volume 1...2012/10/24 · presentation, of phase 1 of the application. and that again is prescribed...

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

Re: FortisBC Energy Inc. Application for Approval of Rate Treatment of Expenditures

under the Greenhouse Gas Reductions (Clean Energy) Regulations and Prudency Review of Incentives under the 2010 -‐ 2011 Commercial NGV Demonstration Program.

BEFORE:

L. Kelsey, Commission Chair / Panel Chair

VOLUME 1

Streamlined Review Process (SRP) PHASE 1

Vancouver, B.C. October 24, 2012

LIST OF ATTENDEES L. KELSEY Commission Chair/Panel Chair G.A. FULTON, Q.C. Commission Counsel Yolanda DOMINGO Commission Staff Philip NAKONESHNY Commission Staff Suzanne SUE Commission Staff Mark THOMAS Commission Staff Thomas HACKNEY B.C. Sustainable Energy Association Bill ANDREWS Counsel for B.C, Sustainable Energy Association Christopher P. WEAFER Counsel for CEC David CRAIG Commercial Energy Consumers’ Association Tannis BRAITHWAITE Counsel for BCPSO Richard GOSSELIN Fortis Energy Arvind RAMAKRISHNAM Fortis Energy Laurel ROSS Commission Staff Sarah WALSH Commission Staff Todd SMITH Commission Staff Song HILL FortisBC Gareth JONES FortisBC Sean HILL FortisBC Regulatory Diane ROY FortisBC Michelle CARMAN FortisBC Dave PERTTULA FortisBC Doug STOUT FortisBC Mark GRIST FortisBC Jason WOLFE FortisBC Marr GHIKAS Counsel FortisBC

Roger DALL’ANTONIA FortisBC Ilva BEVACQUA FortisBC

James WIGHTMAN BCPSO Christina IANNICIELLO B.C. Ministry of Energy, Mines and Natural Gas

INDEX PAGE

FORTISBC PANEL: JASON WOLFE, Affirmed: MARK GRIST, Affirmed: DOUG STOUT, Affirmed: DAVID PERTTULA, Affirmed: MICHELLE CARMAN, Affirmed:

Presentation ................................... 9

Questions ..................................... 46

SUBMISSIONS BY MR. GHIKAS ......................... 145

SUBMISSIONS BY MS. BRAITHEWAITE ................... 163

SUBMISSIONS BY MR. ANDREWS ........................ 166

SUBMISSIONS BY MR. WEAFER ......................... 170

SUBMISSIONS BY MS. IANNICIELLO .................... 175

INDEX OF EXHIBITS

NO. DESCRIPTION PAGE

VOLUME 1, OCTOBER 24, 2012 B-7 SLIDE PRESENTATION .......................... 46 A2-1 FLEETS AND FUELS ARTICLE ..................... 52 A2-2 ABBOTSFORD COUNCIL REPORT .................... 52 B-8 SLIDE RELATING TO BARRIERS TO ADOPTION ....... 53 B-9 SLIDE HEADED INCENTIVE PROGRAM DESIGN AT WORK, EMTERRA EXAMPLE ..................... 53 A2-3 EXCERPT - NORTH AMERICAN NATURAL GAS MARKET

DYNAMICS, A STUDY BY THE CANADIAN ENERGY RESEARCH INSTITUTE ........................... 128

B-10 NORTH AMERICAN NATURAL GAS MARKET DYNAMICS -

NATURAL GAS VEHICLES, A REVIEW, DATED MARCH 2011, A STUDY BY THE CANADIAN ENERGY RESEARCH INSTITUTE .................... 138 B-11 DICTIONARY DEFINITION OF “EXPENDITURE” FROM WEBSTER'S DICTIONARY .................... 141 B-12 DICTIONARY DEFINITION OF “GRANT” FROM OXFORD DICTIONARY ............................ 141

FortisBC - Greenhouse Gas Reductions SRP Phase 1 - Volume 1 Page: 1

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Allwest Reporting Ltd., Vancouver, B.C.

CAARS

VANCOUVER, B.C.

October 24th, 2012

(PROCEEDINGS RESUMED AT 9:00 A.M.)

THE CHAIRPERSON: Everyone who is standing, please sit

down.

MR. FULTON: Old habits are hard to break.

THE CHAIRPERSON: That’s right, exactly. Exactly.

MS. IANNICIELLO: Christina Ianniciello with the Ministry

of Energy, Mines and Natural Gas.

TELEPHONE VOICE: Has joined the conference.

THE CHAIRPERSON: Well, good morning, everybody, and

welcome. For those who don’t know me, I’m

Commissioner Len Kelsey. And this streamlined review

process today is convened to consider certain parts of

FortisBC Energy’s application for approval of rate

treatment of expenditures under the Greenhouse Gas

Reductions Regulation. At times, as we proceed

through the day, I’m sure this will be referred to as

GGRR.

The application was filed on August the

21st, pursuant to Sections 59 and to 61, and Section 90

of the Utilities Commission Act, and Fortis requested

the streamlined review process with a decision from

the Commission by the end of October. The Commission

determined, by Order G-125-12, that the application


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should proceed in three phases, with Phase 1 and 2 by

the streamlined review process. Phase 1 is prescribed

undertaking 1, which is vehicle incentives or zero-

interest loans. Phase 2 is prescribed undertaking 2,

CNG stations and prescribed undertakings, and 3, LNG

stations.

Phase 3, prudency of past incentives and

associated cost recovery, and that phase is being

considered following a written hearing process.

The process this morning will deal with

Phase 1.

The application was filed as an amalgam of

all three phases and, by necessity, it may be

necessary as we proceed through this first phase to

reference information that will be dealt with from a

decision-making perspective in another phase. I think

we should accommodate this, for better understanding,

but not to confuse the decision-making required for

the phase that we’re in.

The application asks specifically for

decisions on the following matters. Approval of the

following two deferral accounts: the first being a

non-rate-based deferral account, referred to as the

NGT incentives account, attracting AFUDC to capture

(a) all grants and costs, including a portion of

application costs related to prescribed undertaking 1


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for the period until December 31st, 2013; and (b) to

capture the 2010-2011 incentives in the amount of $5.6

million.

This account is to be transferred to rate

base effective January 1, 2014 and will continue to

capture the actual incentives granted under prescribed

undertaking 1, and will be amortized over a ten-year

period into the delivery rates of all non-bypassed

natural gas customers.

The second deferral account is a non-rate-

based deferral account attracting AFUDC, which is

referred to as the fueling station variance account,

to capture the total revenue surplus or deficiency

pertaining to fueling station facility costs that have

not been forecast in rates, as well as the

administration and application costs for the

prescribed undertakings established under Sections

2(2) and 2(3) of the GGRR.

Proceeding Time 9:04 a.m. T2

This account is to be transferred to rate

base effective January the 1st, 2014, with an

amortization of three years into the delivery rates of

all non-bypass natural gas customers.

Number 3, the accounting and rate treatment

methodology to be applied to these deferral accounts,

and the related expenditures associated with the three


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prescribed undertakings identified in the GGRR for the

current period of the 2012-13 revenue requirements,

and for future years as described in section 5 of the

application. This methodology entails recovering

program costs from all non-bypass Fortis Energy

customers.

Fortis is also seeking orders that the

incentive grants distributed in 2012 and 2011 that

total 5.6 million as outlined in section 7 of the

application were prudently incurred expenditures and

are recoverable through rates from FEI's non-bypass

natural gas customers, and (2) the 5.6 million in

previously issued incentives will be subject to the

accounting and rate treatment that FEI has proposed in

section 5 of the application. FEI commits to treat

the 5.6 million and previously issued expenditures as

part of the $62 million in the prescribed undertaking

established under section 2(1) of the GGRR.

In this Phase 1 process, we will be dealing

with prescribed undertaking 1, vehicle incentives or

zero interest loans. To be clear, this does not

include accounting treatment for CNG or LNG fuelling

stations or the prudency of past incentives and

associated cost recovery.

Following this Phase 1 process, we will

reconvene to deal with Phase 2. As I already


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mentioned, Phase 3 is being dealt with by way of a

written hearing as per Order G-154-12. Having

reviewed the matters, I think it may take more time to

deal with Phase 1 than Phase 2, and we may have to

adjust our proposed schedule accordingly. In any case

I want to deal with both phases today, and so we will

take whatever time it takes to conclude this.

The Commission distributed Exhibit A-5,

which described the process we will follow in this

proceeding today. A more detailed outline of the

process was published in March of this year and is

available on the Commission website. And I refer

there to the streamlined review process.


To clarify the process, following my

comments and introductions, FEI will be called upon to

commence with an oral discussion, or a short

presentation, of Phase 1 of the application. And that

again is prescribed undertaking 1, vehicle incentives

and zero-interest loans. Participants may verbally

direct questions to FEI during any part of the

presentation by first identifying themselves and

taking into consideration requirements for the

transcript process. All participants are expected to

conduct themselves in an open and respectful manner.

I have a further thought on questions, which I’ll get


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to in a moment.

To close, FEI will provide final

submissions, followed by final submissions from

interveners, if there are such submissions. Then FEI

will have an opportunity for reply submissions.

Unless interveners have agreed otherwise,

final submissions by interveners will proceed in

alphabetical order of each intervener organization. I

have asked Commission counsel Gordon Fulton to

supervise this.

Prior to this part of the proceeding, I

will canvass the applicant and the interveners to

determine how much time will be allotted to each for

their submissions.

Now, getting back to questions, in terms of

questions I think it would be most productive if

questions other than clarifying questions follow the

presentation. And when a question is raised, others

who have a question on the same topic follow with

their questions. That way, we can efficiently group

questions together rather than each asking our own

questions in turn. I may have questions as well. We

will, however, at the end of the question period, make

sure that everyone has had an opportunity to ask their

questions.

I remind you that this period is for


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questions, not argument or comments of support.

This session is being recorded and a

transcript will be made available. When you speak,

please identify yourself and speak clearly. We also

have people participating by telephone today, and

again, I would ask as they may have questions, to

identify themselves and speak clearly and loudly so

everyone can hear, and their questions can form part

of the transcript.

Finally, I want to remind everybody that

the streamlined review process is relatively new.

It’s new for the applicant, new for many of the

interveners and certainly new for the Commission. So

let’s not get too tough on each other in terms of

process. Everyone is learning here, and I expect some

accommodation.

We’re going to start by going around the

table and introducing ourselves, after which Hal

Bemister will swear in the representatives that are

here from Fortis. And then once that’s complete,

we’ll proceed with the hearing process.

So to begin, as I mentioned on my entry, I

am Commissioner Len Kelsey and I'll start to my

immediate right.


MR. FULTON: Gordon Fulton, Boughton Law Corporation,


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Commission Counsel.

MS. DOMINGO: Yolanda Domingo, Commission Staff.

MR. NAKONESHNY: Philip Nakoneshny, Commission Staff.

MS. SUE: Suzanne Sue, Commission Staff.

MR. THOMAS: Mark Thomas, Commission Staff.

MR. HACKNEY: Tom Hackney, B.C. Sustainable Energy

Association.

MR. ANDREWS: Bill Andrews, counsel for the B.C.

Sustainable Energy Association.

MR. WEAFER: Chris Weafer, counsel for the Commercial

Energy Consumers' Association.

MR. CRAIG: David Craig, Commercial Energy Consumers'

Association.

MS. BRAITHWAITE: Tannis Braithwaite, counsel for the

BCPSO.

MR. GOSSELIN: Richard Gosselin, Fortis Energy.

MR. RAMAKRISHNAM: Arvind Ramakrishnam, FortisBC.

MS. ROSS: Laurel Ross, Commission Staff.

MS. WALSH: Sarah Walsh, Commission Staff.

MR. SMITH: Todd Smith, Commission Staff.

MS. HILL: Song Hill, FortisBC.

MR. JONES: Gareth Jones, FortisBC.

MR. HILL: Sean Hill, FortisBC Regulatory.

MS. ROY: Diane Roy, FortisBC.

MS. CARMAN: Michelle Carman, FortisBC.

MR. PERTTULA: Dave Perttula, FortisBC.


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MR. STOUT: Doug Stout, FortisBC.

MR. GRIST: Mark Grist, FortisBC.

MR. WOLFE: Jason Wolfe, FortisBC.

MR. GHIKAS: Matt Ghikas, external counsel for FortisBC.

MR. DALL'ANTONIA: Roger Dall'Antonia, FortisBC.

MS. BEVACQUA: Ilva Bevacqua, FortisBC.

THE CHAIRPERSON: And our telephone participants, please.

MR. WIGHTMAN: James Wightman, BCPSO.

MS. IANNICIELLO: Christiana Ianniciello, B.C. Ministry

of Energy, Mines and Natural Gas.

THE CHAIRPERSON: Is there anyone else on the telephone?

No. Okay, thank you very much.

Mr. Bemister, would you swear in the Fortis

representatives please.

FORTISBC PANEL:

JASON WOLFE, Affirmed:

MARK GRIST, Affirmed:

DOUG STOUT, Affirmed:

DAVID PERTTULA, Affirmed:

MICHELLE CARMAN, Affirmed:

MR. GHIKAS: Mr. Chairman, before that panel launches

into its presentation, I just had one point of

clarification on the process about the phasing. As I

understood what you were saying this morning is that

the phasing is being done for administrative

simplicity to keep the issues separate. In terms of


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the evidentiary record itself, the intention that

Fortis has been operating on is that the evidentiary

record is still unified in terms of the application as

a whole, so that in terms of general comments that are

made this morning or in the context of -- we don't

necessarily have to repeat those in the afternoon.

And certainly, you know, that would be our hope that

we'd be able to just simply rely on what was said this

morning, and that goes for both the general

presentation and also for legal submissions as well.

I think that would simplify the afternoon process.

Proceeding Time 9:14 a.m. T5/6

THE CHAIRPERSON: Yes, I think that's an important

question and it does speak to the fact, as I

mentioned, that this application really presents an

amalgam of the various issues, the three main issues,

and which as you suggest we separated for

administrative reasons. And also to try to be

responsive to Fortis’s request for the decisions that

are absolutely necessary on a shorter timeline, and

perhaps having more time for some other decisions.

And so we will consider the material, the

evidence presented, in this first session as being on

the record for the other sessions. But I think it’s

important that we try to stay focused, certainly in

terms of the questions on the various phases and I


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suggest to you that may be helpful in terms of

clarification as we move into phase 2. You know, you

may want to hit the highlights of the evidence that

relates to phase 2. And certainly during the written

hearing process you’ll want to deal with --

specifically with those issues as well.

MR. GHIKAS: Understood. Thank you.

THE CHAIRPERSON: So I’d ask Fortis, then, to proceed.

PRESENTATION BY FORTISBC:

MR. STOUT: Thank you, Mr. Chairman. Ladies and

gentlemen, good morning.

As I said, my name is Doug Stout, and I’m

responsible for the energy solutions and external

relations group for the Fortis Utilities. So, the

natural gas transportation initiative falls within

that area.

And so I just thought I’d make just a

couple of brief comments before we start into the

presentation. Chairman Kelsey went over the history

of the -- a lot of this, and I think it’s quite

germane to the whole thing. We’ve been pursuing this

transportation initiative since 2008 when we first

discussed it in our resource plans that were filed at

that time. And through a variety of subsequent

regulatory filings and initiatives, and we’ll go over

those in more detail through the presentations this


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morning.

But we’ve taken this on as a very important

initiative with our business context, to deal with the

issues of declining volumes on our system and use by,

call it traditional gas customers over the years. And

through those -- kind of laying out those different

frameworks that we’ve put out, and over the four

ensuing years here have kind of refined that business

model with input from industry, input from the

Commission and ourselves, as we move along this, as

this is an evolving, I think, industry in process, not

only here but across Canada.

And we’ve taken this on really to deal, as

I said, with those declining throughputs and how do we

maintain the use of the system to the benefit of all

customers. We initiated the first of incentives that

we rolled out under our energy efficiency and

conservation program in roughly 2010, 2011, and we’ll

talk a little more about that this morning. The

Commission later denied those incentives as part of

the energy efficiency and conservation programs, and

so we’re dealing with those in this proceeding as well

in the later phases.

It was subsequent to that decision on the

energy efficiency and conservation initiatives that we

entered into discussions with the provincial


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government around the GGRR. And that evolved over a

number of months into the regulation that was rolled

out this spring.

And so on this front we’ve got two

presentations to go through today as we talked about.

One on the incentives this morning. That will be

about 40 minutes or so. And another one this

afternoon that will deal with the fueling station

issues. Again, about the same amount of time frame.

So the folks we have on the panel today

were introduced. I’ll deal with policy and company-

related issues. Dave Perttula will go over the --

kind of run through the history of where we’re at and

roll out the specifics of the GGRR and the approvals

we’re looking for here. Jason Wolfe will be able to

talk about the ongoing incentive process, so we have

some more information on that program as it’s in the

first phase at this point in time, so it gives some

more context there. Michelle Carman will take on the

heavy task of answering all the kind of rate-related

and accounting-related issues, and Mark Grist will be

able to handle the discussions around customer-related

issues and what’s going on in the marketplace.

So we view this -- you know, the decisions

that are going to come out of this process, and

hopefully some others here that are ongoing, as very


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critical to how we manage the business in our -- the

gas business in B.C. moving forward. And it’s within

this process that we think it’s really critical that

we get a lot of clarity around how things are going to

work, enable us to move forward and enable the

marketplace and the industry to move forward. And

that’s, you know, kind of what we’re looking for

today. We think it’s critical to the company, it’s

critical to our customers, and it’s critical to the

government in understanding how this program will be

undertaken and how we’ll be able to move forward into

the future.

So with that, we’ll turn the presentation

over to Dave, and folks will be able to introduce

themselves a little more fully when they go up and

start their part of the presentation.

MR. PERTTULA: Good morning, everyone. As we’ve heard

already, my name is Dave Perttula, and the way we’ll

be doing this presentation, we’re going to be moving

back and forth a bit between the different presenters.

And so rather than having us walk up to the front and

take the microphone up there, we’re going to do it

from a seated position like this. And I’ll let people

on the phone know what slide we’re at. It should be

fairly obvious, but I’ll try to keep people on the

phone apprised of where we are.


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So just very quickly for the agenda in this

session, the presentation will look first at the

approval sought, and Commission Kelsey went through

those in detail so we won't labour on those; look at

the background and context and then dig into the

details of the GGRR more specifically; and then we'll

get into the heart of the issue which is the

accounting treatment going forward. And then

following that a brief discussion of what we are doing

and what we're planning to do in terms of programs,

and then we'll have an opportunity for questions and

answers at the end. However, as Commissioner Kelsey

mentioned, you can interject with questions along the

way.

So I'm moving to slide 3 which is the

approval sought, and this is a high-level summary of

that. We're basically looking for approval of the

proposed accounting treatment for vehicle incentives,

and the basic general principle is that it would be a

rate-based deferral account with ten-year amortization

in the rates of non-bypass customers. And then we

have an initial period where, because our 2012 and '13

revenue requirements are already established, we're

having an initial period where it's in a non-rate-base

deferral account attracting AFUDC and then brought


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into a rate base at the beginning of our next revenue

requirement period, 2014. And so the balance would

then -- that's in place at that time would begin to

amortize.

There are some things that are established

by the regulation itself and by Section 18 of the

Clean Energy Act. And so the Ministry determinations

are that the approval of the spending amounts are set

out in the GGRR, and the timing of spending has in

effect been established by that. Meaning that the

spending can take place within the envelope -- or the

period of time that ends with the March 31st, 2017.

Also the reporting requirements are to the Minister as

set out in Section 18, and so those are sort of the

high-level picture of what we're discussing today.

And then I'll pass the clicker off to Mark

Grist here to move into some of the background. Sorry

if you couldn't hear that on the microphone there.

MR. GRIST: Good morning. I'm Mark Grist and I'm a

senior manager of business development. As such I

have a small team at Fortis that's responsible for

developing the products and services that our

customers are going to need into the future, with the

focus also of making sure that we ensure the long-term

health of the utility system in terms of load and

competitive rates for all our customers.


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At this point in the presentation we

thought it would be useful to spend a little bit of

time talking about the business environment and some

of the customer context that has formed the basis and

some of the background for the development of the

Greenhouse Gas Reduction Regulation.

Apologies for that. So, with respect to

our traditional markets, as you can see from the graph

on the left we do face some challenges in our

traditional energy delivery market. This is an

example from the residential context. And if you look

at the line on the left graph that trends from the top

left down to the bottom right, you can see that the

average use per customer -- use per household, has

been declining, from roughly 105 gigajoules per

household per year down to around 90 gigajoules per

household per year. That’s really the result of

advances in building envelopes, tighter building

envelopes, better insulated homes, and higher

efficiency appliances such as furnaces. That decline

has been partially offset by customer additions, but

as you can see in the graph on the right corner, the

net effect is that we’re facing some drops in the load

from our traditional markets.

That really is the reason why we are


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interested in developing natural gas applications for

our -- within our customer base. It’s basically to

add load to keep the utility system healthy so that we

can keep our rates reasonable for all our customers.

We feel that the development of the natural

gas market provides benefits for all the stakeholders

involved, and this slide basically covers that in the

summary form. Working from left to right, across the

slide, on the production side the development of the

B.C. natural gas resource base creates economic

benefits, of course, and that translates into things

like tax revenue and royalty revenues for the

province.

On the transmission and distribution side,

the more efficiently we can utilize our existing

resources that translates into delivery rate benefits

for all our customers.

With respect to the end user, the natural

gas for transportation fleet customers, they benefit

by having delivery of a lower-cost fuel for operation

of their vehicles. And the operation of those

vehicles results in greenhouse gas reductions within

our communities, to the tune of about 20 to 30

percent, versus diesel fuel. As well as reductions in

criteria air contaminants, such as particulate matter,

SOX, NOX, carbon monoxide, and that sort of thing.


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So across the full spectrum we feel there

is benefits to all stakeholders.

From the utility perspective, when we look

at natural gas as an end use in transportation, it’s

really quite comparable to all the other uses that --

the myriad of uses that our customer base uses natural

gas for today. We’re delivering gas to customers who

use it for space heating, for water heating, for

customer -- for cooking, for patio heaters, perhaps

for industrial processes as a feed material, and

transportation is just another application from the

utility’s perspective in delivering gas to customers.


It does have one attractive feature though,

as unlike most of our applications which are quite

seasonal in nature, the load delivered from the

natural gas for transportation area is nice and flat

and it's quite attractive as far as a system

utilization perspective goes.

Okay, so I'm going to change gears here a

little bit and talk a little bit more about the

customer perspective and all the elements that are

required to deliver a usable product to the customer.

So, you know, we start at the production end and the

collection of the gas in the transmission system and

it's distributed to the customer's site, at which


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point -- I'm talking about the CNG chain here. At

which point it goes through a compression service,

through some intermediate storage, through a fuel

dispenser, and ultimately it's delivered into the

customer's vehicle. And that's the point at which it

becomes useful for the customer.

On the LNG side it's much the same. We

take gas off our transmission system, put it into --

run it through a liquefaction process where it's

chilled into a liquid form. It's trucked out to the

customer's site using tankers. There is local storage

and dispensing through a fuelling station at the

customer's site, and again it becomes important to the

customer where it's delivered into his vehicles.

This morning we're going to be talking

primarily about the provision of the vehicles and the

barriers that customers face in trying to adopt

natural gas vehicles.

So looking again at it from a customer

perspective, when he's looking at natural gas for

transportation he's comparing it to diesel fuel.

Diesel fuel has most, almost all of the market for

heavy duty transportation uses. So a customer when

he's looking at vehicles is comparing it to the cost

of a diesel vehicle, and there's a big barrier there

because the cost of a natural gas vehicle ranges from


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about $40,000 more to about $100,000 more. So that's

a pretty big barrier for a customer to buy into.

The other thing that makes it quite

difficult is for a diesel vehicle he can just drive up

to any card block and get fuel, without any sort of

long-term commitment. To get natural gas for his

vehicle under the terms of the tools that we've been

working with, he basically has to sign up for a very

long-term commitment and cover 100 percent of the

costs associated with building the infrastructure to

fuel those vehicles. Those are two pretty big

barriers to get across, and that's really what the

Greenhouse Gas Reduction Regulation is designed to

help us address. If we're going to get the greenhouse

gas reductions, we have to get adoption of those

vehicles into the customer markets, and so the GGRR is

really designed to help us address those two primary

barriers.

So with that business and customer context

in mind, I'll now turn it over to my colleague here

who will take us through to the next step of the

presentation.

MR. PERTTULA: Thanks. It's Dave Perttula again. For

folks on the phone we're at slide 9 entitled GGR

Background Timeline, and it's quite a busy chart, as

you can see, and Ilva is just handing out larger


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versions of that for the benefit of those of us that

are visually challenged.


But there's quite a number of policy

issues, pieces of legislation, and regulatory

proceedings that have surrounded this whole

initiative. Some of you may recall, starting from the

left, in 2009, we had proposals with respect to

natural gas vehicles in our 2010/2011 revenue

requirements application, but those were settled by a

negotiated settlement process and we ended up taking

those off the table in that particular situation, but

without prejudice to bringing those forward in future

applications.

Then the next item on the list is the Clean

Energy Act, which came in in about the middle of 2010.

And the Clean Energy Act has in it references to

natural gas vehicles and first of all Section 18 and

35(n) of the Clean Energy Act deal with natural gas

vehicles and greenhouse gas reductions. And the --

actually the government announcement that came out

when the Clean Energy Act came into effect was -- one

of the points was the promotion of natural gas and

electricity in vehicles. But, so, there was support,

definite support for the use of natural gas and

vehicles in the Clean Energy Act.


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We began working, as people are aware, with

the prospect of providing incentives under our EEC

programs, and felt that we had a basis for doing that.

And so the earlier incentives that are part of Phase 3

of this program are -- we were dealing with customers

on those and made commitments to provide those in the

period of September, 2010 to March, 2011.

We filed our first application for a

station for waste management and general terms and

conditions a little later -- that was the beginning of

December, 2010. And the waste management decision

came out July 20th of 2011. And in the meantime, we

had filed our 2012 and 2013 revenue requirement

application in May of -- May 4th of 2011. We also went

through an incentives review process under EEC, which

led to the decision, as people are aware, that we

could not provide those incentives under EEC because

they didn’t meet the definition of a demand-side

measure.

After getting that decision, which was in

the middle of August, 2011, we filed a revenue

requirement update and we removed the effects of our

forecasts for NGV from that -- or from the stations

and incentives. We removed that from the revenue

requirement going forward.

But it was the incentives decision in the


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middle of August that spurred our proposal to the

government, which began in September of 2011, and the

government conducted consultations over a five- to

six-month period between September and roughly March

of 2012.

In the meantime, more towards the end of

that period, the province issued natural gas and LNG

strategy documents which again had support for natural

gas for transportation. In fact the incentives

program that we're talking about this morning was

mentioned in there.


The other thing that -- next on the list is

the general terms and conditions which we had applied

for back in the waste management application, and so

that was finally approved with somewhat more stringent

conditions than we had originally sought in that

application, but in February of 2012.

Next the revenue requirement decision came

out in mid-April of 2012, and shortly after that a

decision on our BFI fuelling station, that was May 1st,

and we asked for reconsideration of some aspects of

that, most notably the requirement to have all the

stations in different classes of service from the

natural gas customers. And then shortly after that

BFI decision the GGR was enacted. So about a little


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less than two weeks after that was the official

enactment date.

We also, a bit later as we move along, we

filed our Rate 16 application. That's what went in in

September. And Rate 16, just for everyone's benefit,

is around our provision of LNG service. It's been a

pilot program with interim approval or temporary

approval, and so if we're going to expand the LNG

offerings in particular, we need to move that into a

more permanent -- into a permanent status and with

expanded capability.

And then just in the last couple of weeks

we've had a decision on the Vedder LNG Station and

also the BFI reconsideration decision, Order G-150,

and then that brings us to today in terms of the

hearing that we're having here, the streamlined review

processes that we're having on the GGRR. And I think

just from looking at the picture here, the timeline,

we can see that there's a lot of issues that are

interrelated with each other. But it's our view that

the things that we're applying for today can be

determined and that will give us the basis for moving

forward with these programs and expenditures.

I'll just move very quickly to the

regulation itself, and if you've got the application

with you, the actual text of the regulation is in


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Appendix B of our application. And so it consists of

an introduction and definition section, Section 1 of

the Regulation. That sets out the types of vehicles

that are involved, and so included are heavy duty and

medium duty trucks, school buses, transit buses, and

marine vehicles. And so for the first group, the ones

that are specified as eligible vehicles or -- I'm

sorry, a specific vehicle, just to be technical here,

they have to be sort of factory-built vehicles. So

they can’t be retrofitted, whereas the same provision

doesn’t apply to the marine vehicles.


The definitions also include things around

safety guidelines, the truck tanker load-out for --

that’s part of prescribed undertakings 2 and 3, and

then also that the undertaking period goes to March

31st, 2017.

Just to put some pictures to these vehicles

that we might be providing these incentives to, the

next slide has four, two for CNG and two LNG. So

there is a waste hauler, as a CNG example, or a

transit bus also as a CNG example. And then on the

LNG side, you’ve got the Class 8 tractors, or ferries

are given as an example on this page as well.

And then just to put prescribed undertaking

1 in sort of a picture format, we’ve got a pie chart


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here of what’s involved. And just for people on the

phone, we’re on slide 12.

So, the overall envelope of spending in the

prescribed undertaking is $62 million, in the title of

the pie chart there. And we have an envelope of $11

million for marine vehicles. We have our prior

spending of $5.6 million in there that we propose to

include as part of the envelope of spending, and then

the yellow wedge there is for grants for safety and

maintenance upgrades for parties that adopt the NGV

vehicles, and then lastly we’ve got a bucket of

administration, marketing, training, and education of

3.1. And sorry, I missed the biggest blue part, which

shows up for the trucks and buses of being 38.3

million.

Now, if we -- for example, if we didn’t

spend the entire bucket for the marine vehicles of $11

million, that money could be redeployed to fund other

trucks and buses in the big blue bar there, or the big

blue wedge. Similarly, if we didn’t spend all the

money for safety and maintenance, or the

administration and training buckets, those -- the

amounts that we haven’t spent there could be

redeployed in incentives for the trucks and buses.

So, beyond the spending envelopes, the

prescribed undertaking sets out caps on the amount of


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the price differential between vehicles that we can

fund on a year-by-year basis. There is a schedule

that starts out with 100 percent, being able to fund

100 percent of the price differential, and then that

scales down to 80 percent and then goes down by 10

percent a year after that.

And so, I think in essence that’s the

summary of prescribed undertaking number 1 for the

vehicle incentives that we’re here to talk about

today. And I’ll pass the baton over to Michelle here.


MS. CARMAN: Thanks, Dave. So, as mentioned a couple of

times already this morning, what we're actually

seeking approval for in this application is the

accounting treatment of these costs and the recovery

of the program costs as well as the grants. So this

little graphic just shows a simple picture of what

we're asking for. So we're going to use a rate base

deferral account to capture those incentives as well

as the costs; an amortization period of ten years

through the delivery rates of all non-bypass customer.

Now, future revenue requirements, we will forecast the

incremental throughput associated with this program,

so non-bypass customers will also receive those

recoveries through their delivery rates as well.

The next few slides, I'm going to go


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through each of these points in a little bit more

detail. So for those on the phone, we're on slide 13

and I'm now moving to slide 14.

So the first point I'd like to stress,

although we fully intend to spend the full $62

million, it will only be the actual incremental costs

incurred as well as the actual grants provided that

will be recovered through the deferral account and the

delivery rates of non-bypass customers.

And another point I'd like to clarify,

we're using the word "incremental" a lot, and it's

incremental in the context of these items were not

contemplated in the 2012 and '13 revenue requirement,

as my colleague Mr. Perttula referred to earlier.

There is a really great -- a question that was asked

and a response that was provided in terms of evidence

to this fact, and at a high level really it goes back

to the timing. So that great time limit that Mr.

Perttula took us through. We filed the revenue

requirement application more than a year in advance of

when the regulation was actually enacted, and further,

we had actually conducted updates to the revenue

requirement to reflect the NGV incentives decision.

And what that resulted in is no NGV incentives

included in our EEC, or either any additions to the

NGV incentives, existing NGV incentives account that


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we had in the revenue requirement application.

So this timing, in terms of the fact that

things are now happening in '12 and '13 that were not

forecast, actually leads us nicely into the

requirement for a deferral account. From our

perspective, a rate-based deferral account is

appropriate for several reasons. So starting actually

on the far right there, that pinkish reddish box, this

treatment is entirely consistent with most of the

deferral accounts that we have in place. Most of our

deferral accounts are rate-based deferral accounts.

It's a consistent treatment for costs of this nature.

It's familiar to the Commission, interveners. It's a

method that allows a utility to recover the costs as

well as a fair return.

Now, specific to this case, these grants

really represent an investment in the long-term health

of our system. And what I mean by that is, it does

add additional throughput to the system, helping us

address the issues of declining throughput that we are

facing. Again in this particular case, the grants are

similar to long-term assets. It's a long-term program

with benefits associated with the vehicles that are

being incented for purchase, and in fact there is in

the contribution agreement which I believe is Appendix

I of the application -- somebody will correct me if


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that's wrong -- that FEI actually does have a security

interest in the vehicles themselves.

For 2012 and '13 this account will be non-

rate-base. As mentioned before we've already set

delivery rates for 2012 and '13. The account will

attract AFUDC and will transition to rate base

effective January 1, 2014. So the only reason that

we're asking for a non-rate-base account attracting

AFUDC is because delivery rates have already been set.

So the application of AFUDC to this account is

entirely appropriate because it represents the funding

required until it goes into rate base and it mimics

the return that would be received once in rate base.

Alternatives to rate-base treatment were

considered in some of the IR responses, notably in CEC

6.1. We explained that we also looked at an annual

expensing of the grants and the costs. So certainly

an annual expense approach is going to result in

higher rate impacts, but it certainly does perform

well in terms of recovery of the costs. Where we fall

a little bit short with the annual expensing is it

doesn't match the recovery of the costs of the program

with the benefits, the period of the benefits over

which we expect to enjoy those benefits.


And that actually leads in nicely to the


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next issue. So, the amortization period. When we’re

deciding what an appropriate amortization period would

be for an account, we take several factors into

consideration. So in this case we are looking to

balance a reasonable period for recovery of the costs,

the average expected life of the vehicles that are

being incented, the duration of the benefits

associated with those vehicles that are expected, or

that are incented, and it’s last on this list but it’s

certainly not least, is rate volatility.

So when we took all of those into

consideration, a ten-year amortization period provided

the best balance of all of those objectives. Now, we

did consider alternate amortization periods.

Specifically in the BCUC series -- I can’t think of

the response off the top of my head here. I’ve gone a

little bit blank. It will come to me eventually and

I’ll shout it out for you.

But we did look at a five-year amortization

period. So, similar to an expensing approach, it’s

great in terms of being able to recover the costs in a

shorter time frame. But where it loses out to a ten-

year amortization period is that matching, again, of

the costs and the benefits. So what this graph shows

you -- on the left is an amortization period of ten

years. The graph on the first is an amortization


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period of five years. And for those on the phone, my

apologies, we’re on slide 17. And moving a bit

quickly here.

And to clarify, what we’ve done for

purposes of showing how there is better matching under

a ten-year period is just to reflect the incentive

costs themselves as well as the vehicles that are

being incented. So that the red line that we see --

so it’s rate impacts. The red line that we see are

the costs over the time frame. The blue line on the

bottom are the delivery rate benefits associated with

these incentives. And the reason that they’re the

same is because they’re the same in both cases. The

benefits occur over that -- the identical period.

And what the smoother line in the ten-year

graph shows is that there is a better alignment of

costs and benefits. So the flatter the line the

closer that your costs and benefits are matching.

Furthermore, it also indicates less rate volatility.

So, when compared to a five-year

amortization period, although, yes, we recover the

costs faster, it does not perform as well as a ten-

year period in terms of matching those costs with the

benefits or in terms of rate volatility.

Does anyone have any questions about the

graph? Sometimes charts can add -- questions? No?


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Okay.

So in the same vein we also investigated

20- and 30-year amortization periods. So, absolutely

the longer you spread out costs the better it’s going

to be for rates. There is going to be less rate

volatility. However, again, in terms of matching the

costs with the benefits, what we’re trying to isolate

here are the benefits associated with the vehicles

that we’re incenting. And the average life of those

vehicles that we’re incenting is approximately ten

years. So this is a repeat of the vehicles that we

showed earlier above providing you with the average

life for each of these categories.

THE CHAIRPERSON: I do have one which I consider to be a

clarifying question. And that is, when you talk about

matching the costs with the benefits, are these costs

just the incentive costs or are they the costs that

reflect the interest charges, the other charges on

those incentives?

MS. CARMAN: Yeah. So it’s the full cost of service

impacts of putting the incentives in a deferral

account and amortizing them over that period.

THE CHAIRPERSON: Thank you. Thank you.

MS. CARMAN: It’s -- oh, yes?

MS. DOMINGO: So earlier you said to have a longer

amortization period, clearly you’re going to have a


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lower rate impact. And I think the IR question you

were, I think, looking for was BCUC 1.10.1. Is that

the one where --

MS. CARMAN: Let me take a look.

MS. DOMINGO: Sorry, it’s Yolanda Domingo.

MS. CARMAN: Yes, that’s correct. 10.1 is where we

compare to the five-year.

MS. DOMINGO: Right. So you’ve got the five-year

comparison. So it looks like -- I mean, would you

agree that it -- I mean, the rate impact is still

relatively small, even if we go to a five-year. I

mean, I think it ranges from about half a percent in

the first year and ranges up to 1.5 percent in, say,

the worst-case year, if you will. But I suppose maybe

the shorter -- would you agree, maybe the shorter

amortization period will have -- will lessen the

carrying costs in the deferral account, and given that

the rate impact isn’t that much, are you -- would the

company be opposed to a shorter period at all?


MS. CARMAN: So, certainly the shorter amortization

period lessens the carrying costs. But on a

discounted basis the total cost of service associated

with the deferral account is roughly the same.

Now again, from our perspective we think

the ten-year amortization period is appropriate


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because it matches the duration of the benefits. So

we're expecting, you know, the benefits from those

vehicles, they last -- the vehicles last about ten

years. You know, from our perspective it's -- you

know, the costs over ten years is reasonable.

MS. DOMINGO: Okay, and --

THE CHAIRPERSON: Can I just interrupt for a second. I

think we're at this stage, with all due respect, we're

moving beyond clarifying questions and we're getting

into questions which I think are probably more

appropriate to ask during the formal question period.

MS. DOMINGO: Okay.

THE CHAIRPERSON: So I'd ask that -- I'm qualifying my

question as a clarifying question. I hope that was a

reasonable designation for that particular question,

but I think we'll wait with a question of the nature

of the one that's just been asked for the question

period.

I also recognize that I violated one of my

rules and that was I didn't indicate who was asking

the question, and so I'll remind people to identify

themselves before they ask the question. Thank you.

MS. CARMAN: Okay, then I'll continue on. This is the

last point in that circle that I provided. So the

cost recovery that we're proposing is from all non-

bypass customers, and as well the benefits of the


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program go to all non-bypass customers. And from our

perspective, that's required in order for this program

to be successful. If costs were only recovered from

those customers who receive grants, it effectively

turns the grants into loans, and the expected uptake

in the program and the associated GHG reductions would

not be achieved. So from our perspective it's very

important that these costs are recovered from all non-

bypass customers.

So further, the intent of the regulation is

to reduce greenhouse gas emissions for the benefit of

all customers in the province, and all customers

actually benefit from the incremental throughput on

the system. So it's actually one of those win-win

scenarios where, yes, there are costs associated with

the program, but in the long term there are not only

greenhouse gas emission benefits, there's also

delivery rate benefits that will flow to our non-

bypass customers. So therefore it follows that those

costs should be recovered from non-bypass customers.

So I'm now going to pass things over.

MS. SUE: (inaudible)

MS. CARMAN: Yeah, that's the cumulative, so that the --

MS. SUE: In years?

MS. CARMAN: In the year 2030. So that for the period of

the analysis that we provided in the application


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there's an expected delivery rate benefit of --

delivery rate reduction of 5.6 percent cumulative by

2030.

MS. SUE: Thanks.

MS. CARMAN: You're welcome.

MR. WOLFE: Hello, I'm Jason Wolfe. I'm a director of

market development and my team at Fortis is looking

after the actual disbursement of the incentives. So

it might not be quite as exciting as a regulatory

accounting, but I'm going to go through the power

providing incentives.

After we received the regulation, we had

been working prior to that about looking at what the

program would be like and wanted to catch you up on

where that was today. Even though it's not entirely

within this application, I think it's instructive to

understand the demand and what our customers are

seeing and wanting out of this program.

You saw -- we're on slide 20 and you saw

the pie chart on the right there already, that the

total bucket of funds that we're talking about today

are the 62 million. The largest bucket of that, of

course, is for the trucks and buses, a smaller bucket

for marine incentives. Safety and maintenance

incentives and then the admin marketing and for the

third phase, the demonstration round of incentives.


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In June, late June of this year we put out

the call for the incentives. It went out to a large

number of our customers. That was for the incentives

for the marine and the trucks and buses. For the

safety and maintenance upgrades we have not determined

that incentive process yet and we haven't started

that. That's primarily because we haven't -- we need

to understand where all the vehicles are going to be

used and what companies are going to take up the

vehicle incentives before we provide incentives for

maintenance and safety upgrades of the shops.


And right now, we haven’t put in place a

lot of effort on the administration, marketing,

training, and education. Again, we’re seeing where

the vehicles are going to first before we start

putting a program together for that.

We’re on slide 21 now. Again, in June, we

sent out an email to our email list of all the

trucking companies and interested parties in this.

That list of about 500-plus companies, trucking

participants. Of that, we have 19 applications that

we received. So that’s it. The big uptick from the

couple of customers we have right now being Vedder

Waste Management and BFI. But certainly there’s a lot

of room to grow this market. We’re happy that we had


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19 applications that were well put together by

customers.

On the charts, or the graphs, pie charts on

the right-hand side, the requests that came from the

customers on the trucking side was 25 million, 25.8

million. The larger component of that being the LNG,

a little smaller on the CNG. LNG trucks do cost a

little bit more than -- on an incremental basis, so

that was quite expected.

On the number of trucks, the pie chart kind

of flops the other way. There are more CNG trucks,

again, but at a lower cost, 258 of those, and 165 of

the MR. CANNING: -- or LNG trucks. And this is

just what came in the application initially. And then

there was one marine application asking for $3

million. However, marine applications are quite

expensive, and the actual incremental cost on that

marine application is 12.4 million.

If we move to the next slide, slide 22.

After receiving those applications and going through

the initial phase of the screening process, which is a

multi-phase process that was overseen by fairness

advisor and we also had consultation with government

about where we were on the process, and how everything

was proceeding, and what we were doing, out of that

initial list of -- on the previous slide -- of 428


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vehicles, 401 vehicles are preliminary awarded. And

when I say “preliminary”, there are still a number of

steps left that we have to conduct with our customers

before they will actually receive the incentives.

First off, we need approval for the rate recovery

treatment under this proceeding. We need -- for LNG

vehicles, we need approval of rate schedule 16. We

have further due diligence to conduct with the

customers. And once all that’s completed, as my

colleague, Ms. Carman, noted there is a contribution

agreement that must be signed by the customer. So

this is only a preliminary award, less than we do

expect the numbers to change slightly as business

requirements of our -- of the participants are

factored in as well.

But all that, we have 401 vehicles now, and

the total incentives are 12-point -- sorry, 21.7

million, with 3 million for marine, 7.8 for the CNG

and 10.9, nearly 11, for the LNG.

We’ve spoken a lot today about the volume

and the benefit to customers of that volume on the

system, and the pie chart on the lower right-hand side

speaks to how much volume is coming on the system, at

least with this preliminary award list. And there is

quite a significant load, especially on the LNG front.

There is nearly 850,000 gigajoules, and 250 on the CNG


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and 150 on the marine.

MS. SUE: Suzanne Sue. Jason, is the marine LNG or CNG?

MR. WOLFE: Sorry, yes. Yes, sorry. The marine is LNG.

MS. SUE: Thank you.

MR. WIGHTMAN: James Wightman from BCPSO. What’s the

percentage increment and total load that that 1.25 GJs

represents?

MR. WOLFE: On our system load?

MR. WIGHTMAN: Yes.

MR. WOLFE: Our system load is -- correct me -- if

someone can clarify if I’m incorrect, it’s around 200

GJs annually.

MR. WIGHTMAN: So this is about .6 percent increase.

MR. WOLFE: Yeah. When we talk about the size of the LNG

facilities, just the tank itself at Tilbury is .6.

BCF or close to 600,000 gigajoules, and on the island

it’s 1.5 or close to -- or 1.5 million gigajoules.

That’s just storage, that’s not liquefaction capacity,

because uses some scope and scale of how much LNG at

least is going to be required for these customers.

MR. NAKONESHNY: Jason, this is Philip Nakoneshny. With

regards to the LNG, the demand part, does that relate

to the contract commitments that are supposed to

happen with the incentives?

MR. WOLFE: Just a preliminary indication of what they

are. Once they sign a contribution agreement, then


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that number will be firmed up.

MR. NAKONESHNY: Right.

MR. WOLFE: This is just the initial indication. We need

to confirm with the customers their actual load and

that’s in the further due diligence that we’re doing

with those customers. So that may change.

MR. NAKONESHNY: Right.

MR. WOLFE: As well as if the vehicle numbers change.

MR. NAKONESHNY: But it’s the forecast right now.

MR. WOLFE: Yeah.

MR. WEAFER: Sorry. Chris Weafer, CEC. Under the

regulation, there is an envelope of $62 million that

we’re talking about here, and there is also another

$40 million envelope for LNG. So --

MR. WOLFE: Sixty-two, if I can -- 62 is the envelope for

the incentives funding. The other 40 that you’re

talking about is for stations.

MR. WEAFER: Okay. So when we look at this discussion

and the awards list, there is no -- we’re not moving

into that $40 million envelope. This is still all

within the 62.

MR. WOLFE: And as a clarification, that $40 million

isn’t incentives. That’s the allowance which we’ll be

discussing more this afternoon under the undertakings

2 and 3 for the building of stations.

MR. WEAFER: Okay.


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MR. WOLFE: So 62 million is the actual incentives, of

which a small portion, the 3.1 is admin. But the rest

pretty much make up all the incentives.

MR. WEAFER: Right, okay, so when we talk about it in

this context it's still within the $62 million

envelope. That's all I'm just trying to correct.

MR. WOLFE: Yes.

MR. WEAFER: Okay, thank you.

MR. WOLFE: And if we move on to slide 23, what's showing

right now is the left-hand graphs, and when we

initially met with the government we set out kind of

an expectation of how many vehicles, how much volume

we would expect to go through the system. And what

you're seeing here is an actual from the preliminary

award list to -- versus what was proposed or what we

thought would happen when the development of the

regulation was occurring. And so you can see, and at

least in this initial call, based on the same time

frame, the CNG is quite close to what we expected to

come forward on an actual litres displaced, but the

LNG is much more and what we're seeing there is that

the trucks that have so far applied to the program are

using -- are expecting to use much more volume than

what we were thinking of. That's just because of the

requirements of those specific customers.


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And so just on the average there, the

average on the preliminary award list of litres

displaced per dollar incentive is much greater. So

we're quite excited about that. That means greater

greenhouse gas reductions.

And then on the average annual GJs per

vehicle, sort of what I was speaking to earlier, the

CNG is pretty close to what we expected but the LNG is

much higher, and that's just due to the nature of the

trucks that -- vehicles that have applied thus far.

That might change, or will likely change at least a

little bit once we firm up the fuelling demands.

And that's it for my part of the

presentation. And that concludes the presentation

component of the day.

I think now, Mr. Chairman, do we turn this

over for questions?

THE CHAIRPERSON: Yes, I think we can begin with

questions, although I note that it's quarter after

ten, and rather than cut into the question period at

some point I think we might be wise to take a short

break at this stage and come back at 10:30 and begin

with questions at that point.

Mr. Bemister, what arrangements -- oh, Mr.

Bemister is not here at the moment. I was just going

to ask him what arrangements we would make regarding


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the telephone connections, but I presume we'll leave

those in place and so our telephone participants can

simply join -- rejoin without having to dial in again.

Okay, so 10:30, thank you very much.

(PROCEEDINGS ADJOURNED AT 10:15 A.M.)

(PROCEEDINGS RESUMED AT 10:32 A.M.) T19

THE CHAIRPERSON: Thank you, Mr. Bemister.

Mr. Fulton.

MR. FULTON: Yes, so before we move into the questions

and answers, if we could mark the slide presentation

Exhibit B-7.

(SLIDE PRESENTATION MARKED EXHIBIT B-7)

MR. WOLFE: Mr. Chairman, if I may, there's a question

from Mr. Wightman about the volume on the system.

THE CHAIRPERSON: Yes.

MR. WOLFE: The actual numbers now from our staff. So

the actual volume on the system that the total

throughput on the system is 206 petajoules. However,

the non-bypass customer volume is 160 petajoules.

THE CHAIRPERSON: Thank you.

MR. WIGHTMAN: James Wightman, BCPSO. What was that last

number, please?

MR. WOLFE: 160 petajoules for the non-bypass customers,

and that's what we are talking about in regards to the

rate mechanisms and the collection of rates.

MR. WIGHTMAN: So this would be still less than a 1


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percent increase in surplus.

MR. WOLFE: .78.

MR. WIGHTMAN: Thank you.

MR. WOLFE: And that's just from this first round of

incentives.

THE CHAIRPERSON: Thank you, okay, we'll move to

questions then, and I'll just ask or I'll invite the

first question. Who has the first question?

MS. BRAITHWAITE: I guess I'm first. Tannis Braithwaite

for BCPSO.


MS. BRAITHWAITE: Is it the position of the utility that

the Commission cannot order a program based on

interest free loans as opposed to grants for the

vehicle incentives?

MR. PERTTULA: Yes, it would be our position that the

regulation allows either zero interest loans or

grants. So it's at the utility's election basically.

So not the Commission's determination.

MS. BRAITHWAITE: And are you basing that position on

Section 18 of the Clean Energy Act or --

MR. PERTTULA: Yes, on the basis of the regulation, the

regulation itself.

MS. BRAITHWAITE: Is it the utility's position that the

Commission is restricted from looking at the prudence

aspects or public interest aspects of the regulation


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and the incentive process overall?

MR. GHIKAS: Matt Ghikas. I can take that one again.

It's sort of a legal one. Yes, and I will deal with

it in submissions, that the scope of the review is not

one to determine whether we need to award the

incentives at this time, and it's not the Commission's

role. It's also not to determine how the funds were

disbursed under the regulation. But I'll elaborate on

that.

MS. BRAITHWAITE: Okay. In the -- I think it was in the

CPCN process for the Vedder, there was evidence that

Vedder was achieving fuel savings in the range of 35

to 50 percent of their costs. And based on a very --

the most conservative calculations with the evidence

provided, I think that came out to about $1.4 million

a year in savings running their trucks using LNG over

diesel. Is there anyone on the panel that can confirm

that?

MR. GRIST: Yes, I can confirm that the fuel savings for

the customers are very substantial. I would like to

elaborate a little bit more though with respect to the

customer's business case evaluation when adopting

natural gas vehicles. And Ilva, perhaps I could have

the slides that address that brought up. This might

take a couple of minutes.

Okay, so when we're looking at a customer


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like Vedder and their evaluatons on whether to adopt

the natural gas vehicles in their fleet or not, it is

a very complex business decision and involves a lot of

factors for them. Fuel price and fuel savings is

obviously one big component of that, but there's also

a number of other issues that have to be factored into

their overall business case.

First, the vehicles that we're looking at

are expensive and we're talking about, you know,

capital cost premiums to acquire the vehicles for

Vedder approaching $100,000.


Then there's fuel availability concerns,

which greatly restrict where they can operate those

vehicles, and what they can do with those vehicles.

Related to that, there is issues with respect to what

sort of salvage those vehicles might have at the end

of their life. You can’t just sell them because there

is no secondary market without a fueling source. And

so that affects their end-of-life economics.

But probably the most important aspect that

we’re dealing with here is the dominance of diesel in

their business. All their competitors are running

diesel fuelled equipment. And so if they switch to

something new, they’re putting their business at risk.

Now, we believe that the natural gas


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vehicles are very strong, fairly well proven in the

market, and are very adequate to compete head-to-head

with diesel. But for that first guy to make that step

out and say, “Okay, I’m going to put my whole business

at risk here,” he’s going to have to have a fairly

good economic incentive to make him make that

decision. It’s not like somebody who is using natural

gas to heat their business, if they go to a new type

of furnace and the furnace fails, well, their

facilities go cold for a couple of days.

For someone like Vedder, if the trucks

don’t perform, they’re out of business. I mean, that

is their business. So, the risk/reward trade-off to

get those first guys to move to natural gas is

something that has to be very significant to get the

first movers to go. So, I know there is a perception

that those fuel savings and the economic business case

here makes it a no-brainer, and incentives shouldn’t

be needed. But that’s clearly not the case. Nobody

is adopting natural gas vehicles in this market

without the use of incentives. And so that’s why

we’ve gone to the point where we’re -- we’ve worked

with the government to get authorizations to provide

these grants to get those first movers to go.

Is there any questions with respect to

that?


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MS. SUE: Suzanne Sue, BCUC. Is there any questions from

the interveners?

MS. BRAITHWAITE: I just have follow-up questions about

fuel and savings for the other companies, but you can

go ahead.

MS. SUE: Okay, great. Are you speaking mainly of LNG

trucks or also MR. CANNING: , trucks that you need

this big benefit in order to adopt these vehicles

without incentives?

MR. GRIST: In that particular example, I was speaking to

the LNG business case. The issues are the same,

though, for the CNG business case. The incentives are

more -- sorry, the capital cost premium for the CNG

vehicles is towards the other end of that spectrum,

more around the $40,000 per vehicle as opposed to the

100,000 which is the LNG vehicles.

MS. SUE: All right. I will hand out two exhibits.

Please mark them as Commission Exhibit A2-1 and A2-3.

I’ll give Mark a few minutes to hand those

out.

MR. FULTON: Mr. Chairman, we should identify what A2-1

is.

MS. SUE: Okay. Oh, A2-1 is the Fleets and Fuels article

regarding Emterra in Winnipeg adopting CNG trucks for

their garbage business, and without any incentives

whatsoever. And A2 is the Abbotsford Council report,


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which awarded the refuse contract to Emterra also, to

the best of our knowledge, without incentives.

(FLEETS AND FUELS ARTICLE MARKED EXHIBIT A2-1)

(ABBOTSFORD COUNCIL REPORT MARKED EXHIBIT A2-2)

THE CHAIRPERSON: Sorry, may I ask just a clarifying

question here? And it has to do with this line of

questions. And I’m just curious to know what the

purpose of the line of questions is. What’s the

objective, in terms of the line of questions?

MS. SUE: Basically we’re asking questions whether

incentives were required, and basically who we should

pay, given especially that these customers undertook

the business without any incentives.


MR. GRIST: Just in response to that, I will respectfully

submit that the provision of the incentives has

already been authorized by the province -- by the

Minister, through the regulation. Nevertheless, I

think it would be instructive to respond to that

specific history with respect to the fleets and fuels

article, and provide you with a bit of context as to

how Emterra got to that point where they made that

decision for Winnipeg.


So there's a timeline involved here and a

bit of a story on this. If we go back to September of


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2010, as part of that demonstration round of

incentives, one of the successful applicants was the

City of Surrey who were interested in evaluating

natural gas vehicles and we provided them with

incentives to help them acquire a single vehicle that

they used in conjunction with Emterra, to get

comfortable with the operability of CNG in their

particular fleet operations. Over that timeframe we

spent a lot of time working with the City of Surrey

and their consultants to convince them --

Sorry, my colleagues just mentioned to me

that we've put up a slide that shows this timeline,

and both with this slide and the previous one we will

introduce that into the record and provide copies to

everybody, including everybody who's on the phone as

well.

MR. FULTON: Yes, so just on that point then, if we could

mark the first slide that related to the barriers to

adoption as Exhibit B-8, and the second slide headed

Incentive Program Design at Work, Emterra Example,

Exhibit B-9. Thank you.

(SLIDE RELATING TO BARRIERS TO ADOPTION MARKED EXHIBIT

B-8)

(SLIDE HEADED INCENTIVE PROGRAM DESIGN AT WORK,

EMTERRA EXAMPLE, MARKED EXHIBIT B-9)

MR. GRIST: Thank you. So after we helped them get their


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first vehicle, we worked with them to answer all their

questions about fuel costs, stations, the operability

of these vehicles, and we spent quite a bit of time

working with the City of Surrey. That led them to

become comfortable with making their requests for

proposals for refuse collection service. That

proposal included in it a requirement to use natural

gas vehicles.

So in the bid process that happened, BFI

actually won that bid over the incumbent. The

incumbent was Emterra. The successful bid by BFI was

$2 million a year below the cost of collection that

Emterra was charging the city at that time using

diesel fuel vehicles. So there was a changeover in

the service provider for the City of Surrey.

Subsequent to Emterra losing that business to a CNG

fleet, they quoted on business in Winnipeg, and our

conclusion is that they probably learned from that

process that CNG could provide overall savings to the

cities, and they quoted based on a CNG option, were

successful in acquiring that business based on the

CNG.

Now, circling this all back and what it

means with respect to our program, we believe that

this is a perfect example of how the program was

designed to work and how it is working in practice.


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We provided an incentive that led to a follow-on

decision for 52 vehicles to be added by BFI to serve

the City of Surrey. Those 52 vehicles were done

without incentives. That competitive pressure of the

CNG operator taking business from the diesel operator

resulted in a dynamic where the competitive pressure

forced that operator to go to CNG vehicles. They

learned from that, and it had follow on spinoff

benefits, not in our jurisdiction, but it's exactly

how the program is designed to be worked. That's how

the principles of how it is designed, so --

MR. WOLFE: And we think that the government, the

ministry saw this and put together a regulation that

provided that incentives could be distributed because

it was the surest way to advance a market and result

in greater greenhouse gas emissions in the shorter

period of time.

MR. STOUT: And I think when you look at the way the

incentives are structured to ratchet down over the

phase of the program, that's part of the whole idea

that the first movers enter the market, coupled with

future smaller incentives and some competitive

pressure, not unlike what happens with new implements

of all kinds under energy efficiency, you start to

drive the market towards the new norm. And that's the

goal of where you get to over time.


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MS. SUE: Okay, Suzanne Sue again. If you look at I

guess the exhibit, the Abbotsford Council report which

is A2-2 on page 3 or 4 under the heading "Strategic

Directions", they discuss the recommended proponent's

use of CNG in further support of the city's goals.

And please note that BFI and Emterra were the two

competitors -- were two of the competitors, and that

Emterra was awarded the contract and they will be

using CNG trucks. And has Fortis provided Emterra

with any incentives?

MR. WOLFE: Right now, or as I showed in the slides,

partway through the incentive process we actually

haven't granted any incentives yet because there are

still many steps to that process. Those incentives

will be granted once we get through this application

and some other components. As far as who is within

that pool of 19 customers, we can't mention those

names as of yet because we don't have any release yet

from those customers, and those customers haven't yet

committed to take an incentive.


MS. SUE: Suzanne Sue again. Given that both BFI and

Emterra were both -- both had proposals using CNG

trucks, do you think that the market in this area has

been kick-started or is fully developed?

MR. WOLFE: Not yet, no. And as such we do have the


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regulation that provides for those incentives.

However, from a practical standpoint in dishing out --

or in determining who gets incentives or not, one of

the internal criteria that we have developed is that

it is -- that the vehicles will -- or the companies

won’t receive incentives if it is for a prior

commitment. So if there was already a call out, for

example, in this case, Abbotsford, that required CNG,

then those trucks that went to Abbotsford couldn’t get

incentives, because the market has already moved in

that specific instance. But that’s not to say that

the market might have not -- or other municipalities

may not have moved quite as quickly.

MS. SUE: Okay. Suzanne Sue again. I have one more

question. FEI states that recovering costs of

prescribed undertaking number 1 from customers

receiving grants would reduce the cost savings from

NGV programs, and undermine the purpose of providing

incentives. And which have implications for Section

18(3) of the Clean Energy Act. And however, BFI and

Emterra both began using CNG garbage trucks without a

grant under the GGRR. How can cost recovery from

recipients be described as undermining the program?

MR. WOLFE: Are you speaking -- sorry, just as a

clarification, just cost recoveries from those

specific --


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MS. SUE: Yeah, basically FEI is saying that these costs

should only be recovered from non-bypassed customers,

and none of the costs should be directly recovered

from the grant recipients. And --

MS. CARMAN: Just to clarify -- this is Michelle Carman

-- it’s likely that those grant recipients are non-

bypass customers. If they’re on our system, consuming

either CNG or LNG, they are part of non-pass -- the

group of non-bypass customers. And they are

contributing towards those costs.

MS. SUE: Suzanne Sue again. I just -- I guess we’re

just getting back to the idea of cost causality and

the customers that are producing the costs and

receiving the benefits should possibly pay the

majority of the costs.

MR. STOUT: It’s Doug Stout. I don’t think that’s -- if

you look at the energy efficiency and conservation

program, if a customer installs a new boiler, furnace,

water heater, that reduces their costs, or switches

from heating oil to natural gas and joins the system,

they get a cost savings benefit 100 percent. They pay

a portion of the costs. And these folks are paying a

portion, their trucking costs. Some costs are covered

by the incentive and everybody participates in that.

Those folks under energy efficiency, same as this

program, pay back a portion through their delivery


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rates, through the non-bypass customers, just as this

programs works. It aligns with the same concept.

Well, they’re different magnitudes of potential

savings, or different issues around technology, there

is still the fuel price risk with those customers in

all cases.

And so there is a variety of different

factors at play that are somewhat similar to the

barriers around the trucking industry or transport

industry. Not as many, as Mr. Grist said. There are

still more known technologies on the gas, like for

boilers and water heaters, et cetera, that reduce the

risk of switching for that customer who switches. And

they have that fuel cost differential is really their

risk, but the efficiency gains they keep. And

everyone pays for that. So we think it lines up with

the same concepts.

MR. WOLFE: And, sorry, if I could add just a couple of

other points. The pool of customers that are under,

say, taking LNG or CNG incentives, that pool of

customers will be relatively small, even if all these

19 go forward. It’s just those 19 customers. So, if

you are recovering incentives just from those

customers effectively you do turn that into a grant,

not an incentive, and that does take away from one of

the options that is available under the GGRR to offer


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incentive. Because you’re taking away the actual

component that would be an incentive.

The other part of that is that if you’re

just recovering from that small group of customers,

those trucking companies are also competitors to each

other.


And recovering all the costs just from the

small pool of customers you're actually recovering it

from competitors, and then there can result in kind of

a perverse incentive for people to take more or less

incentives because their competitor would actually pay

for it.

MS. SUE: Suzanne Sue again. It's just a sharing of the

cost question, it's not I guess an issue whether it's

a grant or an incentive. We're just -- the Commission

understands Fortis's view that the costs should be

recovered from all non-bypass customers primarily, but

we are concerned that, you know, maybe that the

customers receiving the grants should pay maybe a

little more.

MR. WOLFE: I don't think that's how we view it. We view

it that the benefits do flow to all the customers

because of the increased load on the system as was

shown earlier, with the decreasing rates over the life

and therefore all those non-bypass customers do


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receive benefits they should pay. And as my colleague

Mr. Grist pointed out, the actual recipients of the

incentives are taking on additional risk as well.

MR. GRIST: Mark Grist here. Just one further point of

clarification. I just want to make it absolutely

clear that the BFI 52 truck fleet for Surrey was done

without incentives, and that was a direct result of

the first round of incentives. So that led to 60,000

gigajoules of take or pay load added to our system,

which helps to pay back the cost of the incentives.

MR. NAKONESHNY: This is Phil Nakoneshny. The line of

questioning that we're getting into is directly

related to the aspect of the Commission setting the

rate and the cost recovery approach that they take.

We understand FEI's proposal, and because the

Commission has to ensure that FEI recovers enough

revenue to recover the costs that are under the

regulation, the regulation does not specify from whom.

So that is why we were asking questions in terms of

should it be some other group other than the group

that FEI has proposed, being just the non-bypass

customers. And we also recognize that these customers

that would be served by FEI, they would also be

customers of the broader group.

So it is whether any cost allocation to the

people getting the incentives is a decision that the


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Commission can make that differs from the proposal

that FEI has put forward, because the regulation is

not specific enough in terms of from whom.

MR. WOLFE: There are -- one of the points to your

comments there are that in recovering it just from the

smaller pool of customers or recovering more from

those versus the non-bypass customers, in our opinion

would lessen the uptake of the program and then as a

result not achieve the objectives of the GGRR in

reducing greenhouse gas emissions. So in recovering

it from all customers it would -- we believe it would

help the program be successful, and therefore those

costs should be recovered from all, from that

component.

MR. GRIST: Mark Grist here, if I could just follow up on

that. In the extreme, if all these -- the costs of

the incentives were allocated only to the NGT

customers who are taking the incentives, that

effectively turns the grant into a loan. That makes

the business case for these operators not attractive

so we don't get the adoption, so you don't get the

payback of the program.

There's two elements to consider in this

program, of course. One is the costs of providing the

incentives and how those have been recovered, but also

the benefits. So there's no point in incurring costs


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if you don't have some reasonable path towards getting

the benefits from it. And that's why we're suggesting

that if -- as the regulation was contemplated in our

discussions with the Ministry, the cost recovery would

be from all non-bypass customers. And in that

circumstance, the incentives provided to the vehicle

operators to make the transition to natural gas

vehicles which creates the GHG reduction benefits the

province is looking for, and also creates the load

addition benefits that help pay for the program.


MR. NAKONESHNY: Yes. This is Phil Nakoneshny again.

With regards to the comment describing it as being the

extreme case, what I believe staff are asking is, does

the Commission have a discretion to decide if there

can be any allocation to the incentive recipients that

is greater than a zero percent allocation? And not to

presume that it’s either 100 percent or zero percent,

but can it be anything, even slightly above zero

percent?

MR. GRIST: Mark Grist again on that one. I’m not the

legal side of this, but my understanding is that, you

know, the Commission does have the ability to

determine how the rates are set and how these are

recovered. However, there is guidance provided in the

Clean Energy Act that indicates that the Commission


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shall not frustrate the program through the process of

setting those rates.

In our perspective, if this was to be put

into a situation where the costs of the incentives are

recovered from the people who are getting those

incentives, that would frustrate the program.

MR. STOUT: And it’s Doug Stout. I think the other

thing, when you look at it -- not just at a snapshot

year but in the whole context, the fact that the

incentives are not designed to ratchet down, such

that, you know, the early movers get more benefit from

moving to help stimulate the market, driving hopefully

more of what we see with Emterra, BFI, and those kind

of things happening, and the incentives comes down to,

in effect, those future recipients are getting less of

the incentive. So there is -- you know, it’s designed

over that five-year term to level out. I know it’s

probably around 60 percent, depending on how much

uptake. It may be lower than that. Of the total,

that’s going to be recovered. And there still is a

recovery from those who get incentives through the

delivery margin, plus those customers who move like

the BFI, who moves because of the competitive

pressure. They will be contributing towards those

incentives, recovery of those incentives through their

delivery rates as well.


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So there is an overlap, and I think it’s

across the context of the five-year part of the

program to look at what the effect is and how it’s

designed to move.

MS. CARMAN: Michelle Carman here. I’d like to just

address -- so the rate design concern that you brought

up was one of cost causality. And most of us are

aware rate design is not a black-and-white exercise,

and that there are actually several considerations

when we are allocating costs, and cost causality is

just one of them. So, in this case what’s important

to consider is that the intent of the regulation is

for greenhouse gas emission reductions. Which is not

something that’s included in the cost of service or is

quantifiable. And so that’s certainly taken into

consideration when we would consider how these costs

should be allocated.

So in this particular case, if it’s a

greenhouse gas, the purpose is for greenhouse gas

emission reductions. It’s a benefit to all customers.

And, you know, from a rate design perspective, we’re

comfortable allocating that cost to all customers.

And another small but minor point is that

the waste haulers that we’re talking about in this

specific example are just one component of the natural

gas for transportation market. There are other


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sectors of the NGT market.

MR. NAKONESHNY: Okay. And this is Phil Nakoneshny

again. You had talked about the rate design

considerations that I believe Mark had mentioned, with

regards to recovering costs from all the customers

that are receiving the benefits. From the information

that is on file, it appears that the fuel savings that

are occurring to the recipients of these incentives,

they receive a higher benefit year by year compared to

the non-bypassed ratepayers.


So the question is whether we do the rate

design that Fortis has proposed, which is here's the

cost of the program broadly and it's recovered from

everyone on a more or less equal basis, and the staff

questioning is on the lines of should there be some

other consideration rather than just the across the

board proposal that Fortis has?

THE CHAIRPERSON: Are there further questions on this

topic?

MR. ANDREWS: I have one.


MR. ANDREWS: Bill Andrews from BCSEA. Can you describe

the process by which Fortis will address the

proportion of the pot that will go by way of grants

compared to loans, and to whom it reports about that


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decision?

MR. WOLFE: Yes. Right now our intention is that we will

be giving out grants or incentives and not loans for

the reasons that we've discussed already. We don't

see, at least right now, that loans are the right

mechanism. And as far as reporting goes, within the

Clean Energy Act we would report that to the Minister

on the Minister's request.

MR. ANDREWS: Thank you.

MR. GHIKAS: Would it help -- just on this, would it help

to quantify, I mean, do you have any information on

the quantification of the cost/benefit analysis that

goes in? And I know we're going a bit around in

circles here, but it just -- the zero interest loans

can -- it might help, Mr. Chairman, if the panel

describes what the business analysis is on a zero

interest loan from the customer's perspective. I know

I'm kind of doing a reply here, but it seems like it

would help.

THE CHAIRPERSON: I'm not sure that it would. I think we

have an answer from Fortis on their intentions on

grants versus loans. Unless somebody wants to pursue

that line of questioning, I don't know that that's

necessary.

MR. STOUT: Mr. Chairman, it's Doug Stout. If I could

just make one comment. I think the document about


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Abbotsford is maybe helpful in that, and just in

looking at that it's under the analysis part. And

note BFI was the incumbent waste hauler in Abbotsford

at the time, so others would know they were bidding

against BFI and what they had done with the City of

Surrey. And when you look at the costs that are laid

out, we see that Emterra and BFI are within a couple

of hundred thousand dollars of each other at about 6.2

to 6.7 million. The next highest bidders are closer

to 9 and a half and 10 and a half million.

So while that company got the benefit of --

they got some business they didn't have before, they

put a very large piece of that potential savings on

the table in order to get that business. So now it

goes back to the folks of Abbotsford who are paying

for those waste hauling costs. But I think that goes,

you know, shows part of the public interest when you

look right across the whole piece of this on the

broader scale, that the benefits flow in a variety of

ways back to those end users. Some will be natural

gas customers, some of them may not, but it does have

a broader perspective to it, I think, when we look at

it that way around reducing greenhouse gases, but when

you get to the economics of who's keeping the benefit.

If it's transit buses, for example, would end up

taking the funds, whatever savings there flow to the


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broader public interest producing greenhouse gases

into the public interest.

So I think it's aligned and that -- I think

that's, you know, when we went through the

discussions, those kind of things were talked about

was government and around developing this regulation.

And where did the different benefits flow and how

would they potentially flow over time across B.C.

THE CHAIRPERSON: Further questions on this topic?

MR. WIGHTMAN: James Wightman, BCPSO. Just one quick

question. I noticed in the slides you had the

estimated life of an LNG vehicles or tractors from

five to ten years. Would it be possible for somebody

that got an incentive in 2011 to buy a tractor that

reached its end of life while the regulation was still

in effect, to apply and get funding incentives to buy

a replacement tractor?


MR. WOLFE: The average life span does vary, as we noted,

and depending on the use of the tractor trailer, if

it's used more its life span would be lower. Right

now we aren't that far advanced in our determination

of what incentives or the program what it would look

like in future years, so I can’t comment specifically

whether or not we would give an incentive out to that

customer.


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However, if we go to the principles that I

discussed earlier about it couldn’t be something that

was already required by an RFP, for example, it could

be that in the future when we develop the program, we

look and make an internal determination as to -- if

somebody had an incentive before whether or not they

should get that. However, at this point, it’s too

early to determine exactly if that would occur.

MR. WIGHTMAN: It’s possible that that could happen.

MR. GRIST: Mark Grist here. Just doing the math on your

inquiry. The program expires March, 2017, I believe.

And so in that example of a five-year truck, that was

funded under this program, it wouldn’t start to see

service until 2013. So, that would take them beyond

the end date of the program, if my math is correct.

It was also -- a related point is that

because we are weaning down the amounts of the

incentives, you know, even if that were possible,

which I don’t believe it is, under the first round

they might get a 70 percent incentive program. By the

time we get to that point in time it would be down in

that kind of 40 percent or less amount of incentive.\

So, two-part answer. One is, it’s not

possible under the timelines involved and two, even if

it was possible, they would get a much reduced

incentive.


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MR. WOLFE: And from a broader perspective, I think it’s

the goal of FEI and the province to have as many

trucks on the road as possible, to have the greatest

greenhouse gas emission savings. And so in our

development of the incentive program in discussions

with the province on that, and the fairness advisor,

those -- that would be the major consideration in

developing the program.

THE CHAIRPERSON: Further questions on this topic?

MS. SUE: This is Suzanne Sue. I just have one more

question. I guess on slide 23 of the handout, B-7, I

guess because the volumes of LNG is doubled per

vehicle, are you assuming, then, the kilometres the

vehicle has used has basically doubled, because you’re

using twice the fuel?

MR. WOLFE: Sorry, I don’t know if it’s a one-for-one

relationship on mileage and volume of fuel on this.

However, yes. So, some of the trucks that we have

seen are using -- will be in-service a lot more during

the day than other trucks, and as a result they’re

using more fuel and they’re going further distance.

MS. SUE: And Suzanne Sue again, just one more question

regarding, I guess, James Wightman’s discussion about

the -- if a company could come back in and get in

another round incentives, would be -- could Vedder

theoretically do that? Because they have already


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received -- possibly received incentives under the

demonstration program. And if -- basically, and that

started in -- prior to -- they started in 2010. So

they could come back possibly in 2015?

MR. WOLFE: I guess going back first of all, the

incentive program is something that has developed by

FEI. The actual mechanism of the grant program. In

consultation with the government and the fairness

advisor. And part of the goals as I mentioned was to

increase the number of trucks on the road, however

best to do that with the use of incentives. So, if --

we don’t want to -- we’re not -- we are discouraged, I

think, in providing a large number of incentives to a

few vehicles, because that would result in fewer

greenhouse gas emissions and less of a benefit.

So, taking that one step further, we would

want to try to incent new load and new customers to

use a system -- it would be our hope that if a

customer already received a grant, that they would

already understand the benefit of it, and they would

be more comfortable with the fuel, and would then, in

their next purchase of vehicles, not require a grant.

And that’s kind of consistent with the ratcheting down

of the incentives.

But right now, that would be something that

would be discussed between the province and FEI, and


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it just -- and we don't have those kind of parameters

set.


MR. GRIST: Mark Grist here. In addition to that we are,

you know, receiving stakeholder feedback on the design

of the program, and it will be adjusted as we move

forward for the learnings that come up with in the

discussions with the Ministry and other stakeholders.

One of the other issues or constraints that

we have is that we also have to be very cognizant of

providing these incentives in a fair manner that

doesn't create advantages of one carrier over another.

So for example, if Vedder was competing for a new

piece of business with another carrier and they were

not able to get incentives for their vehicles and the

new guy could, then that raises an issue of fairness

that has been part of the discussions that we've had

with our fairness adviser in the design and makeup of

the program to date. So those issues need to be

factored in as well.

MR. STOUT: It's Doug Stout, and I think we talked in

some of the IRs about the criteria around the

incentives. But part of the criteria also is its link

to this afternoon's discussion on fuelling stations,

is also getting the infrastructure built out. We say

that's an impediment to everybody adopting this on a


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broader scale. So there could be a -- I'll pick

Vedder for example, that uses a fleet in the Lower

Mainland for collecting milk. They also have a fleet

that's a long haul trucking fleet. If they were one

of the early movers in the long haul trucking side and

that helped build out infrastructure that others could

then more easily adopt and move to, because the

fuelling infrastructure is key to adoption of this as

well, that's part of the criteria under the incentives

that we have at this point in time as well. So it

does fit together with how this thing evolves across

the whole province.

THE CHAIRPERSON: Any further questions?

MR. CRAIG: Mr. Chairman, Commercial Energy Consumers,

David Craig, just a few questions.

Mr. Ghikas, if I can start with your

summary in paragraph 2 at the bottom:

"FEI submits that the only issue for the

Commission to determine in Phase 1 and 2 of

the proceeding is how, i.e. from which

customers and using what rate constructs,

the costs of prescribed undertakings will be

recovered from customers."

Can we also agree that it would be also

over what time the recovery takes place would be

within the Commission's scope of decision making?


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MR. GHIKAS: Agreed.

MR. CRAIG: And the primary reason for this being the

scope of what you believe we should be focused on at

this point is the regulation, Section 18, doesn't

really deal with rates and recovery. So that's the

reason we're here today, is it's a Commission decision

to determine the rates and recovery.

MR. GHIKAS: I'll deal with this more, Mr. Craig, in the

final submission. But as a quick answer to your

question is that Fortis's position on these matters,

Mr. Chairman, is that the issue of need for the

incentives and whether or not incentives should be

dispersed and the processes or mechanisms by which

those incentives are dispersed is something that falls

outside of the scope of this proceeding, and that

really this proceeding is designed to set rates to

meet the statutory requirement that costs be

recovered. And the mechanisms, when I say rate

mechanisms, that would include all aspects of the

deferral account mechanisms that have been proposed,

the amortization period, the recovery of AFUDC on

them, things like that are all rate related.

MR. CRAIG: Right. And in your proposal then, and this

may go to someone else on the panel, the proposal that

the rates for the incentives be recovered from all

non-bypass customers, the NGT customers are included


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in that, I think you had mentioned that earlier. So

there will be a small percentage of the costs

recovered from NGT customers.

MS. CARMAN: That's right.

MR. CRAIG: And so when we come to dealing with rate

constructs, it remains an open question as to just how

much that should be, and Fortis has proposed that it

be equal across all non-bypass customers. But

presumably at some point in the future when things are

very successful, that may be much less of an issue now

than when you're building the market in the early

stages.

MR. STOUT: Doug Stout. I think that's right. I mean,

it's a small number today. It will grow over time in

total amount.

MR. CRAIG: Yeah.

MR. STOUT: Yeah.

MR. GRIST: I think we should keep in -- sorry, Mark

Grist here. We needed to keep in mind that this is

not intended to be a permanent program. It's just

intended to be in place until 2017 and we wean people

off the need for incentives during that timeframe.

MR. CRAIG: And that's where I'm going. The primary

argument you're putting forward is what kind of

priming does it take and that’s a question that may --

that we may have more evidence on as time evolves.


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MR. GRIST: Agreed.

MR. CRAIG: And so if the Commission is setting a rate,

it could at least keep constructs in mind as to what

the percentages are from different customer groups,

and they make those decisions over time. Your case

would be that you’re looking for that percentage to be

small, as you’ve defined it now, equal across all non-

bypassed customers. And that’s to make sure that you

get off to a good start and are capturing the market.

MR. GRIST: Agreed.

MR. CRAIG: Okay. I want to go to the time frame. We’re

looking at fueling stations, and you already have an

Order from the Commission that sets a depreciation

rate of 20 years, a five percent depreciation rate.

MS. CARMAN: Michelle Carman here. That’s correct.

MR. CRAIG: And so when you’re making the investments for

all of us customers for those fueling stations, you’re

clearly expecting that there is going to be benefits

flowing from those investments over at least a 20-year

period.

MS. CARMAN: That is our expectation, but in the case of

the incentives, we’ve linked the cost recovery

associated with those with the expected vehicle life,

because the incentives are being provided for the

purchase of vehicles. They’re not tied to fueling


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stations themselves.

MR. CRAIG: Yes, I understand that’s your point, and not

to get into argument, but there is an alternative

consideration that the reason for the incentives is to

build the market, not necessarily the life of the

truck, and the market is at least 20 years, and you’re

framing it that way for the purpose of creating future

benefits. And so it is a consideration within what

we’ve allowed to be considered here, that a 20-year

period may be an appropriate matching of costs and

benefits in an alternative to the one that you’re

looking at.

MR. PERTTULA: Dave Perttula here. Yes, I think it’s

definitely a consideration. However, the benefits

associated with the vehicle life are more certain than

the longer-term benefits, and the other aspect of this

is that we aren’t the only party that will be

providing the stations. It will be other groups

potentially that are providing stations as well.

And so we don’t see the incentives program

and the stations program linked to each other. That

being said, I think your point is well-taken.

MR. CRAIG: Let me go one step further. You’re expecting

continuing uptake, from the evidence that you’ve put

forward, after the incentive program.

MR. PERTTULA: Yes, that’s right.


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MR. CRAIG: And you have evidence and you’re building a

long-term resource plan at this point that’s

forecasting a 20-year period, and you’ve put evidence

in in this hearing that you’re expecting a rising

curve of participation. Over at least the 20-year

time frame that you’ve run numbers for, for this

hearing?

MR. PERTTULA: Again, that’s right.

MR. CRAIG: And then I’d just like to conclude with a key

point that you’ve made in the paper, and throughout

the process. You’re looking for certainty and

finality of decisions about this in order to provide

confidence to the market as we come out of this

proceeding. So you want all the decisions made here

so there is no uncertainty. And presumably the

problem with uncertainty is that we don’t get the

market uptake, we don’t get the benefits. And we may

have pieces of the costs that are hanging around. And

we will also end up with potentially delayed benefits

as we have with the uncertainty that’s been preceding

this process. Is that correct?


MR. STOUT: It’s Doug Stout. That’s right. We need

certainty around this to help the market move.

MR. CRAIG: And delaying the future stream of benefits

that you’re proposing actually in a present value term


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amounts to quite a significant amount, if I delay that

by a year or two.

MR. STOUT: Delay the movement of the market, you mean?

MR. CRAIG: Delay the progression towards transforming

the market. If I move that back a year and you’re

delayed a year further in getting into things because

of uncertainty, that will -- the benefit to customers

of that is the present value of that future stream

moved forward one year -- or moved back one year.

MR. STOUT: I think there is that, and there is also the

risk that that whole uptake curve drops significantly

by not having certainty in actually moving in what’s a

really strong window of opportunity in the marketplace

to initiate this.

MR. CRAIG: Thank you. That’s all my questions.

THE CHAIRPERSON: I believe there was a question from

Commission staff.

MS. DOMINGO: We’re trying to group some of the questions

together. I’m not so sure if that’s working well, but

we’ll try very hard here.

Just further on --

THE CHAIRPERSON: Will you identify yourself, please?

MS. DOMINGO: Sorry. Yolanda Domingo, Commission staff.


MS. DOMINGO: Further, or just continuing to -- in Mr.

Craig’s questioning about the amortization period, and


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I’m just wondering in -- and in the fueling stations’

variance account, I know we’re going to talk about

that in more detail this afternoon, but in that

variance account, you are proposing a three-year

amortization period and I believe you said that it’s

because it aligns with the timeframe of the

regulation. And so -- and I believe that’s -- can I

confirm that that’s not -- I mean, that’s different,

obviously, for your incentives deferral account.

MS. CARMAN: Yeah. So, to clarify, this is Michelle

Carman. There are two separate and distinct accounts

with different purposes.

MS. DOMINGO: Right.

MS. CARMAN: So, the incentives account is one in which,

you know, it’s connected to vehicles that have a

longer-term life, where the fueling station variance

account we actually don’t expect the balance in that

account to be significant. And in that particular

case, as I discussed in the presentation, when we’re

considering an amortization period, we balance several

considerations. So in that particular case, we feel

that a three-year recovery period is appropriate.

MS. DOMINGO: Because it’s going to be a smaller balance?

MS. CARMAN: It’s going to be a smaller balance, yes.

MS. DOMINGO: Thank you.

THE CHAIRPERSON: I had a couple of questions.


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MR. WEAFER: Mr. Chairman, did you want interveners to

finish before you -- I just wanted to follow up on a

question of Mr. Craig.

THE CHAIRPERSON: Please, go ahead.

MR. WEAFER: I just wanted to take you to slide 18 of

your presentation with respect to estimated vehicle

lives. And as we understand the evidence, the

deferral account amortization of ten years, you’ve

tied it to vehicle lives. But would you not agree

with me that on the slide here, the estimated vehicle

lives are on average in excess of ten years?

MR. PERTTULA: It really depends on the balance of

vehicles that you’re incenting. You know, if you have

more in the class 8 tractors that are on the shorter

end, that would tend to bring the average down. So,

it could be higher than that on average, but on -- we

think that ten is a reasonable estimate of that.

MR. WEAFER: So we could leave that to argument, but on

average, what you’ve got here is in excess of ten

years’ life.


MR. PERTTULA: It’s a -- if you added up the numbers and

divide it by 40, you might get higher than 10. But

it’s really a function of how many vehicles -- or how

many grants you’re likely to place in these

categories. And for example, even if you're in the


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one category, like say the LNG tractors, if you're

awarding grants to higher use vehicles, it may even be

right at the short end of that timeframe there.

MS. CARMAN: And just to clarify, so the ten-year average

aligns with the financial analysis that's included in

the appendices. So it is the assumption that's

embedded in those cost and benefit forecasts.

MR. WEAFER: I understand it's the assumption. I'm just

saying --

MS. CARMAN: I should clarify. In terms of the mix of

the vehicles.

MR. WEAFER: I understand it's the assumption.

MR. GRIST: Mark Grist here. Just to clarify, the

preliminary applications that we are progressing,

there's 258 -- sorry, 165 of the vehicles are

contemplated to be in that Class 8 tractor range, and

typically these ones are running a fair amount of

miles so they're in that kind of 5 to 10 year

category, so that would kind of bring the weighting

that way.

MR. WEAFER: That's fine, thank you.

THE CHAIRPERSON: Further questions?

MS. BRAITHWAITE: I still didn't finish my question.

Tannis Braithwaite. (inaudible)

THE CHAIRPERSON: Okay. Could I ask you to identify

yourself again, please, just --


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MS. BRAITHWAITE: Yes. Tannis Braithwaite, BCPSO. I

note that the current round of incentives is being

offered at 75 percent of the cost differential between

the diesel vehicles and the LNG vehicles and CNG

vehicles. How was the 75 percent figure arrived at?

MR. WOLFE: This was something in discussions internally

and then discussed with the province as to whether

this made sense or not. But with the number of

vehicles that were being requested, the number of

vehicles requested kind of matched with two years'

worth of funding. We looked at it from the point of

view that 100 percent incentive was what was given out

in that 5.6 million, which is the part of the

discussion in Phase 3, which would then put us into

the next phase at 80 percent. And because there are

enough vehicles and with what we had discussed with

the provinces, the expectation of the uptake, that

represented another two years' worth of vehicles.

So the logical conclusion of that is to

pool 70 percent and 80 percent and average that out to

75 percent for the vehicles. That's the maximum that

would be given up to those customers, and as yet we

don't know -- we don't have a definitive response back

as to whether that's enough for those customers to

uptake the program. That's still part of the ongoing

due diligence phase.


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MS. BRAITHWAITE: So if I understood that correctly, the

intention was to provide -- leaving aside the 5.6

million, approximately half of the total $62 million

in the first -- in this round?

MR. WOLFE: No. It was -- the first round would have

been at 80 percent based on the number of trucks and

participants. That represented in our discussions

with the Ministry two years' worth of funding. We

expected that many vehicles after the second year, and

so therefore it would be 75 percent.

MS. BRAITHWAITE: Okay, so has the uptake of the -- there

was 19 applicants. Is that what was anticipated or

what was forecast?

MR. WOLFE: It wasn't so much the applicants, it was the

number of trucks. The 400 trucks, give or take, was

what was expected after two years of funding, not one.

MS. BRAITHWAITE: And so earlier I said 50 percent of the

funding, but it's really two out of five years of

funding is what you anticipate disbursing under this

round of incentives.

MR. WOLFE: Yes.

MS. BRAITHWAITE: Okay. And so the uptake has been

basically in accordance with what was forecast or

anticipated?

MR. WOLFE: In accordance but a little advanced. So it

is representing two years in one round, which would


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mean that the next round of funding would be not at 70

percent but would be at 60 percent. But we don't know

the timing of that next round of funding.


MS. BRAITHWAITE: I was interested in the comment earlier

about Fortis having a security interest in the

vehicles that incentives are being provided for. Are

there any scenarios in which those vehicles would be

included in rate base?

MR. WOLFE: Not physically owned and not our property and

rate base. This would be more of an accounting

treatment, because we are holding a security interest

as part of the contribution agreement. It is similar,

in a sense, to having an equity stake in ownership on

that. And therefore that translates into the part of

our justification for including these costs as rate

base.

MS. BRAITHWAITE: Okay. I may have misunderstood that.

So the entire cost of the incentive that’s being

provided towards the vehicles is included in rate

base?

MR. PERTTULA: It’s included in rate base by virtue of

going into the deferral account, which then is

incorporated into rate base.

MS. BRAITHWAITE: Okay. This is a question that we asked

in the IRs, and it seems to me that the way this is


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structured, this program is structured, is currently,

anyways, non-bypass customers are being asked to pay

an amount that’s greater than the cost of service.

And they’re being asked to pay that amount for assets

which will then be included in rate base. And my

question had to do with the return on equity that’s

provided for -- on that rate base, that is effectively

being purchased by non-bypass customers. And the

response was, “Well, it’s shareholders who provide

equity financing and not ratepayers.”

But I’m wondering how you would

characterize the money that’s being -- that ratepayers

are being asked to provide for the purchase of

vehicles and fueling stations which will then be

included in rate base. It’s not debt financing. So

is it not effectively equity financing that’s being

provided? And then is it not that shareholders are

then being asked -- asking to have a return on that

rate base that has actually been financed by the

ratepayers?

I’m not sure that question makes any sense,

but --

MS. CARMAN: Well, maybe first I’ll try to clarify, and

you can let me know as we’re going along if what I’m

saying is making any sense. So, yes, we are including

the costs in a rate based deferral account. The


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utility’s rate base is financed by an approved capital

structure, and that includes an approved equity

component of 40 percent, which represents the

shareholders’ contribution to the actual financing of

the rate base itself. And a debt component of 60

percent.

So, the deferral account itself is -- the

balance of it is recovered through the delivery rates

of non-bypass customers. So the cost of service

associated with that deferral account includes the

amortization -- annual amortization expense, as well

as an earned return component, 60 percent of which is

related to the debt costs for financing and 40 percent

which is related to the equity.

Is that clear so far? Sort of?

MS. BRAITHWAITE: Sort of.

MS. CARMAN: So --

THE CHAIRPERSON: Could I have an answer to that

question, rather than a shake of the head? Because

it’s hard to record a shake of the head on the

recording.

MS. BRAITHWAITE: Well, it’s sort of clear, but I think

I’ll have to hear the rest of the answer before I can

have a real sense of whether what I’m getting at is

being addressed.

THE CHAIRPERSON: Okay, thank you.


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MS. CARMAN: So if I’m understanding what you’re asking,

is from the perspective that the -- you know, the 62

million will come from ratepayers. You’re saying, how

is that rate base? Is that maybe a fundamental

question that you’re asking? And why should that be

financed by the capital structure?

MS. BRAITHWAITE: Well, the capital structure is, as I

may just be completely misunderstanding how this

works, but there is an assumption that the assets that

are included in a rate base for Fortis are financed by

either debt or equity. And so -- and what ratepayers

pay is the cost of using those assets.

MS. CARMAN: Correct.

MS. BRAITHWAITE: And so in this case ratepayers are

being asked to pay -- non-bypass customers are being

asked to pay more than the cost of using those assets.

MS. CARMAN: In what regard? Maybe that’s what I don’t

understand.

MS. BRAITHWAITE: Well, where -- that’s where the

incentive comes from, right? The additional financing

that’s being provided to the trucking companies is

coming from -- or proposed to come, at least, from

non-bypass customers. So they’re paying for something

that is not part of the cost of serving them.

MS. CARMAN: Okay.

MR. WOLFE: I think what you’re saying, a trucking


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company will get an incentive. How that is funded

from the company’s standpoint is, it’s funded by the

shareholder and by debt, and then those costs, as well

as other costs, are then put into the cost of service

recovered from all non-bypass customers.

MS. BRAITHWAITE: Exactly. No, I think that’s exactly --

and that’s kind of what I’m getting at. It’s -- the

money actually comes from the ratepayers. Right?

Putting it into the cost of service, I understand

that’s how it works. But it’s not actually part of

the cost of serving the non-bypass customers.

MR. PERTTULA: Actually -- Dave Perttula here . The

money isn’t coming from ratepayers. The money is

coming from FortisBC, either through the equity that

the shareholder puts in or the debt financing. What’s

coming from the customer is through rates. They’re

paying for those costs. But those costs -- they’re

treated, as Michelle was saying earlier in the

presentation, just the same way that other rate-based

costs are. The EEC expenditures, for example, are

treated the same way. They’re a rate-based deferral

account. The company has to put out money to provide

these incentives, but we don't get it back from

customers over time.

Proceeding Time 9:04 a.m. T32-33

We're getting effectively over the ten-year


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period that you're amortizing it. So we're just

earning what we call a fair return on the money that's

been invested for that period of time.

So it's just sort of conventional

ratemaking principles and it's a recognized cost that

the utility earns a fair return in the investment that

it makes. So that's just another cost item. But

we're not recovering more than the cost of service.

We're recovering more than the incentives because

there's a carrying cost, but customers are actually --

probably they're -- it's a timing issue of when we get

the money from the customers. If you looked at things

on a present value basis, you would be getting the

same amount of money from customers as if it was

amortized over a short period, or if it was expensed.

So what's happening here is just that by

spreading it out over time, we are actually, as

Michelle was saying in her presentation, we're

matching the costs and benefits of the program and it

deals with -- we've said in the IRs at several points,

it deals with intergenerational equity. If we were

recovering it over a shorter amortization period or on

an expense basis, current customers would be paying

for all those costs and then future customers would be

getting the benefits. I mean I'm, you know, just sort

of painting a picture there.


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But I don't know if that sort of fills in

the background or whether that was too much regulatory

accounting.

MS. BRAITHWAITE: Yeah, if --

MR. WIGHTMAN: Can I ask a quick follow-up for BCPSO?

THE CHAIRPERSON: Just hold on for a moment, please. I

just want to deal with this question. Has Fortis

answered your question?

MS. BRAITHWAITE: Yes.

THE CHAIRPERSON: Thank you. Mr. Wightman?

MR. WIGHTMAN: Yes. Will you be providing the equity

component of the financing of the incentives through

retained earnings or through an issue of new equity?

MR. PERTTULA: I think that's an overall cash flow matter

and we're not claiming that it's out of one way or the

other. So I don't think I -- I mean cash flow and

cash management is really sort of a separate function.

But we are effectively funding these items that are in

rate base on the 60/40 basis that's allowed.

MR. WIGHTMAN: Well, my question was because this is an

increase in equity, and what would be stopping you

from borrowing to give the money out, then charging

ratepayers an equity and debt component on the return?

So it just seems to me if there's an increase in

equity, where is it coming from?

MR. PERTTULA: The increase in rate base that comes from


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this is just like other elements of adding to rate

base. If we invest money on new pipe in the ground or

other rate base assets, it causes our overall rate

base to increase and so we have to finance that. And

so, yes, it comes -- we have to make presentations and

this would be more in a revenue requirement

application where we would demonstrate that our -- you

know, we're funding our rate base by debt and equity.

And so does that respond to your question?

MR. WIGHTMAN: Well, I guess if equity is increasing,

then it has to come from one of two places. That's

all. And that was my question, because if it doesn't

come from an increase in equity it comes from an

increase in debt totally. That's all.

MR. GHIKAS: Mr. Wightman, it's Matt Ghikas. There's a

deemed capital structure that Fortis has to reconcile

to. That's what being referred to by the witnesses.

So that the Commission is overseeing the capital

structure, and when it's reconciled it has to match

the 60/40. So if there's new assets being added, they

still have reconcile it at the end of the day.

MR. PERTTULA: Yes, and just to add a little bit, we do

have to maintain our 40 percent common equity ratio.

So over time we have to issue new equity or debt, but

we maintain that 60/40 split. So --



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MR. WIGHTMAN: Okay, thank you.

MS. DOMINGO: It’s Yolanda Domingo here. And further

into that topic, maybe we could just put some things

into perspective. I think -- and I think it all comes

down to Section 18(2) of the Clean Energy Act. Where

in there, that it states that the Commission is

required to set rates that allow the public utility to

collect sufficient revenue in each fiscal period to

enable it to recover its costs incurred.

So, and then there is a couple of IR

questions and responses, specifically 4.1 and 4.2,

which gives Fortis’s position. So there I believe

Fortis indicates that it has interpreted that section

of the regulation to mean that the rates must be set

to not only allow the utility to recover its costs but

also a fair return. So I understand your position

there. But I’m not certain that those are the words

that are explicitly included in the regulation.

But what is specific is, “to enable it to

recover its costs”. So couldn’t another

interpretation of that part of the regulation,

couldn’t that mean to recover any out-of-pocket costs,

potentially any financing costs? And that could be

measured in a number of ways, possibly incremental

costs of debt or short-term interest, or what-not,

could be included in the definition of costs. But not


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necessarily in equity return. Can you comment on

that?

MS. CARMAN: Well, first of all, you know, we interpret

the cost to be the entire cost of service associated

with the incentives. And included in a cost-of-

service calculation is the earned return, and there

are, as we briefly just discussed, there is two

components to earned return. There is a debt

component and an equity component.

So, when considering the entire cost of

service, and the costs associated with the cost

incurred by the utility, there are both debt and

equity components.

MS. DOMINGO: Okay. I just wanted to raise a piece of --

it was included in the FortisBC, and this is the

electric, 2012 and ’13 revenue requirement and

integrated system plan decision. And there is -- the

Commission Panel there had raised a point on -- I

believe it was page 105 of that decision, and it

states that "deferral accounts are regulatory

accounts, not true capital assets." And therefore

that panel had ordered that the appropriate return is

the weighted average cost of debt on a certain number

of deferral accounts.

And so exploring -- I mean, keeping that in

mind a little bit, maybe we can talk about that aspect


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of it. And I think this was in line with the

questioning that Ms. Braithwaite had earlier in

regards to the financing costs that should be allowed

on the return on rate base. So I think the question

really then is whether the proposed expenditures, are

they rate base or are they not rate base?

Does the company agree that the incentive

payments -- they’re simply just cash payments, or I

guess a financing transaction to the NGT customers.

They don’t actually represent physical assets that are

invested by FEI and used to provide service to its

customers. So, I mean, isn’t that -- aren’t rate base

expenditures normally defined as such?

MS. CARMAN: This is Michelle Carman. Consistently rate

based deferral accounts have been included in FEI --

in the Fortis Energy Utilities rate base. As alluded

to in my presentation, in this particular case, there

is a long-term nature associated with this program.

It’s tied to, you know, a long-term benefit on the

system, similar to a fixed asset. Again, there is the

tie-in to the security interest in the vehicle. But,

you know, the decision that you’re referring to,

FortisBC did reply to that decision, and we disagreed.

And articulated that it’s incorrect to draw a

distinction between capital and operating costs based

on the nature of the expenditures, the deferral


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accounts. In all cases, the utility is being

compensated for that time lag for when those -- when

that -- between when those expenditures are incurred

and when they’re recovered.


MS. CARMAN: So, are you -- the equity return is

applicable because it reflects the funding required

until the asset for -- well, the assets and rate base,

or goes into rate base, in the case of the AFUDC.

MS. DOMINGO: Okay. In that case, does FEI agree that

the incentive grants and the related expenditures, how

they’re being treated, that they are different than

say the CNG and LNG stations that we're going to talk

about in Phase 2, where FEI constructs and operates

the stations. It is a different arrangement.


MS. CARMAN: The nature of the costs may be different,

but the requirement for a deferral account and the

fundamental principles of a deferral account and rate

base are the same.

MS. DOMINGO: I just wanted to go further a little bit.

It's on page 7 of the application. The company

discusses the -- yeah, near the bottom of that page, I

believe. FEI had mentioned the NGT incentive review

decision and that's dated August 20th of 2011. That's

where the Commission had determined that NGV


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incentives did not meet the definition of the demand-

side measure under the Clean Energy Act. So

accordingly the Commission at that point disallowed

the use of the EEC program to fund the NGT incentives.

So keeping that in mind, wouldn't this mean

that any NGT incentives shouldn't be treated as rate

base, and as such they should not earn an equity

return?

MS. CARMAN: No, I don't agree with that conclusion.

What that decision said was that NGT incentives could

not be included within the EEC programs. It did not

make any determinations on whether or not NGT

incentives should be included in rate base or not, and

in fact the incentives that had been provided have

been put to the side for Phase 3 of this review.

MS. DOMINGO: This session.

MS. CARMAN: Right.

MS. DOMINGO: If the Commission does agree with FEI's

interpretation of the rate base treatment, what should

be the amount that would be recorded in rate base for

any fiscal period? Would it be the mid-year rate base

calculation or some other --

MS. CARMAN: For the deferral account?

MS. DOMINGO: Correct.

MS. CARMAN: Included in rate base would be the mid-year

balance of the deferral account.


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MS. DOMINGO: Mid-year?

MS. CARMAN: That's correct.

MS. DOMINGO: Okay. My last question is if the

Commission does not agree with FEI's interpretation

for the rate base agreement and therefore doesn't

allow the AFUDC as a financing cost, what do you

propose as a methodology that could be determined for

fair financing costs?

MS. CARMAN: So are you suggesting no deferral account

treatment whatsoever in an expense treatment?

MS. DOMINGO: I'm just talking about the financing

portion of the deferral treatment. So would it be

maybe a weighted average cost of debt or -- I'm just

speculating.

MS. CARMAN: Well, first of all, if something is included

in rate base as mentioned earlier, it should attract

the allowed return on rate base, which includes an

equity portion. If it's for some reason determined

that this should not be included in rate base, still a

deferral account, a non-rate-base deferral account,

it's still our position that AFUDC should apply

because it reflects the finding that is actually

required for those dollars.


THE CHAIRPERSON: I'd like to jump in here just for a

moment with a couple of questions. I'm not trying to


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stop the questioning, but I did have a couple, because

we're kind of getting way, way, way beyond the context

that was raised earlier with respect to these

questions.

But first I'd like to make an observation

and that is we -- through this discussion we continue

to talk about the incentive payment, and we talk about

incentives generally, but we also commingle that with

specific reference to an incentive payment. And I've

just scanned the regulation and I may have missed it,

but the word "incentive" doesn't appear anywhere in

the regulation. And so I think for clarity we should

-- I think it's okay perhaps to use the word

"incentive" if we're grouping things together and

talking generally, but I think we need to be specific

here about referring to what's in the regulation and

not calling it something else.

Secondly, I think it would be helpful if

during the lunch break, which we're going to have

shortly, I could ask Fortis as an undertaking to come

back with the definition using Webster's presumably, I

think that's the standard place we go, the definition

of the word "grant", just so that there's clarity

around what the word "grant" means and so we can all

have a common understanding of that. So I think that

would help maybe sharpen the focus of our discussions.


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Then the other -- I have two questions and

this goes to the issue of perhaps fairness in terms of

the program, and I just ask this for clarification.

It doesn’t really turn on the decisions that we’re

making here, but the subject did come up. The first

one is, it’s my understanding that Fortis would not

provide grants for programs that -- for vehicles to be

used in programs that are currently underway. So for

instance in the Surrey garbage collection program that

was bid on the basis of using NGV vehicles, Fortis

would not retrospectively or not then provide a grant

for those vehicles. That was my understanding.

What would prevent -- and let’s use real

examples here. What would prevent Waste Management

from -- which is currently running NGV vehicles in the

Vancouver area, from bidding on a waste collection

contract in Maple Ridge, as an example, using NGV

vehicles, and if they win that contract, simply moving

the vehicles that are working somewhere else under a

previous grant, moving them over to that jurisdiction?

So in other words they kind of bid into that offering

at Maple Ridge based on using NGV vehicles, but now

they’re going to simply shift the vehicles that they

receive grants for, for somewhere else, over to that

jurisdiction.


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MR. GRIST: It’s Mark Grist. I’ll answer the last part

of that first. The due diligence that we go through

in making these arrangements with our customers

requires them to provide us with evidence of the

vehicle being purchased, and also registered for

operation. So we get the VIN numbers -- sorry,

Vehicle Identification Numbers, and all that

additional stuff. So, if they simply moved vehicles

from an existing operation to the new one, they

couldn’t provide us with the evidence that they had

actually acquired those new vehicles.

THE CHAIRPERSON: So then they would be prohibited from,

in effect, using vehicles that -- for which they had

received a grant to use that vehicle in some other

location, over to a new location.

MR. WOLFE: No, sorry. Maybe -- how the customer uses

it, or where they decide to use it, if they got -- in

this example, say Waste Management had applied to the

program and got grants, and we determined that that

was an additive program, or an additive purchase, that

it was a new vehicle, not one that they had -- they

got grants for that vehicle. If at some point they --

and they were using it at the time in Coquitlam. If

at some point in time Maple Ridge has an RFP out, and

Waste Management bids on that and wins that, and they

bid based upon having NGV vehicles, and they want to


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move them there, there is nothing to stop them from

doing that. That’s fine. They’re still using the

vehicles as far as the load -- as long as the load is

what it is expected, whether they use it for one use

or another, that’s okay within the context of the

contribution agreement. They’re not asking for new

vehicles for Maple Ridge. They’re just taking

vehicles that they already have the -- yeah. I think

that --

THE CHAIRPERSON: Do you see that as raising a fairness

issue on the part of competitors who would be bidding

for that -- let’s use the term, let’s use the location

Maple Ridge -- would be bidding for that Maple Ridge

business? Do you see that as being a potential

controversial issue in terms of this program? Because

those other competitors don’t have natural gas

vehicles, and can’t -- if they win the contract, they

can’t go and be sure of getting a grant to purchase

them.

Proceeding Time 12:02 p.m. T37

MR. WOLFE: It’s Jason Wolfe again. It could be, and

certainly there have been discussions in this first

round of various applicants, and what they’re asking

for, and we’ve gone back and forth with the fairness

advisor and province as to whether or not this should

or should not qualify, does this make sense for the


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program? Does this accomplish what the program is

intended to accomplish? And so those are sometimes

the tough discussions that go back and forth.

It would really depend on the circumstance

of the RFP in that case, whether others might have the

opportunity, if it wasn’t an RFP for NGV vehicles or

NGT vehicles, you could have other applicants that

would apply, or send in their RFP, and also apply to

us in a round of funding, potentially. But those --

there are lots of complex components in that that

would be discussed during that funding with the

fairness advisor and with the province.

MR. STOUT: Doug Stout. But I think that is probably the

long-term goal of the program, is to -- is we get

weaned off incentives. We want people using that

advantage, the province does, to drive more adoption

or greenhouse gas reductions in those things. So

it’s, I think, that is an outcome that’s hoped for.

That’s where we hope this is going to get to, that

that drives that competitive pressure for others to

start going out and buying vehicles without

incentives. And we wean them off. It is --

THE CHAIRPERSON: Yeah. Absolutely. I’m more concerned

about the short term.

MR. STOUT: Yeah.

THE CHAIRPERSON: Final question. Is there, in your


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agreements with your grant recipients, is there a

prohibition on selling that vehicle during any period

of time, and I could foresee if somebody needed three

NGV garbage trucks to perform in a contract that they

have won, they’d be pretty anxious to go out on the

market and buy those trucks, even if they had to pay a

premium for them. Is there a prohibition from -- for

a grant recipient that owned several trucks to sell

those trucks at a premium to another company?

MR. GRIST: That specific case is not really addressed in

the agreement. The agreement does have restrictions

about removing the vehicle from the B.C. jurisdiction,

when the GHG reduction benefits wouldn’t be incurred

in -- you know, so they’re not allowed to do that, and

that’s the purpose of having our security interests.

And they have a requirement to continue to purchase

fuel for those vehicles, for the life of the vehicle,

from the Fortis system as well. So there are some

protections on that.

I’d like to jump back to your original

question, though. With respect to the fairness in the

example that you raised, all carriers have equal

access to each round of the funding. So, we don’t

think we’re upsetting the playing field. The example

you raised where somebody’s got a fleet of natural gas

vehicles and can therefore compete more effectively on


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a new piece of business comes up, that’s not much

different than the situation that exists today if

somebody’s got a 2010 certified diesel vehicle with a

certain performance on the road, and a certain

emissions profile competing with somebody whose fleet

might be older and dirtier. They’re going to have a

different set of competitive dynamics going after that

business. And --

THE CHAIRPERSON: Yeah, I think I have an answer to my

question. Thank you.

MR. GRIST: Fair enough.

THE CHAIRPERSON: Okay. Let’s go back to questions -- in

doing so, I note that it’s five after twelve.

Quickly, around the table, how many more questions in

any category do people have to ask? Is there a pent-

up demand here in terms of questions? I’m just trying

to plan time.

MR. ANDREWS: I don’t have any questions. It’s Bill

Andrews, excuse me.

THE CHAIRPERSON: Okay. What about Commission staff? Do

you have a number of additional questions?

MS. DOMINGO: Not too many.

THE CHAIRPERSON: Not too many. Down the table --

MR. WEAFER: No further questions from CEC.

THE CHAIRPERSON: Okay. Mr. Andrews?

MR. ANDREWS: No questions.


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THE CHAIRPERSON: Yeah. Thank you. Ms. Braithwaite?

MS. BRAITHWAITE: No further questions here.

THE CHAIRPERSON: Okay. Well, let’s spend a few more

minutes on questions, because I think we may be able

to dispense with the questions and then during the

lunch break perhaps people can prepare their

submissions. So I think if anybody needs to have a

quick break, I’d encourage them to jump up and have

their break. And if we have any financial questions,

we’ll hold them till you return.

Okay. Commission staff, you indicated you

had a few more questions?

MR. GRIST: Commissioner Kelsey?


MR. GRIST: I just wanted to take this opportunity to --

I’ve looked at the agreement, the contribution

agreement, in a little more depth. And there is a

section in there, 2.7, that describes a bunch of

repayment events. And actually sale of the vehicle is

one of the repayment events.

THE CHAIRPERSON: Oh, thank you for that clarification.

Ms. Domingo, please.


MS. DOMINGO: Thank you. Yolanda Domingo. In the three

prescribed undertakings in the regulation, they're

separately referred to as class of expenditures or


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class of programs.

In response to BCUC IR 2.1, the company

argues that establishing separate classes of service

for a class of projects or programs or contracts or

expenditures that would result in these classes of

service being treated as self-contained is contrary to

the general intent of Section 18 of the Clean Energy

Act. However, in another response, this is 2.2, FEI

also agrees that the regulation does not expressly

state that the three prescribed undertakings are to be

included within FEI's natural gas class of service.

I guess I'm just wondering, given that the

regulation is going to be revoked March 31st of 2017,

certainly the prescribed undertakings have a limited

life, if you will. Would the company agree that -- I

guess, is it reasonable to assume that the Commission

would have some discretion -- and I'm talking about

after the regulation expires. Would it be reasonable

to assume that the Commission would have some

discretion in order to order a different treatment for

the remainder of these costs at that time?

MR. GHIKAS: Could I just ask for clarity? It's Matt

Ghikas. What do you mean, a different treatment?

MS. DOMINGO: In terms of -- and I'm wondering, I guess

I'm just speculating, currently the regulation speaks

to the fact that the program costs and the incentives


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are going to be recoverable. And given that the

regulation is going to be revoked in 2017, what will

happen to the remainder of that cost? Like could the

Commission come in at that point and order a different

treatment of that cost at that time?

MR. GHIKAS: And I'll answer this from a legal

perspective. If the different treatment involves

disallowing the costs on the basis that they shouldn't

have been undertaking, then the answer is no.

MS. DOMINGO: Or potentially recovery from a different

party?

MR. GHIKAS: Or -- well, a Commission has jurisdiction

over fixing of rates, so the Commission will set rates

in a manner that it perceives as appropriate at the

time.

MS. DOMINGO: Okay, if that is the case would it -- do

you think at this point that -- could the Commission,

is it reasonable for the Commission to require that

the three prescribed undertakings be set up as self-

contained business units, but to treat the cost

recovery by allocating those costs back to say natural

gas class of service until the regulation ends?

MR. GHIKAS: I'm not sure if I'm the one to answer that,

but I just am not sure I understood it. I'm sorry, if

you wouldn't mind saying it again.

MS. DOMINGO: Yes, sure.


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MR. NAKONESHNY: This is Phil Nakoneshny. Along with

this group of questions, Fortis's proposal is that the

prescribed undertakings are to be part of the natural

gas class of service. And so the first group of

questions is on the basis, are you looking for that

approval to be for the duration of the regulation? In

other words, starting from arguably now until March

31st, 2017? So that's the first question that we're

asking. Or are you looking for the Commission Panel

in this case to make a determination that is more long

term? Or when could the Commission review or

potentially change the rate recovery? Could it be at

any time during -- between now and the end of the

regulation? Whether this comes to argument I'll leave

that to Fortis to decide. So that's the first

question.

I don't know if you want to respond or you

want me to just go on with the other questions.

MR. GHIKAS: You can ask them if that's the way you want

to -- that's fine by me, and then I can answer them.

MR. NAKONESHNY: Okay. The other question with regards

to the self-contained business unit, Fortis has

proposed, by including the prescribed undertakings

within the natural gas class of service, it allows the

rate recovery to happen to the non-bypass customers,

and it avoids this frustration of Section 18 of the


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Clean Energy Act.


The alternative that we are asking Fortis

to comment on is whether the Commission in this

decision could require that -- let's say the CNG and

the LNG and for that matter even the incentive

deferral account was to be recorded outside of the

natural gas class of services, let's say in a separate

class of service, maybe all leave separate or maybe

just one or two of them. And then for the Commission

to decide the appropriate cost recovery. In other

words could they do a cost allocation back from this

self-contained business unit that is outside the

natural gas class of service, back to the non-bypass

ratepayers? Is that an option?

So those were the two points that we were

asking in this line of questioning.

MR. GHIKAS: I'm happy to address those in argument

after. Do we want to deal with it all at once or I'm

happy to give --

THE CHAIRPERSON: In argument's fine.

MR. GHIKAS: Okay.

MS. DOMINGO: Thank you. Just a couple of questions on

reporting and prudency, and this'll be quick.

MR. GRIST: Mark Grist here. If I could just ask, when

questions are made with respect to CNG, for example,


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service, if we could be clear what we're talking about

because we provide CNG under our, for example, Rate 25

delivery service for people to use for vehicle fuel.

And then we also have the fuelling station services

where we're providing compression and expensing

services. It's all part of delivering to the end user

a usable product. But one is already clearly within

the natural gas class of services, as you've been

describing, and the other one is more under discussion

in the context of the AES inquiry. So we tend to use

just CNG as a catch-all, but I think it's important to

be specific as to which aspect of that we're talking

about.

MR. NAKONESHNY: Yes, okay. You are going to make the

reply argument or the argument about this. If you

could also address the tracking and the reporting. So

putting the money spent into the self-contained

business units is one way to accomplish tracking.

During the period of the regulation that the

Commission decides they want to do something

different, then by virtue of having tracking that may

not be a self-contained business unit can reporting be

done sufficient that anything that the Commission is

trying to identify and requires some different

treatment for rate setting or cost recovery or any of

those things, can that be accomplished by a means


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other than making it a separate class of service?

So it would go to your comment with regards

to CNG and the different parts that are involved in

providing the CNG service to a customer.

MR. GHIKAS: Mr. Nakoneshny, can I ask you to just

clarify, when you're talking about moving the costs

into some other self-contained business unit, are you

talking about Phase 1 of this proceeding type of --

like prescribed undertaking 1 only? Or are you

talking about prescribed undertakings 2 and 3?

MR. NAKONESHNY: It has pretty much moved into 2 and 3.

It would be the same kind of approach.

MR. GHIKAS: But just for clarity, are you contemplating

that a scenario where the incentives themselves are

also within that separate unit, or is it just the

fuelling stations that have been constructed under

prescribed undertaking 2 and 3 being in a separate

class?

MR. NAKONESHNY: All three as a possibility.

MR. GHIKAS: All three, yes.

MR. NAKONESHNY: Okay.

MR. STOUT: It's Doug Stout. Or having sufficient

accounting tracking so we know what incentive costs

and what costs -- all costs were attributable to each

of those different phases.

MR. NAKONESHNY: Yes.


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MR. STOUT: Okay.

MR. NAKONESHNY: Because they are decisions that this

panel should be making with regards to this

application and this regulation, and it goes until

March 31st, 2017. But is it meant to be just a one-

time decision during that time period? Can it be

multiple decisions? Can the Commission revisit its

decision during the time period? And then can it also

say that it wants to leave open, that any rulings that

it makes and when the regulation ends. And then cost

recovery is just a mechanism of how you will recover

the costs from somebody, from some customer. So

there's different means to accomplish what you're --

what Fortis is proposing.


MS. CARMAN: Just to clarify. You know, it may end up in

the argument, but in section 5.3.3 of the application

we do acknowledge and indicate that we will maintain

separate records on the CNG and LNG fueling stations,

which will allow for each station to be tracked

separately.

MS. DOMINGO: The last few questions I have is in regards

to the reporting and prudency. In BCUC 1.2, FEI has

indicated that it could submit the prescribed

undertaking report to the Commission to demonstrate

that it has acted in accordance with the regulation.


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So I just wanted to get some clarification of what the

expectation is of BCUC's role in regards to the report

to the Minister.

Can we confirm that the Commission is not

expected to review or grant approval or is it just --

if it's filed to the Commission is it just filed for

information?

MR. WOLFE: It is just for information purposes only. It

would not have a role.

MS. DOMINGO: Thank you. And then the following question

is 1.3, and this question talks about the potential

over expenditures. And in the response FEI states

that the Minister will determine whether the

expenditures, and we're talking the over expenditures

in this question; whether they would fall within the

parameters of the regulation. And the net result

would be that the Commission would consider the

eligibility of these excess expenditures for recovery

in rates by applying its normal test. For example the

prudency test.

And then also in another response, this is

4.5.1, the company also states that the Minister, not

the Commission, would use the utility's expenditure

with respect to the prescribed undertakings. And

further on there it also states that the need for the

incentives and the prudent execution of those


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incentives are part and parcel of the decision to pay

out the funds.

So I just wanted to get some clarity on

those items. Is the company indicating that any over

expenditures could or would be subject to a prudency

review by the Commission? And that all expenditures

and costs made within the setting limits are

automatically assumed to be prudent? Is that your

position?

MR. WOLFE: The costs made within the $62 million

envelope are reviewed, or will be reviewed by the

Ministry and it will be their determination whether

those were reasonable or not. We don't intend on

spending more than the 62 million. It wouldn't be our

intent and we would be tracking the dollars spent so

that we didn't do that.

In the situation or scenario where we did,

it would be because we thought that that was a prudent

expenditure and we would -- similar with any other

expenditures we make, as a utility we feel that they

are prudent at the time and wouldn't expect a prudency

review on those unless the Commission found otherwise.

MS. DOMINGO: So it is possible. You don't expect a

prudency review, but it is possible?

MR. WOLFE: I think that is within the Commission's

jurisdiction.


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THE CHAIRPERSON: Excuse me just for a moment. May I

just jump in to a question that was being asked, and I

hope I don't take Commission staff off track here, but

we're talking about the Ministry making a judgment,

and I may not have the words quite correctly here, but

the Ministry making a judgment on the appropriateness

of over expenditures. That was, I think, what we were

referring to.

MR. GHIKAS: Over expenditures or did you mean making a

judgment about the expenditures within the -- I just

didn't understand. You used the term "over

expenditure". I'm not sure if --

THE CHAIRPERSON: I had the impression we were talking

about spending beyond what is in the regulation, but

it may in fact have to do with spending within the

regulation. In any case, I'm just curious, and

perhaps you could point out to me in the regulation

where it describes that scenario.

MR. GHIKAS: That money is being spent beyond the

envelope?

THE CHAIRPERSON: Well, where the Minister has discretion

to determine the appropriateness of expenditures

within the regulation. Where does it say that in the

regulation?


MR. GHIKAS: It doesn't say that. It doesn't say that.


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The regulation, in my submission, Mr. Chairman, is

that the -- that the regulation has supplanted a needs

assessment prospectively, and it also prevents the

Commission from going back after the fact and

challenging the nature of the expenditures by virtue

of whether or not they were -- whether or not they

were required.

If those expenditures are being undertaken

within the parameters of the regulation itself, my

submission would be that those are by definition

prudent expenditures.

THE CHAIRPERSON: Yes, but my question, and I think I

have the answer to it, the question relates to a

statement that I think I heard Fortis saying, and I

could go back later in the record, that the Minister

would -- the Ministry or the Minister would have

discretion to determine certain aspects of these

expenditures, the appropriateness of them, perhaps. I

thought you had said expenditures beyond the limits

that were here, and perhaps I didn't hear you

correctly. But what you were talking about was

discretion that the Minister had with respect to

expenditures in this program, and I simply was seeking

clarification on where it specifically gives the

Minister that in the regulation -- gives the Minister

that discretion.


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And I think your answer was that it really

doesn't.

MR. GHIKAS: It doesn't say that expressly, no.


MR. PERTTULA: But it does say in the Clean Energy Act

that the reporting is to the Minister, and I think the

province kind of expected that when they -- when they

issued the regulation. If you look at the news

release that the Ministry of Energy and Mines issued,

which was Appendix A in our document, it does say "The

province will require annual reporting on the programs

being offered to review success and determine if any

changes are needed."

THE CHAIRPERSON: Agreed, but that's on a prospective

basis rather than a prior basis, as I understand that.

MR. PERTTULA: I think going back to Mr. Wolfe's comments

earlier, we intend to manage within the limits of all

the different limits of the regulation and if we felt

that we were getting close to a limit, that we would

either not undertake that expenditure or we would

perhaps consult with the Ministry about what approach

to -- could be taken, in terms of whether an amendment

might be required or whether we would just file for

that expenditure in the normal course. Like taking a

station, for example, through GT&C 12(b) rather than--

THE CHAIRPERSON: Yes. No, I understand that. Thank


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you.

Ms. Domingo, would you like to continue?

MS. DOMINGO: Thank you. And sort of in line with what

Mr. Kelsey was saying earlier, I guess -- you

mentioned earlier that there's -- the company has all

intentions to keep within the spending limits. I do

understand that, and there is several IR responses

that indicate that as well.

But there was one that I wanted to just get

some clarification on. This is IR 1.3. In there,

it's the last paragraph there. So FEI states that:

"If circumstances arise where it became

apparent that an expenditure limit is going

to be exceeded, FEI would have to seek an

amendment to the regulation or pursue

expenditures…"

I presume pursue them anyway,

"…and seek the Commission's approval to

recover those costs above the limit."

So I just wanted to get some clarification on what

means.

If the company had proper record keeping of

all the expenditures, what kind of circumstances would

involve FEI to be spending over its limit,

potentially?

MR. WOLFE: Again, as my colleague Mr. Perttula said, we


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wouldn't intend to -- the circumstance could be that

we've got more vehicles or more applicants than funds

available and we feel -- say we had $10 million of

funds left to -- under the total pot of funds and we

had $11 million of applications that we felt were

reasonable under the incentive program before we

decide to go through and to disburse all those $11

million, we would likely have a discussion with the

Ministry as to whether that was appropriate or not.

And perhaps an outcome would be an amendment to the

regulation, or if that wasn’t the case, and we still

decided that it was the right thing to do, and we felt

it was prudent, we might make those expenditures, but

then that would be outside of the prescribed

undertaking.


MS. DOMINGO: Okay. In terms of prudency, what does the

company see as the Commission’s rule in future

potential prudency reviews of the program? Earlier

you mentioned that this was possible. And I’m

speaking even -- and I’m talking about all the

expenditures, we’re talking incentive grants and even

the program costs. And even if all those expenditures

are within the spending limits, are there any

circumstances that would or could trigger prudency

review from the Commission?


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MR. GHIKAS: So, that’s another legal one. Do you want

me to just add that to the list and deal with it after

lunch?

MS. DOMINGO: Sure.

MR. WOLFE: Yes. Thank you.

MS. DOMINGO: That would be fine. And then just my last

question, and I think it’s -- in B.C. Hydro’s fiscal

2011 revenue requirement, B.C. Hydro indicated that

their exempt projects, and that is one where the

aspect of need is exempt from the Commission review,

that the aspect of prudent execution can still be

subject to Commission review. And I suppose you can

answer that within your final submissions as well. It

was just to get an understanding of what Fortis’s view

on that is, whether you agree or don’t agree with

that.

MR. NAKONESHNY: This is Phil Nakoneshny. I’ve got a few

other topics that I want to pursue with Fortis.

With regards to the approval term, we’ve

already talked about having Fortis confirm that --

whether they are expecting the Commission to have its

approval end on March 31st, 2017, or some other date.

The other question is, should the

Commission be providing its confirmation or approval

that all of the rate treatments that are being

requested are to be effective either from the OIC date


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or from the date of the application, or some other

date that Fortis is proposing? And this is certainly

with regards to Phase 1. I guess it would be with

regards to Phase 2. We’d likely be asking the same

question in Phase 3.

And then with regards to the year of

undertaking, the regulation talks about six years and

identifies the various percentages. And Fortis has

described the grants being in the 75 percent range,

and it sounded like that was a combination of year 2

and year 3. And then -- so I was just curious that

from Fortis’s perspective, like, does year 6 in the

regulation, does that end as of March 31st, 2017? So

are we talking a fiscal year? And then

correspondingly now that we’re in 2012, where are we?

Are we in half of year 1, and half of year 2? Or year

2 and year 3?

So, that’s also something you could --

either you can answer, or you can put into argument.

It would just be helpful to know.

MR. GHIKAS: Okay. We can -- whoever it is that answers

that will be -- we can come back after the break, if

you want. It may not necessarily be me on that one.

MR. NAKONESHNY: And those are the questions that I --

oh, actually there is one more that I did have. There

was some comment with regards to the grants, and the


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reason of putting them into the rate base deferral

account, with regards to the incentive having a

security aspect in the vehicle. And so, the questions

were, is Fortis -- are you getting into an ownership

interest in the truck by doing this, and under what

arrangements or scenarios would Fortis ever exercise

its rights to these securities? In other words, would

Fortis ever end up owning a truck as a result of that?

And if the truck was going to be sold,

would there be some obligation on the part of the

customer to buy out their obligation or if they sign

up a contract with Fortis related to the incentive,

are they committed if they have to follow all the way

through, or do they have out clauses?

MR. WOLFE: I think the general intent in the

contribution agreement with respect to this section is

to ensure that the vehicle is used for its useful

life, and that we get all the greenhouse gas savings

and the load on the system. So that that’s a general

intent of that section of clauses. And within that,

there are a number of options that are at the

discretion of Fortis to take in ensuring that that

happens.


Some of which -- and to trigger repayments,

some of which would be selling it, moving the vehicle


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out of service, things like that. Security interest

is a little bit more specific in that it -- that we

are asking for the security interest to be registered

so that if in some circumstance we get put ahead of

other institutions that may have an interest in that

vehicle. Again, it is trying to ensure that the

dollars that go out for the incentives result in the

benefits on greenhouse gas and load.

MR. NAKECHENY: Thank you, those are my questions.

THE CHAIRPERSON: I have a couple more questions, but let

me just canvas the room first. Does anybody in the

room have any further questions? Ms. Sue?

MS. SUE: Yes, I have a couple of questions for

clarification. The first one is in BCSEA 1.8.2.1, FEI

states that

"One of the eligibility requirements as set

by FEI for NGV incentives under the

prescribed program is that an applicant must

primarily fuel the NGVs using natural gas,

delivered through FEI’s natural gas

distribution system."

Can you provide a definition of “primarily

fueled?” Do you mean the take-a-pay volumes, a

percentage of the customer's total volumes, and can

customers take supply from other suppliers than FEI?

MR. WOLFE: Sorry, what question again? BCSEA? One


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point?

MS. SUE: 1.8.2.1. You might also because calling it

8.2.1, because I am using the one to refer to the fact

that it is the first round of IRs?

MR. WOLFE: Yes.

MR. GRIST: If you could just give me one moment here, I

am just checking what the contribution agreement --

the draft contribution agreement says on that matter.

Okay, so in the contribution agreement,

under section 1.2, described as vehicle use, "the

recipient represents and warrants to FEI the vehicles

will be primarily used in British Columbia, where

primary use shall mean at least 75 percent of total

kilometers driven in any year, or as otherwise

reasonably determined by FEI."

MS. SUE: So you are not actually making -- that doesn’t

actually -- that is not exactly what was said in the

IR response, where it says it primarily fueled. I

don’t know if there is a one to one correspondence

between fuel and kilometers?

MR. WOLFE: The next clause in that contribution

agreement, 1.3 says,

“The recipient represents and warrants to

FEI the recipient will fuel the vehicles

using natural gas fueling source approved by

FEI.”


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MS. SUE: Oh, so that you mean all of the fuel, or --

MR. WOLFE: And then acting reasonably includes directly

from FEI, from an FEI owned station, from a fueling

station which uses natural gas purchased from FEI or a

cardlock service which uses fuel purchased from FEI.

MS. SUE: Okay, thanks. So that means 100 percent of the

fuel has to be purchased from FEI?

MR. WOLFE: Acting reasonably.

MS. SUE: All right, thank you. I guess the other

question I have is BCUC 5.1, it is on page 17 of the

IR responses. Okay, and this goes back to I guess the

-- back to your slide 23, showing that the LNG that is

being used is basically 100 percent more than

forecast. And what I am asking is, I guess in that

table you show Vedder forecast, Vedder Transport

showing fuel savings of almost $9.4 million, and

doubling that would be something like close to 18.8.

Is that sort of an accurate translation of the amounts

you have in your slide and what is in this table?

MR. GRIST: It is Mark Grist here. That is a pretty

difficult one to answer on a global basis, because

each carrier’s proposed operation is different. As

part of their application for incentive funding, they

have to divulge to use what their intended use is,

where they are operating the vehicles, the total

mileage, total fuel consumption, that sort of thing.


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So it really would be specific to each carrier’s

individual application.


MS. SUE: Okay, I have one more question. And it regards

cost allocation. And it sort of goes back to this --

how much the customers that are receiving grants are

actually going to benefit. And I would like to hand

out Commission Exhibit A2-3, the North American

natural gas market dynamics. This is a Canadian

Energy Research Institute study. And I’ll give a few

minutes for the study to be handed out.

(EXCERPT - NORTH AMERICAN NATURAL GAS MARKET DYNAMICS,

A STUDY BY THE CANADIAN ENERGY RESEARCH INSTITUTE,

MARKED EXHIBIT A2-3)

THE CHAIRPERSON: In the interests of the time, I’m going

to jump in here and ask for another undertaking while

people are passing around the papers. And that is, I

would appreciate it if Fortis would come back with the

definition of the word “expenditure”, please.

Information Request

MS. SUE: And if you can turn to page 21, and the table

at the very top.

All right. On page 21 of the CERI NGV

study shows that a five-year interim return rate of 48

percent, and a 10-year interim rate of return rate of

58 percent for an LNG heavy tractor fleet of 30


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vehicles -- and this is without incentives. Given

these rates of return for a fleet without incentives

please explain why the $3.1 million for expenditures

on administration, marketing, training, and education

costs, which directly benefit the grant recipients,

should not be recovered from the customers receiving

the grants.

MR. GHIKAS: Can I just ask -- this is just being handed

out now. Perhaps we need a chance to read it before

we answer the questions. Maybe we can get back to you

on the answer afterwards.

MS. SUE: All right.

MR. GHIKAS: Unless the witnesses have had a chance to

read it.

THE CHAIRPERSON: Well, I think it would be reasonable to

maybe start the session after lunch with the response

to that question.

MR. GHIKAS: Did everybody catch the question?

MS. CARMAN: Yes, if you could repeat the question again,

to make sure we answer it appropriately.

MS. SUE: Oh, all right. The table shows that a five-

year interim rate of return of 48 percent and a ten-

year interim rate of return of 58 percent for a LNG

heavy tractor fleet of 30 vehicles without incentives.

Given these rates of return for a fleet without

incentives, which directly -- without incentives.


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Please explain why the $3.1 million of expenditures on

administration, marketing, training and education,

these costs which directly benefit the grant

recipients, should not be recovered from the grant

recipients.

THE CHAIRPERSON: Does that complete your questions?

MS. SUE: Yes.

THE CHAIRPERSON: Are there any further questions?

Okay. Hearing no response, I will take it

that there are no further questions. I did have one

question, and I can appreciate that time is rolling on

here, but my question really was triggered by the

discussion we were having earlier about the rationale

for the 75 percent level of grant compared to what

would be allowed in year 2, which would be 80 percent.

And there was discussion about -- well, it really is

covering a two-year period, some of which is 80

percent and some of which is 70 percent.


And I’d like some clarity around Fortis’s

interpretation of prescribed undertaking which is item

number two in the regulation (b), where it says,

“A grant or zero interest loan for an

eligible vehicle, do not, in a year of the

undertaking, exceed the percentage

difference as indicated in the following


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table…”

So, what are we talking about here in terms

of the year of the undertaking? What is an

undertaking, I guess, is part of my question, and how

does Fortis intend to handle this during this

transition year, year two, year three which was being

referred to earlier. Does that mean that Fortis is

committing to provide grants in this year of

undertaking -- because it strikes me that this would

be an undertaking -- provide grants of 75 percent

which will be paid out in the following year where the

limit is 70 percent. And, perhaps as importantly,

what happens then at the termination of the program

where we talk about total expenditures on the

undertaking, during the undertaking period, which ends

the end of March, 2017. What level of precision do we

have around that date in terms of the difference

between undertaking and expenditure, if you understand

what I mean?

MR. WOLFE: I think key in that is that these amounts

here, if you forget -- take away the idea year, key is

that those are maximum amounts.


MR. WOLFE: That could be given out in a given year, so

whether it is year one or two. Year one you can give

out a maximum of 100 percent.


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When we were looking at our program design,

and also taking into account we had given out

incentives already to the 5.6 which are part of phase

3, those we gave out at 100 percent. So, the spirit

then, disregarding the year concept, the spirit would

be if we’ve already given out incentives at 100

percent, and it is a time period after that, we would

move to the next maximum limit, which would be 80

percent in that next tranche of funding disbursement.

So, I think we might have to take it back

as far as which is the official year one start date,

and how does that factor in to the 2017, but the key

there is that the maximum, as long as it is not

exceeding that maximum in a given year, and whether

this is year one or two, the incentive amount is below

that. I think when it comes to the end date, though,

that end data is fixed, we may run out of funds before

that point in time, depending on the uptake of the

program, but the end data is fixed within the

regulation.

THE CHAIRPERSON: Well, I guess to be more specific, are

you assuming that because you have undertaken to

provide grants at the 75 percent level in year two,

which has that 80 percent upper limit, you are then in

a position to undertake grants in year three at 75

percent, because you didn’t use that extra five


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percent in the previous year?

MR. WOLFE: I think the overall intent would be that we

tried to get as many vehicles on the road as possible,

and that means -- which in part was why the grants are

meant to reduce over the year. I think our intent

would be, then, that the funding in this round was 75

percent. Then we would drop to the next tranche of

funding, which would be 60 percent at that point in

time, and that the specific date for that next tranche

hasn’t been determined yet.

THE CHAIRPERSON: Well, I don’t think you are answering

my question. My question is, in year two, your upper

limit is 80 percent. My understanding is that you are

in that process today, and what you are doing is you

are providing grants or you are proposing to provide

grants at the 75 percent level. I understood your

rationale for that to be that there was pretty good

demand for this and you could probably back off the 80

percent a little bit. That may or may not be your

rationale. In any case, you had talked about really

combining the two years together, the 80 percent year

and the 70 percent year, and so you are going to

provide grants at the 75 percent level.

My reading of this regulation doesn’t

provide the latitude for you to provide grants in year

three at 75 percent. It says 70 percent. So I am


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just curious to know how you see yourself being able

to blend the two years together and provide grants at

the 75 percent level in year three. And year three is

easy to determine, you just simply start with the year

six, and you count the years back. How does Fortis

see they have the authority to offer grants at the 75

percent level in year three, when this table sets a

limit of 70 percent?

MR. PERTTULA: First of all, the regulation doesn’t

specify a start date for that six year period. We

answered an IR about whether other utilities could

participate in this, and for example, if maybe Pacific

Northern Gas decided that they wanted to do that, they

are enabled to by the regulation. And they could

start their program at a different date, and have that

be the first year of the prescribed undertaking for

them.


So, there is not a -- sort of a mechanical

calculation backwards from -- March 31st, 2017 to get

those six-year periods. I think we -- in our

situation, we provided information to the government

about what we thought this program was going to

produce in terms of results, and in blending the two

years together, we’re staying under the -- technically

the 80 percent cap, if -- and we could actually --


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we’re not actually prevented from bringing more

funding in, but we made presentations to the

government about how much success we thought we would

have with this program, and we’re trying to comply, or

deliver, on that success even though we’re not

technically constrained to the spending equally in

sort of five one-year increments over five years.

MR. GRIST: Maybe I can just add to that. So, for this

round, we are operating within that year two guideline

of the cap of 80 percent being the high level. We do

have flexibility to bring some money forward into that

program as the regulation is defined. But to stay

consistent with the intent of our discussions with the

Ministry, we brought it down to the average of the --

for the monies we’re bringing forward. That’s all

consistent with what is allowable under the

regulation. And we have confirmed that with -- or

through our discussions with Ministry staff, that they

are okay with the approach we’re taking on this.

MR. GHIKAS: Is your -- just for clarity, and maybe

you’re ships passing in the night here a little bit.

Is your question -- so this year is year two.


MR. GHIKAS: And they’re operating under the 80. Next

year, would they be able to offer incentives higher

than 70?


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MR. STOUT: And I think -- Doug Stout -- the answer to

that would be “No.” We’d have to be under the gap for

next year. So the incentives for this year would be

granted each year.

THE CHAIRPERSON: Let’s use the term “grant”, okay?

Because we’re not talking about incentives.

MR. STOUT: Sorry, grant. Sure, yeah. So, grant, the

grants would be -- could be awarded this year. But

the next round of grants would have to be below those.

Below that 70 percent cap.


MR. STOUT: Yeah.

THE CHAIRPERSON: Okay. That, I think, concludes the

question period. And after lunch, and I’m proposing

we reconvene at 2:00, will that provide people with an

opportunity to sharpen up their pencils and prepare

for the submission section? Also, I’d appreciate it

if you could bring those undertakings back and file

those at that time.

We’ll reconvene at 2:00. At that time, we

also have the answer to one question, I think, that

was going to be researched. That -- yeah, with

respect to that exhibit. What I will do, in starting

the session off, is just determine who in the

intervener group wants to make a submission and how


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much time they think they need, and then we can design

our schedule at that time.

So let’s reconvene at 2:00. Mr. Fulton,

did you have a question or a comment?

MR. FULTON: Yes. Just -- yes, I do have a comment.

Order G-127-12 provides that Phase 2 is to start at

1:30. So that given the delay of this morning, it

would be your intention, I take it, Mr. Chairman, to

have Phase 2 commence shortly after the conclusion of

the Phase 1 submissions.

THE CHAIRPERSON: That’s correct.

MR. FULTON: Okay.

THE CHAIRPERSON: Thank you. Enjoy your lunch.

(PROCEEDINGS ADJOURNED AT 12:56 P.M.)

(PROCEEDINGS RESUMED AT 2:01 P.M.) T47/48

THE CHAIRPERSON: Let’s resume where we left off, and I

think we had a couple of leftover pieces of business,

a couple of undertakings and the response to an

exhibit that had been shared around before lunch. So,

let’s deal first with the two undertakings.

MR. GHIKAS: Mr. Chairman, we’ve circulated the complete

article of the excerpt that was provided by staff

before lunch. So this is the North American Natural

Gas Market Dynamics - Natural Gas Vehicles, A Review,

dated March, 2011. And it’s -- I think it’s B-10,

Exhibit B-10. Thank you.


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(NORTH AMERICAN NATURAL GAS MARKET DYNAMICS - NATURAL

GAS VEHICLES, A REVIEW, DATED MARCH 2011, A STUDY BY

THE CANADIAN ENERGY RESEARCH INSTITUTE, MARKED AS

EXHIBIT B-10)

MR. GHIKAS: And I won’t be speaking to this. I believe

-- is it Mr. Stout that’s speaking to this? For --

okay. Sorry.

MR. STOUT: Mr. Wolfe.

MR. WOLFE: So on that one, responding to staff’s

question about the article and the $3.1 million in

education, training, marketing and admin expense,

before we get into the actual document from the

Canadian Energy Research Institute, I’d like to draw

everyone’s attention to responses from BCUC, 6.5.1.

In that response, we break down what the

activities are within that 3.1 under administration,

all the various different components there, such as if

awarding and managing the grant process; in the

marketing component, that includes public

communication, information sessions, et cetera. And

in the education and training component, that is

developing training programs, working with

governments, colleges, to deliver training, and

program verification. So, these -- the costs, the 3.1

million that goes to this don’t directly relate to

those who receive incentive awards. It’s a much


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broader group than just those that receive incentive

awards that this applies to.

If I can then draw your attention to BCUC

IR 8.1, in this we note that the regulation doesn’t

make a distinction between cost of grants or loans and

expenditures for administration, training and

education. And if you put those two responses

together, it is our position that the 3.1 million

relates to certainly more than just those customers

that received incentives. From a cost causality

standpoint that would suggest that because the

benefits flow back to all customers, all customers

should pay for those costs. And there is no

distinction between that 3.1 million and the rest of

the incentives as part of the $62 million bucket.

From there I would like to turn it over to

Mr. Stout to discuss more about the CERI document.


MR. STOUT: Yes, just kind of following on, if we look at

that, there is a table at the top of the page, and

then there is a paragraph that starts with, “The

challenges of implementing the roadmap” with the

heading?

MR. GHIKAS: What page?

MR. STOUT: Pardon me, on page 21 of the document.

MR. GHIKAS: So the excerpt, just for clarity, the


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excerpt provided by staff was pages 20 and 21.

MR. STOUT: So I just thought in looking at that one, it

was kind of informative here, that, you know, given

the kind of context laid out of the some scenarios and

the benefits here, there is still a large market

failure as noted by Enercan, about four sentences down

here, "for the market failure in Canada’s

transportation sector are formidable barriers to entry

for natural gas adoption. Imperfect information, lack

of choice and externalities." And notes that all of

these conditions are present in Canada today, and it

also points to a lack of education about vehicles and

participants in the marketplace need to know what they

are getting.

But if we go on to the next page, it talks

below the tools of the stakeholder disposal and onto

the next page where there's four points, which include

fiscal measures as we are talking about today, and

regulations. But the information, the educational

strategies through outreach hubs and these type of

things, and we are working on, as we go through this,

those types of programs with Enercan. We worked with

Enercan and B.C. Government and other parties in the

road map through these network hubs, through the

Canadian Natural Gas Vehicle Alliance, that reach out

to a broad range of stakeholders in the marketplace.


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So I think it is, you know, we provided the

whole excerpt, I thought it was -- when you read the

whole document it kind of follows along the whole, I

think lays out in summary the line of reasoning that

the government went through and other stakeholders of

what it takes to move things along. And in particular

is the educational side of things, training being a

key component of where we need to go, tied in with the

cash rebates and incentives.


MR. GHIKAS: The other matters, the undertakings that

were left by yourself, Mr. Chairman, were the

definitions of expenditure and grant from the

dictionary. The definition of “expenditure” from

Webster’s has been put on one sheet, and that would be

B-11. And the definition from Oxford on “Grant” is B-

12.

(DICTIONARY DEFINITION OF “EXPENDITURE” FROM WEBSTER'S

DICTIONARY MARKED EXHIBIT B-11)

(DICTIONARY DEFINITION OF “GRANT” FROM OXFORD

DICTIONARY MARKED EXHIBIT B-12)

JUSTICE: Just a matter of clarification then, is it

Fortis’s understanding that -- I refer you to

prescribed undertaking 2 and specifically the table

which calls for the end of year six, which I believe

is March 2017, and then (c) below that, total


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expenditures on the undertaking during the undertaking

period. Is it Fortis’s position then that that will

be the end date of the expenditures as defined by this

definition?


MR. PERTTULA: We provided an IR response, and

unfortunately I don’t have that right at hand here,

but we said that if we are under a firm contractual

commitment to carry out a prescribed undertaking -- or

a fueling station or provide incentives prior to March

31st, 2017, but say, for example, the vehicles didn’t

arrive until after that date, we would make the

incentive payments afterwards, and they would still be

part of the prescribed undertaking. But still subject

to the overall $62 million cap. So, that slight

qualification to March 31st, 2017, being the very last

day that money can go out the door.

THE CHAIRPERSON: Is that what Fortis proposes to do, is

that consistent with the definition here?

MR. GHIKAS: Which definition, sorry?

THE CHAIRPERSON: The definition that you’ve provided on

expenditure. And I’m just really trying to clarify

this now, so that we don’t have misunderstandings

about this later. That’s my intention.

MR. STOUT: It’s Doug Stout. Yeah, I think -- I mean,

for the way we’re looking at is that we have made the


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expenditure, past tense, or have a commitment to that

expenditure that fits within the undertaking. But

that commitment made before that end date of the

program.

MR. GHIKAS: The way I would answer that, Mr. Chairman,

is -- if there is ambiguity in the regulation, and I

applaud your initiative in terms of trying to nail

that down, because I do think it’s very important to

be nailed down. It really depends on whether -- on

how you define “expenditure”, whether it’s actually

the physical -- the cash leaving your hand, or whether

it’s a commitment to expend. And in -- you know, in

BCUC IR 1.4.3, we talk about in terms of an

expenditure in a general regulatory context that, you

know, it’s the commitment that’s driving it. But I

100 percent agree with you, there is ambiguity here.

And in my submission, it’s a reasonable

interpretation, what FEI is proposing to do.

THE CHAIRPERSON: Okay. Well, I’m going to suggest that

the decisions we’re being asked for at the moment

don’t turn on this particular matter, but I think it’s

important that we have a clear understanding, both so

that Fortis can be plan-ful in its work and also so

the Commission can be appropriately diligent in its

regulatory oversight. And so I think we’ll punt this

one side and perhaps we could do it as necessary, do a


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short written process on this quite separate from

what’s going on today. Because I think it is

important that we have a measure of certainty on that.

MR. GHIKAS: And, Mr. Chairman, that’s an option, and

certainly I think it would be within the parameters of

what you do today to also make a determination.

THE CHAIRPERSON: Yes, so I understand that, yeah.

MR. GHIKAS: I think the company would --

THE CHAIRPERSON: But I just think that it’s important

that if we are going to make a determination on that

today, it’s important that everybody have an

opportunity for input to that, which we haven’t

provided notice on and people haven’t had that

opportunity. So, and I’m not trying to drag the

process out, but I just -- I’m really trying to avoid

questions that Fortis may have going forward, in terms

of running your program and questions that the

Commission might have in terms of its oversight of

this. We may all be somewhere else in 2018 or

whenever it is this gets reviewed, and it’s important

it be nailed down earlier rather than later.

Okay. Another comment?

MR. PERTTULA: Just that -- just for the record, the IR

that I was referring to was BCUC IR 1.1.

THE CHAIRPERSON: Thank you. Okay. I think now we’re at

the point where we will deal with submissions.


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Mr. Fulton, have you a sense of what a

schedule should look like here?

MR. FULTON: We’ll start with Fortis, and then followed

by BCPSO, BCSEA, CEC, and I don’t believe -- is

someone from the MEMNR still on the line? No.

MS. IANNICIELLO: Yes. Christina Ianniciello is still on

the line.

MR. FULTON: Okay. Is the MEMNR going to make any

submissions?

MS. IANNICIELLO: Yes, only about 30 seconds. I just

have a statement to make.

MR. FULTON: Okay. So then the order will be BCPSO,

BCSEA, CEC and MEMNR followed by Fortis reply.

So, we’ll start with Fortis.



SUBMISSIONS BY MR. GHIKAS:

MR. GHIKAS: Thank you, Mr. Chairman. I circulated

yesterday a document that was filed and marked as

Exhibit B-6, which was an outline of my written

submissions, and you can rest assured that I will not

reading that to you, nor will I be following it all

that closely. I just plan to make some more general

comments and highlight a few, a very few particular

points that have come up in the course of today’s

proceedings. So, but I do propose that if you have


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that handy, we’ll touch back to it at certain points,

and we’ll take it from there.

And I should say it’s my intention to make

these general comments now and not repeat them again

in an hour’s time when we do this. But they do apply,

a lot of them, to both phases.

Mr. Chairman, my submission is that the

clear implication of Section 18 and the GGRR is that

first of all that the Commission’s jurisdiction has

been modified, and in some places replaced by

reporting to the Minister. And the second point is

that, where the Commission does have jurisdiction,

that the statutory framework in Section 18 requires

the Commission to exercise that jurisdiction in a

particular way, and that is, in a way that helps to

ensure that this initiative as a whole is a success.

And in particular, there is some wording in 18(3) that

deals with not -- you know, not interfering directly

or indirectly. And we can come back to that later,

but those are my fundamental points.

These points have, in my submission, both

substantive consequences and procedural consequences

for what we accomplish today and what the Commission

does coming out of this proceeding. On the

substantive side, this application, in my submission,

is, first of all, it’s not about justifying the need


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to undertake these expenditures. It’s not a CPCN

application, nor is it the equivalent of a CPCN

application. That the need has been established by

the regulation.

The second point substantively that flows

from the framework is that the rate constructs that

the Commission does put in place as an outcome of this

proceeding has to ensure full cost recovery. And that

flows from the Act as well.

And thirdly, on a substantive point, is

that it has to affect the lens through which the

Commission is viewing these alternate rate constructs

that permit the cost recovery, and when I say that,

and I was trying to think of what the best way to

describe this is, but in my submission I would urge

the Commission to adopt a positive lens and not a

defensive lens, if I can use that phraseology. It’s a

bit awkward, but I think it conveys the message, in

that really if the Commission is given a range of

options, of rate design options, the options that the

Commission should be pursuing and going with is the

option that is most likely, in the Commission’s view,

to make this initiative a success. And that’s the

frame of reference that the Act requires the

Commission to approach this issue from.

Now, I said there were also, in addition to


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substantive implications, procedural ones. And in my

submission, the procedural implication from this is

that the Commission must take the necessary steps in

this proceeding at the earliest opportunity, which is

this proceeding, to bring certainty and clarity to the

way in which this program is going to be undertaken.

And our last exchange, Mr. Chairman, dealing with the

necessity of dealing with these little issues, up

front, is bang-on this point. And it is that a

prescribed undertaking like prescribed undertaking 1

or 2 and 3 can only work if everyone understands the

ground rules.


And it is not just for FEI, but there are

actually customers out there who are seeking

incentives in this case, and they are coming into this

looking for -- about to make a serious business

decision. And in order to make that business decision

they are weighing all of the risks that Mr. Grist

outlined, and it is a serious implication for their

business. And when they are coming in and they are

making an application, and they are being told now,

you are getting a grant, the expectation is they’re

getting a grant. It is not that something will change

in 2017 and the Commission will come back and say, by

the way, that money that Fortis gave you isn't a


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grant, it is actually going to be taken back through

whatever rate you are paying under a rate schedule

that you are taking service under.

And so in my submission, that -- just the

fact, the mere fact of that uncertainty that these

issues are being raised now, is casting a cloud over

this that the Commission, in my submission, has an

opportunity to deal with and dispose of once and for

all. The most important thing here is that everyone

knows the rules by which we are playing, and so Fortis

would urge the Commission really to take the time and

the care to spell out how it sees this unfolding. And

parties may or may not agree about that, but there are

processes through which you can deal with that, at

least. But it allows everybody to know what the lay

of the land is, and it gives everybody a fair shake to

actually make this thing a go.

One thing that is absolutely clear is that

government wants the utility to do this, and invest

significantly in a program to achieve its legislative

objective. The company clearly agrees that it is a

good thing, not only just because of the greenhouse

gas implications, but also because they believe it is

a good thing generally, and you heard the witnesses

earlier speak to that. But if everybody wants to make

it a success, the fundamental thing is that everybody


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knows what the rules are in advance.

So, first of all, I am just going to go

into these issues in slightly more detail here, and I

will just turn you to paragraph 5 of the written

submissions, and this really is just building on what

I’ve said before and the point that I am making in

paragraph 6, where I refer to the wide range of topics

that are covered in this proceeding, is that much of

the attention in the proceeding has been on matters

that really the Act and the Regulation have already

conclusively determined, and that is not to say that

-- that is not to fault anybody for asking the

questions, and Fortis has put materials in for

background. Everybody appreciates that you know, we

are all kind of -- this is new to everyone, and there

is a desire to have more information and a dialogue,

and that is a good thing.

But, I raise that only because strictly

speaking, and legally speaking in order to decide this

application, the Commission doesn’t need the type of

evidence on the issues that are described, for

example, in footnote 2 on that page. It doesn’t need

information on the quantification of benefits and

costs. It doesn’t need information on the costs of

particular program elements. The open and competitive

process is something that is being done as Mr. Wolfe


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described in consultation with the Minister and a

fairness advisor. And the Commission doesn’t need to

look into whether a zero interest loan is better than

a grant and what not. Those matters have been

determined by the regulation, and are being discussed

on an ongoing basis with the Ministry.

So, if one sifts through that information,

we really are left with one substantive issue, and

that is how to ensure that the costs are recovered

with rate structures that advance and don’t impede the

regulatory -- sorry, the intent of the regulation.


Now, the paragraphs -- you will see in

paragraphs 7 and 8, I site a passage from the

Ministry’s submission in the AES inquiry, which deals

with the modification of the Commission’s

jurisdiction. FEI would adopt that provision.

Now, in terms of paragraph 9, it’s in that

paragraph that I really spell out what I’ve already

dealt with in some detail, which is the importance of

having the certainty in this proceeding. And really,

another way of putting that is, we saw in the slide,

the graphic slide of what we’ve all been through over

the past three years to get to a point where we have

effectively four NGV customers, you know, going

through a number of processes over a period of time.


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And the Commission has -- and those processes, you

know, have been really in a lot of ways a stop/start,

a two steps forward-one back kind of process, as we

work through this. But what this regulation provides

us with the opportunity to do is it really allows the

Commission to cut through the chaos of the noise

that’s in this chart, and create something that allows

us with certainty to move forward today, and not wait

for the outcome of those proceedings, but really move

forward today.

It’s a time-limited opportunity, and that’s

why it’s so important that the Commission take the

earliest opportunity to make these -- bring clarity.

So how does the Commission bring that

clarity? Well, in paragraph 10, I set out Fortis’s

understanding of how the regulation works. And at

this point I’m going to speak to a couple of the

undertakings -- or a couple of the questions that were

left by staff prior to the break, focusing really -- I

don’t propose to read all of those now, but really the

point in (e) is really getting to the question that

Mr. Nakoneshny raised, which is, what’s the

Commission’s role, in essence. What’s the

Commission’s role in assessing the prudency of costs

that actually fall within the parameters of the

regulation, that qualify as a prescribed undertaking.


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And my submission on that point is

fundamentally that the regulation states that costs

are recoverable if they meet the parameters under the

regulation. And the presumption in the question put

to us by staff really assumes that they are within the

parameters of that regulation. And in my submission a

prudency review is a mechanism whereby the Commission

denies cost recovery, and those, in my submission,

those two ideas that costs are recoverable and that

the Commission could come along later and deny cost

recovery based on a prudence review are fundamentally

incompatible.

Now, what comfort do we have, then, you may

be asking. Well, what we do have is compliance with

the regulation itself, and the regulation itself

contemplates steps built right into the parameters of

the prescribed undertaking that FEI has to undertake

in order to allow the expenditures to qualify for the

treatment under the regulation, for full cost

recovery. And it assumes compliance with an open and

competitive process, for example.

And the evidence, of course, is that FEI is

doing that in consultation with the Minister. And

also involving a fairness advisor. So, the comfort

comes from the fact that the funds are being awarded

in a manner that the Minister considers to be


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appropriate, which is this open and competitive

process. And having taken those steps, to put in

place that process, and have funds distributed in

consultation with a fairness advisor, that, in my

submission, it doesn’t leave room for the Commission

to come back after the fact and make determinations

about whether incentives ought to have been a little

bit higher in this case, or a little bit lower, or you

know, whether or not the process should have been

tweaked differently to yield different results or the

parameters of the process should have been different.


In my submission, the fact is that the

mechanisms have been put in place by the regulation,

and that they contemplate a scenario which is exactly

what is being done today, which is that Fortis is

talking to the Ministry, and designing the mechanisms

so that the Ministry knows in advance what the

outcomes are going to be. And although the reporting

is ex-post, there is not going to be any surprises if

they are being distributed in furtherance of a process

that the Ministry has been involved in designing.

So, there was also a question, I believe it

was from Ms. Domingo, and the question was, as I

understood it, and I didn’t get it all down, so maybe

you can correct me if I didn’t quite get it, but as I


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understand it is how does this differentiate between

what B.C. Hydro is dealing with under their exempt

projects?

MS. DOMINGO: Right.

MR. GHIKAS: Okay. All right, there is an IR that deals

with this, Mr. Chairman, it is BCUC 1.4.5.1, and what

you have here is a scenario where you’ve got not only

the need established, but also an amount. You’ve got

parameters established for these incentives, and

you’ve also got a process that is set up, such that

the ministry is, as I was indicating, participating in

development of an open and competitive process. So,

when you have that type of model, the decision to

dispense the funds is occurring at the front end, it

is not like a construction project where you are

getting approval, and then there is a huge long

construction period where a whole bunch of things

might happen to change the amounts that are in

question, and the ultimate cost of the project.

What you have here is a decision to

dispense funds, and then funds are dispensed. And if

the process for distributing the funds is right, and

it is within the context of the envelope that is

provided, the decision is going to be prudent. The

execution and the decision to distribute the funds is

one and the same in the context of an incentive. So,


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in my submission, it really is a matter that the Act

has -- or sorry, the Act and the Regulation have set

up the scope of the review, and in my submission, the

costs are recoverable, because the Act says they are

recoverable.

Now, in point (i) on the submission on page

5, costs associated with prescribed undertakings in

the period while the GGRR is in effect, I should say,

do not become open to challenge by virtue of the GGRR

expiring in 2017. And I can add to that really they

shouldn’t -- rate design changes shouldn’t be made

either, that go against what is being done during the

period as well.

You know, it really is a scenario where --

let me start by saying, before the lunch break the

question was posed to me, well does the Commission

have jurisdiction over the rates, to change the rates?

Well yes, the Commission has jurisdiction over rates.

It does now, and it does then, but it has to exercise

the jurisdiction within the confines of the

regulation. And there really is no reason why

changing the -- why the Act -- or sorry, why the GGRA

expiring would cause a need to change the financial

treatment associated with grants, who they are

recovered from.

You know, the Commission could -- it comes


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back to what recipients of these grants think they are

getting. They think they are getting a grant. They

think they are getting a grant, and really what this

would amount to is coming back in 2017 and saying it

is not a grant, it is a loan, we are coming back to

get it from you because we’ve changed the rate design.

And in my submission, first of all it is fundamentally

unfair to those parties, and second of all, nothing

has happened in 2017 other than the regulation

expiring, that would actually warrant changing

something with respect -- all of the circumstances are

still in place that would justify having the

collection coming from a particular group of

customers.


So, you know, in my submission, that really

is not a basis that the Commission would revisit the

allocation of costs under the GGRR.

And I should say, back to my point about

certainty, that, you know, for the Commission to put

out that signal now, it really is an obstacle to

making this a success. It would be -- it’s an

obstacle to FEI investing the funds and it’s an

obstacle to the customers who would otherwise be

taking the incentives, adding one more risk back onto

their consideration.


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The submission does deal with in part 3,

starting at paragraph 12, the detailed aspects of the

financial treatment of the accounts proposed. Ms.

Carman dealt with those very well, and I’m not going

to repeat what she said. I think that her evidence

speaks for itself. So we can skip over that, and deal

-- and come right down to the issue that’s addressed

starting on paragraph 25, which is the recovery from

all non-bypass customers. And in the course of

addressing this, I’ll also address the question that

Mr. Nakoneshny had, of relating to separate classes of

service.

So, it is correct that neither the Act nor

the Regulation expressly stipulates from whom the

customer -- from whom the costs should be recovered.

But it is implicit -- it is explicit that the

intention of the legislature is that both grants and

zero interest loans be made an option to the public

utility. And it’s a principle of statutory

interpretation that when the legislature uses

different terms, like grants and zero-interest loans,

they’re assumed to actually mean something different.

And in order to give effect to grants and zero-

interest loans, one cannot interpret the Regulation as

permitting recovery of grants from the same customer

who’s getting those -- who’s getting the grants.


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Now, there is obviously in the area less

than 100 percent recovery from the -- let me back up.

The thrust of some of the questions, Mr. Chairman,

that we got from the Commission earlier today was,

well, what about something less than 100 percent

recovery? And my answer to that is, okay, well, there

is probably a grey area, based on the interpretation

that I have given you, that already under a grant

there is some of that cost that’s being recovered by

virtue of being recovered from all non-bypass

customers. Some of it is coming from those same

customers. So there is a small amount there. So

there is obviously a grey area.

But in my submission there is two things

that speak to why the Commission should accept

recovery from all non-bypass customers, rather than

trying to allocate more to the specific customer, the

specific party that’s receiving the incentive. And

the first one is this, that it comes back to the lens

that I say the Commission should be looking at this

through. And the Commission should be asking itself

what is the best way to make this a success? And in

my submission, the clear answer to that is that the

costs should be spread out among a larger group of

customers.

The framework of this regulation is not


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intended to do the absolute bare minimum such that we

may or may not inhibit take-up. It’s that the

government is saying, “We want to make this a

success,” and in my submission the rate design that

FEI has proposed is the one that will most likely make

that a reality.

The second point is that while NGV

incentives are not EEC incentives, the principle

underlying them is the same. And that is, it’s trying

to incent, by virtue of government policy, people to

do things that they otherwise would not do. And in

that context, the EEC context, the approach that’s

been taken to ensure that that is a success is the

very one that the company is putting forward here.

And in my submission, that should be compelling in

this circumstance.


Now, before I move on I will deal with

specifically the question of should we put these costs

associated with prescribed undertakings 1, and 2, and

3, in a separate class or keep it, you know -- to keep

it separate in case we need to change the treatment

down the road. Well, I’ve already spoken to the issue

of needing to change the treatment, but that entirely

aside, the question approaches the issue in a

backwards way in my respectful submission. A class of


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service isn't a tool that is included in the Act in

order to ensure segregation of costs. Segregation of

costs flows from a finding that the utility is

offering more than one class of service. And a class

of service is defined by the characteristics of the

service, and it is not defined by whether or not

something needs to be segregