention. I

think I only need to do this for the purposes of the

record and it’s in paragraph 78 of our submissions.

But there are other ones and so I think I’ll close

simply by saying that I’d encourage you, as I say, to

take this opportunity to provide directions to them.

THE CHAIRPERSON: Thank you, Mr. Hobbs. I have one

question.

MR. HOBBS: Yes.

THE CHAIRPERSON: It wasn’t clear to me, and maybe I just

didn’t hear clearly enough, but I understand that you

made a fairly lengthy submission on the issue that we

should consider when we approve a deferral account.

But what’s your position on these particular deferral


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1453

accounts?

MR. HOBBS: Oh. Thank you. No. And thank you very

much, Mr. Chair. And Mr. Weisberg in fact captured my

view clearly. You should say no. If I didn’t say it

clearly enough I will now.

Fortis is seeking -- Fortis Electric is

seeking approval from you for four deferral accounts.

Whether or not there were similar arrangements for

regulatory parameters in place with respect to those

costs before is -- I mean, in my view you shouldn’t

give any weight to that. What’s important is that

they are seeking approval from you now for yet four

more deferral accounts. And no. And instead of,

instead of establishing deferral accounts I would in

fact establish -- look at the two thousand -- you have

the benefit of the 2013 actuals for those costs, I

would roll in inflation and leave it at that for 2014.

THE CHAIRPERSON: Okay, thank you, Mr. Hobbs.

Before we continue, just looking at the

clock, maybe we could just do a bit of planning here.

Mr. Quail, how long -- or Ms. Worth, how long do you

think you will be?

MS. WORTH: I don’t plan on being overly long, but I do

have more to say than just sort of a few words on

these issues. So I would expect I would be about 15

minutes.


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1454

THE CHAIRPERSON: Thank you. And Mr. Ghikas, do you have

a reply? I assume you do.

MR. GHIKAS: We do have some points in reply, so I

suspect that as between myself and my colleagues they

will probably -- safe to say, you know, ten minutes or

something like that. It’s relatively brief but --

THE CHAIRPERSON: Under the circumstances I’m thinking we

should take a short break and go through as opposed to

taking a lunch break. Is there anyone that would be

opposed to that approach? No? Okay. So 10 minutes,

yes, come back at 20 after 12 and hopefully we’ll wrap

up in half an hour.

MS. WORTH: Yes, Mr. Chair, if I could ask your

indulgence for a few more minutes to allow me to eat

something before we proceed.


MS. WORTH: Thank you.

THE CHAIRPERSON: All right, so 15 minutes, 20 minutes?

MS. WORTH: Please. Thank you.

THE CHAIRPERSON: Fifteen?


THE CHAIRPERSON: Okay, we’ll come back at 25 after then.

Thank you.

(PROCEEDINGS ADJOURNED AT 12:12 P.M.)

Proceeding Time 12:28 p.m. T38

(PROCEEDINGS RESUMED AT 12:28 P.M.)


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1455

THE CHAIRPERSON: Be seated, thank you. All set, Ms.

Worth?


THE CHAIRPERSON: Please go ahead.

SUBMISSIONS BY MS. WORTH:

MS. WORTH: You have for your consideration a record

created not only by the two applicant utilities, and

your Commission counsel and staff, but through the

participation of the diverse interests who have

intervened in this amalgamated PBR process: the

customer groups, the environmental groups, the

competitor coalition, and COPE 378, one of the unions

representing both applicant utilities’ workforces.

But, even within that group referred to as the

customer groups, there is a wide range of interests

brought to bear on these applications.

Why do the most revenue requirements in

recent memory, because we have the residential

ratepayer perspective, the commercial energy consumer

views and concerns, the electrical utilities

industrial customer groups’ perspective, and last but

not least the irrigation ratepayer class as bringing

their interests here as well.

Each party has brought forward concerns,

sometimes as a chorus, with their fellow interveners,

sometimes in a manner that was best characterized as


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1456

designed not only to bring forward those particular

issues, but to do so in a way that is complementary to

the issues brought forward by others and at times

also, in a limited and strategic manner, taking the

lead on certain focused issues allowing others to rely

on their efforts on that issue, while freeing them to

focus on the issues specific to their own clients, or

to capitalize on their particular expertise.

What COPE sees as particularly striking is

that, despite the obvious differences between the

interveners in this process, there were some

significant commonalities in their evaluation of the

PBR, not the least of which was the universal

opposition to this particular set of applications

despite the regulatory and cost efficiencies that can

be achieved through PBR. We are, like everyone else

here, keenly aware of the fact that we are united in

our opposition, but we are also aware that we are not

here today to argue those concerns again. Instead, we

are here to address the three questions that you have

put to us in your June 27th letter.

So, the four parts of the first question

deal with a number of issues that arise should a PBR

be approved. Now, note I did not specify there this

PBR. I believe that we have made our client’s

position about this PBR very clear already, and I will


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1457

not go there again.

In his submissions on question 1, my friend

Mr. Ghikas flagged an alternative to rebasing that

exists, a brief extension. I believe he specified

probably two years. I am both surprised, and then

again not, by Mr. Ghikas’ submissions on that point.

It is no surprise that the Fortis utilities consider

the applications acceptable, so it follows that they

want to put this forward on the record as early as

possible to flag the potential attractive to them for

an extension.

However, given the strength of the

opposition to this PBR voiced by the number of parties

participating here, that seems to preclude the

possibility of such an extension taking place if the

Fortis PBRs are approved as applied for. If, however

the Commission applies another PBR based on the

evidence generated in this process, or orders an

expedited process such as the one suggested by CEC to

take place to design a new one, there may be an

appetite at the time to entertain that idea, and we

agree with Mr. Ghikas the midterm review does seem to

present the appropriate opportunity to canvas that

with the interested parties.

The answers to question 1 were, for COPE,

difficult to formulate, because we were being asked to


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1458

provide input at a very early juncture, before, as Mr.

Weisberg said, there is enough water under the bridge.

This is before we have even had a chance to see

whether a PBR in operation is workable, to evaluate

its performance over time, and there is, as Mr. Ghikas

said, in his submissions, value in maintaining

flexibility. Particularly given the regulatory

landscape we find ourselves in today. Interveners

universally opposed to the PBR as applied for, and the

two utilities firmly entrenched in their positions,

and their unwillingness to consider any modifications

to their applications.

However, in an effort to be responsive,

COPE has formulated answers to the questions as posed

wherever possible, and has engaged in discussions with

other groups in order to find commonalities and

efficiencies in this.


MS. WORTH: We have come to the -- our client has come to

the position that the suggestion forwarded by CEC,

that of an interactive and responsive working group

like that which we actually found useful in the Fortis

Gas supply mitigation incentive program, is the best

option we can see at this time to promote not only a

fair process but to ensure that we do not end up with

a rate structure that would result in the two


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1459

utilities receiving an unjust, unreasonable or unduly

preferential rate.

In COPE's view, utilities would be highly

motivated to preserve their ability to operate under a

PBR program. It is, after all, a regime that works to

their advantage by reducing the regulatory cost and

processes that they are subjected to.

This motivation will, we think, likely

translate into a far greater level of motivation and

cooperation than we've seen in this process certainly,

resulting in a greater change to the input and

suggestions put forward by participants and the

activity of the Commission staff will be considered

and, where appropriate, incorporated to secure

sufficient consensus to have an endorsed application

put to the Commission for its consideration at the

end.

That is a very different situation than we

have found ourselves in here where the companies have

excluded -- sorry, the companies have exceeded their

usual vigorous defense to engage in a campaign of

unwarranted and excessive aggression against the

views, the work and even the professional integrity of

those experts whose testimony contradicts their own.

This process, the utilities’ incentive to

participate rather than to dictate and the timing of


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1460

the review taking place after a PBR has developed over

its term will, we submit, provide the best opportunity

to improve the rate regime by recognizing its actual

strengths as developed while shoring up its apparent

weaknesses again over the time as they've been proven

with the proper information and context that that time

will provide.

Now 1(b) asks for suggestions on the proper

timing of a rebasing process and we've heard some

submissions from interveners about the perception that

cycling between PBR and a cost of service rate

regulation does concern them about there being an

incentive to game the system unfairly to maximize the

benefit to the shareholders on the backs of the

utility's ratepayers.

Those concerns, whether valid or not,

should not, in COPE's submission, preclude a

consideration of how a rebasing should take place and

that this consideration should take place at the

proper time. It may be appropriate to continue with a

new and rebased PBR or to return however long or

however briefly to a cost of service regime. But we

submit at this time it is difficult to know whether

that would be appropriate. And it is our submission

that the appropriate timing for this evaluation is at

or just before the midterm review with an early filing


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1461

to allow for the regulatory review to be complete or

substantially complete before the new term of the

regime begins.

1(c) asks for what other items should be

reviewed in the proceeding to consider a rebasing

application. But COPE submits that in the absence of

an Order specifying what form PBR might take, this --

sorry -- the theoretical -- knowing how the

theoretical PBR might develop over its term and what

issues might actually come to the fore during that PBR

term external to but affecting the terms within that,

it cannot offer any concrete suggestions at this time.

That is again a situation where there is value in

maintaining flexibility.

Now aside from the comments and suggestions

that we've already put on the record in our

submissions now, COPE has nothing to offer in response

to the invitation to provide any other process

suggestions or issues relevant to an ongoing PBR

regime as per 1(d). But we do think that this is an

appropriate time to note that there is, in this

particular circumstance, no alignment as between the

customer and utility interests and that that is

something that should be taken into consideration when

the time does come to formulate the suggestion and

issues relevant to the ongoing PBR, should that be


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1462

determined to be appropriate.


MS. WORTH: Question 2 canvasses the issue of rates for

2014 and 2015 should this PBR not be approved. We,

like CEC and others, see that while there is some risk

in basing a final Order for 2014 rates on the existing

record, it is minimal and manageable. Given the value

to be gained in creating a regime that more closely

allies the interests of Fortis shareholders with those

currently left out in the cold, that being their own

ratepayers, this is yet another situation where COPE

suggests the EC’s suggested process, a GSMIP-like

process that would in our submission and in these

circumstances allow for a relatively compressed and

efficient process capitalizing on the existing record,

to set the stage for the development of a new and

better PBR better supported, we submit, by an

evidentiary update.

And finally in regards to question 3, while

acknowledging the issues that others have flagged,

including CEC, COPE sees no reason to differentiate

the treatment that one Fortis receives on deferral

accounts than the other. So the union does not oppose

the Fortis Electricity Utility’s application in this

regard.

Subject to any questions, those are our


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1463

submissions.

COMMISSIONER COTE: I have a question.

MS. WORTH: Certainly.

COMMISSIONER COTE: You spoke about turning it over to

the group of interveners to work with the utility to

develop a new plan, and you talked -- I think the term

you just used a minute ago was “a new and better PBR”.

Can you tell me a little bit in your view what that

might look like?

MS. WORTH: Well, I mean, the various groups here have

flagged issues like, in our case, the SQIs, and in our

participation should that type of process be convened,

COPE would propose to actually work with the utility

and in concert with Commission staff and other

interveners to find the appropriate balance of the

SQIs and any cost or benefit kind of impacts on the

utility in order to have a PBR that better balances

the shareholder and the ratepayer interests. That’s

just one example. There’s any number of ways that

there can be that kind of back and forth on the

various issues that have been brought to the fore.

COMMISSIONER COTE: So you’re really not looking at

changing the elements of the PBR, just the numbers

that are associated with them and creating more

balance. You used the example of SQIs and I guess

that could apply to any of these. Is that really


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1464

where the issue lies?

MS. WORTH: It can also be a situation where a structural

element could be examined -- identified and examined

and worked on to improve the PBR. Our focus in this

was really strategic in order to allow others to focus

on what their expertise and what their resources

allowed them to do. We took the forefront on the SQI

issue and we were happy to do that. We didn’t forward

anything other than that, so for me to comment on

whether there’d be any interest in addressing the

structural issues is something that I really can’t

kind of say at this time. But it is an option.

At GSMIP there were any number of issues

that we dealt with, the Gas Supply Mitigation

Incentive Program -- not just numbers but also sort of

how it was structured, and we played with things in

order to make sure that it was a solution that was

acceptable to the company as well as to the

participants, and there were endorsement letters that

were provided to the Commission Panel to consider

along with the actual application.

COMMISSIONER COTE: Okay, I think you’ve answered my

question, thank you.


THE CHAIRPERSON: Thank you, Ms. Worth. Mr. Ghikas? Ms.

Herbst?


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1465


REPLY BY MS. HERBST:

MS. HERBST: Thank you, Mr. Chair and Commissioners. I'm

here to deal with two points that have arisen in the

course of intervener submissions: one relating to

deferral accounts and one just briefly on the DSM

regulation.

To deal first with deferral accounts, I

address chiefly the submissions of Mr. Hobbs, Mr.

Weisberg and Ms. Braithwaite. And Ms. Braithwaite and

Mr. Hobbs both characterize deferral accounts as – and

of course this is in relation to item 3 on the

Commission's list – they characterize deferral

accounts as shifting risk to customers, and I have a

couple of points about that.

The first is that this characterization

assumes that the outcome will be unfavourable in any

given case in the sense that the outcome will be worse

that what was forecast and that there will be some

sort of loss to be covered off.

The variance may well work the other way

and the risk in that case is not having a deferral

account and not having customers be able to share the

benefit in the same way that a deferral account would

allow. And so for example when I was speaking earlier

I referred to $6 million flowing back to customers as


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1466

a result of the interest expense deferral account that

was in place during the 2007 PBR term. The risk here

is not having such an account and not having customers

bear or getting the benefit of the full rate reduction

that flows from that $6 million flowing back. I think

what would have happened without a deferral account is

a 50/50 split between shareholder and ratepayers.

Now second, to the extent that there is a

risk, and again turning to the characterization or

speaking of the characterization of the risk being

somehow shifted to ratepayers and if there is in a

given case a lesser cost forecast than actually turns

out to be incurred, there are some circumstances where

in fact the utility should not be left bearing the

risk and Mr. Hobbs characterized his approach as

consistent with Sections 59 and 60 of the Utilities

Commission Act.

I say it's diametrically opposed to it and

if you look at, for example, Section 59(5) of the

Utilities Commission Act, it talks about the utility

having a fair and reasonable compensation for the

service provided by it.

Mr. Hobbs’s approach and more generally not

allowing deferral treatment in certain circumstances

would have the utility bear the loss, would have

prudently incurred costs that are not covered, and


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1467

would not only allow it not -- would not only result

in a situation where it doesn't earn the return that's

contemplated by the section, but wouldn't have those

basic costs covered and that's not consistent at all

with the legislative scheme.

Now there's a bigger -- clearly there

bigger arguments that are being advanced in relation

to deferral accounts by Celgar and ICG, in part in the

context of the core review that's going of the BCUC.

I think that's symptomatic of the fact that there's

some recognition that the present legislative regime

and the present set of jurisprudence and authority

surrounding deferral accounts is not in line with what

Mr. Hobbs would suggest. There has to be some other

mechanism that they're seeking out to get to that

result.

I say that FBC is entitled to be treated in

accordance with the statutory regime that's in place

now and with the authorities that are in place now,

and those do favour the deferral account treatment

that's being sought.

In any event, this set of -- this part of

the submissions that Mr. Hobbs advanced related to

whether or not the test, “Is a deferral account

necessary” as opposed to “Is it simply reasonable to

adopt that approach” and my original submissions


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1468

address the necessity as well.

Now the next point I want to address, still

in relation to deferral accounts, is in relation to

the linkage that Mr. Weisberg drew between deferral

accounts and PBR, I think in part in reliance on a

written submission that had been advanced in that

context as well by ICG.

And I say firstly the deferral accounts

would be applied for whether or not this is a PBR

period. That's illustrated by the fact that both FEI

and FBC applied for the deferral accounts in the

context of the 2012 and 2013 revenue requirements

applications and indeed by the fact that FEI was

granted that treatment in the non-PBR context.

Now there was also a reference to the fact

that only 18 percent of the revenue requirements is

subject to PBR and some connection being drawn with

deferral accounts in that context. It's certainly not

the case that 82 percent are subject to deferral

accounts and I say that it's entirely consistent with

the notion of PBR that the deferral account treatment

be accorded to the items that are being singled out in

this context.


MS. HERBST: And PBR is intended to provide an incentive

for the company to capture efficiencies from


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1469

controllable costs, so prudent management decisions

are made in relation to costs that can be controlled.

The very premise of the accounts that are being

applied for here, is that they are substantially not

controllable items, and so the two are entirely

consistent. But one is not driving the other; they

exist in parallel.

Now, Mr. Weisberg, I think, said in

reliance on an ICG written submission, that the PBR

plan locks in deferral accounts. Now, this assumes

that during the PBR period the utilities are

unsupervised. That’s of course not the case. And so,

for example, there will be annual reviews where

deferral account balances can be reviewed. There is

no -- this is the end of the discussion at this point.

Now, Mr. Weisberg referred as well to the

growing number of deferral accounts and I just flag

that it is apparent from the application and I think

one of the IR responses that FBC is actually

discontinuing a fair number of them. More are being

discontinued than the four being added. There was

also a reference in the interveners’ submissions, I

think Mr. Weisberg alluded to this as being an option

that was being put forth by Mr. Hobbs, of taking 2013

actuals for these items and adjusting for inflation.

Now, I say first of all, this is a new way to


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1470

forecast, it is not really an option to deferral

accounts. It is a new approach that FBC is supposed

to be taking to arrive at the numbers that it

forecasts, and I say that that is not really the issue

in item 3, but in any event, it is not a good method

for doing a forecast. It is likely to result in

forecasts that simply give rise to greater variances.

Certain of these items simply don’t really lend

themselves to the notion of adjusting for inflation.

For example, like interest expense and tax. But, in

any event, these items are, by their nature

substantially or entirely uncontrollable. So, there

is no reason to think that 2013 actuals are a good

predictor of what 2014 will be. The same problem

exists here, although perhaps even in more

concentrated form, as in relation to the five-year

average that was proposed as an option in one of the

BCUC IRs, and that I addressed earlier.

And the last point that I have is in

relation to not deferral accounts, but the DSM -- to

the DSM regulation. And Mr. Hobbs’s suggestion that

the Commission take this opportunity to provide some

directions to FBC in terms of going forward, and I

think he alluded specifically to paragraph 78 of his

submission, and I gather that that is a paragraph that

relates to having similar DSM for FBC and B.C. Hydro.


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1471

And I say certainly that is not a direction that

should be made. The Commission has addressed in the

past, including in the 2012-2013 revenue requirements

application which was also a review of the integrated

system plan, that FortisBC, FBC, and B.C. Hydro are

different utilities with different considerations and

can have different DSM programs. And more generally I

say the interveners will be consulted with going

forward, as FortisBC’s application for 2015-2018 or

2015 certainly, and possibly a further year or two

scheduled is being put in place, as will be the

Ministry, and that no directions should be made in

that respect.

Subject to questions, I will turn it over

to Mr. Ghikas.

THE CHAIRPERSON: I do have a question, please.

MS. HERBST: Yes?

THE CHAIRPERSON: And this may not be that important in

the general scheme, I am not sure, but it was my

understanding when you made your earlier submission

that these deferral accounts exist. Or at least they

are in place during the last PBR period. Is that

correct?

MS. HERBST: That’s the -- there was an interest variance

deferral account which was, I gather, in place, and is

now being reinstated. It wouldn’t be in place now,


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1472

because it was -- approval was sought and rejected in

the 2012-2013 revenue requirements application.

THE CHAIRPERSON: What about the other three?

MS. HERBST: The insurance expense variance account, no.

It was not in place during the 2007 PBR plan. And

similarly, an application was rejected for it during

the non-PBR 2012-2013 application, so it is not in

place. And the tax and the property tax, so they had

the Z factor treatment, but I gather in practice a

deferral account was associated in terms of

implementing that treatment during the 2007 PBR plan,

but generally speaking they’re not in place now.


MS. HERBST: Approval was sought for them in the non-PBR

context for 2012-2013 but not granted. I say

“generally” because there is a property -- there’s a

limited property tax deferral account which had to do

with a specific review that was going on by B.C.

Assessment of certain valuation approaches, and so

there’s a narrow deferral account that’s in relation

to that.

THE CHAIRPERSON: Okay, so during the 2012-2013 period

there were no deferral accounts? Is that --

MS. HERBST: Of these four, other than the narrow one for

property, the narrower for property taxes.

THE CHAIRPERSON: So were these then still flow-through


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1473

expenses or were they considered controllable expenses

or not controllable in the 2012 and 2013?

MS. HERBST: In FBC’s application they were considered --

they were given labels that were slightly different or

somewhat different than are being attributed to them

now. But deferral account treatment was sought on the

basis that at least they had in part a non-

controllable element even in that categorization. I’m

not sure about what has happened in terms of if there

have been variances, what’s happened in the 2012-2013

period. I can ask.

THE CHAIRPERSON: But -- okay, sure, if you don’t mind.

MS. HERBST: Absolutely.

No variances have been flowed through on

those four items for the 2012-2013 period.

THE CHAIRPERSON: On any of those items.

MS. HERBST: Yeah.


MS. HERBST: That’s right.


MS. HERBST: Thank you.

REPLY BY MR. GHIKAS:

MR. GHIKAS: Mr. Chairman, I will be brief. I have four

points I’d like to address. The first one is the

theme that came up through several of the submissions

from my friends, and it is the suggestion that we move


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1474

to a new process to look at a different type of PBR

that, in their words, better meets the needs of both

stake -- of all stakeholders.

Now, Fortis’s submission is that we do not

need another process at this time. What we need is to

bring this process to an end and move forward. And

the parties have disparate views on how to separate in

this proceeding. There’s no question about that.

They differ in fundamental ways, in fact. And what is

evident is that the interveners as a collective,

they’re really questioning fundamental elements of

what it means to be under PBR. And when you have that

type of fundamental disagreement where the utility is

proposing PBR and the interveners are supporting what

in my submission is PBR in name only, when you have

that type of fundamental difference among the parties,

that that is precisely the time when the Commission

needs to come in and make a decision. And the idea

that we should defer the issue because there’s a

fundamental disagreement, in my submission, is

backwards.

At this point in time what we need is

guidance from the Commission and a decision one way or

the other, or else we’re going to be on the never-

never plan. And those workshops or negotiations or

whatever you want to call them are going to get tied


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1475

up in the same type of issues that have been canvassed

at length in the submissions in this proceeding.

When my friend Ms. Worth cited the GSMIP,

the incentive plan, Gas Mitigation Incentive Plan, the

difference in that circumstance is that parties in

that context all agree that GSMIP is a good idea, and

then they negotiate and work on the elements of the

plan.


MR. GHIKAS: At the outset of the proceeding Fortis

proposed an NSP, and that was on the presumption that

parties would want to negotiate within the parameters

of what is a PBR. But when you’ve moved to the point

where the parties are clearly so fundamentally apart

that is the time that I say, in my submission, we need

a decision.

Now a lot of the submissions that were

being made by my friends sounded a lot like moving to

a process that sounds a lot -- whatever its name may

be, sounds an awful lot like an NSP. And my

submission is that the Commission has already said no

to an NSP. And parties may like that and they may not

like that but the fact is the Commission considered it

appropriate to hear evidence on the proceeding and

determine that application by that process. And in my

submission it is entirely appropriate now that that


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1476

decision had been made that the Commission follow

through with the approach that it’s taken.

The second point was one raised by my

friend Mr. Weafer, and it was in respect of the IR

response 1.1 that Fortis had provided which was the

assumptions that went into the calculation of the

revenue sufficiency analysis applied to Dr. Lowry’s

analysis. And my friend spoke to that issue by first

of all saying that a GDP-IPI FDD it was -- my friend

was pointing out that Fortis used actual numbers that

were an average of GDP-IPI FDD of 1.47 percent, and he

was pointing that out and he was suggesting that

Fortis ought to have used a forecast. And he said

that a forecast was available in May 2014. May 2014

is after the hearing was done. That’s when the

forecast came available. And you will see in the

response here that while there may be a forecast it’s

not in the record first of all, and second of all you

will note that Fortis couldn’t find it. So there may

be, as Dr. Lowry seems to be indicating a forecast now

as of May 2014, but if it’s out there Fortis couldn’t

find it and there is evidence of that.

So in my submission Fortis, first of all,

shouldn’t be faulted with using the only numbers that

were available at the time. And second of all if --

it’s really questionable whether the Commission should


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1477

be seeking out and using an inflation measure when

it’s so difficult to find. That was the first point

on that.

The second point is that the implication of

that submission was that these would have material --

using the actual number, the 1.54 instead of 1.47

using this forecast rather than what Fortis did, would

have a material impact on the results of the analysis.

And that’s simply not the case. In the response

Fortis provided the spreadsheet and we’ve plugged in

the numbers in the spreadsheet as the Commission could

do on its own, and it’s clear -- I will give you the

numbers. Instead of $112 million shortfall for FEI,

it’s 108; instead of $129 million FEI cumulative

shortfall in O&M it’s 125; and instead of 34 shortfall

for O&M it’s 33.

Now you can play with these assumptions.

There is no magic to the precise number but the thrust

of the sufficiency analysis is simply an order of

magnitude impression that you come away with at the

size of those numbers. So whether or not you plug in

new numbers and you look at the fact of the matter and

the fact that it’s inescapable is that that is a huge

number and the Commission should have regard to that.


MR. GHIKAS: The third point and the fourth point come


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1478

out of my friend Mr. Hobbs’s submissions about what

the content for the future application should be, the

next application. And the first point that he

indicated that I wish to respond to, was that he

suggested that there be a benchmarking analysis in the

future application and that it be prepared and

submitted for that.

Now my first point in response is that this

all related to my friend’s desire to compare FortisBC

to BC Hydro. And I would simply remind the Commission

that you have made a determination on the relevance or

lack thereof of a comparison in the analysis, a

comparison of those two utilities for the purposes of

assessing productivity.

The second point that I would make in this

regard is that there is evidence in this proceeding on

the utility of benchmarking. And I will just read

into the record so that it’s there FEI’s application

Exhibit B-1, page 21, and also Exhibit B2-8, BCUC

3.42.1.1. And there is discussion there that the

utility of benchmarking is limited by virtue of the

operational differences and the way in which

categorization is done by each utility. And Dr.

Overcast comes away with the -- his evidence on this

is that benchmarking to determine overall productivity

in inordinately imprecise as a measure for evaluating


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1479

service performance.

And so, in my submission, in Fortis’s

submission, the benchmarking analysis should not be

included as a requirement in any future application.

And there is no need for it and it’s of limited

utility.

The second point that my friend Mr. Hobbs

discussed in terms of the content of future

applications was in essences as I understood it a

description of cataloguing of past efficiencies that

had been achieved during the PBR plan and that the

company should be bringing forward and itemizing and

demonstrating which of these savings that occurred

were actually efficiencies and so on. There have been

extensive submissions in the written submissions about

why that type of requirement in a PBR is fundamentally

at odds with the whole point of PBR. And really

requiring that type of analysis in the next rebasing

application is simply fundamentally inconsistent. It

goes to this fundamental disagreement about what it

means to be under PBR and I would submit that it is

not appropriate if this is to be a PBR to require that

type of analysis the next time we go into a hearing

for rebasing.

Those are my four points subject to any

questions; I think we’re free.


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1480

THE CHAIRPERSON: All right. Okay, thank you, Mr.

Ghikas.


THE CHAIRPERSON: All right, Mr. Weafer.

MR. WEAFER: Can I just make one comment on Mr. Ghikas’s

point in terms of availability information?

THE CHAIRPERSON: Go ahead.

MR. WEAFER: The point was raised on the record that this

wasn’t on the record but the Information Request and

here relating to BCGDTP -- GDP-IPI FTD -- that

forecast that we provided was available in May for $85

from the Conference Board of Canada. It’s a material

forecast and surely the company knows it’s -- should

know it’s available if they are relying on it as a

response to the Commission Panel of an IR. Thank you.

THE CHAIRPERSON: Thanks for pointing that out, Mr.

Ghikas. Is that -- okay. All right, well, thank you

very much everyone, and we’re dismissed.

(PROCEEDINGS ADJOURNED at 1:07 P.M.)

Documents

BRITISH COLUMBIA UTILITIES COMMISSION · 7/14/2014 · MR. MILLER: B.C. Sierra -- or Sierra Club of British Columbia and B.C. Sustainable Environmental Association. MR. ANDREWS: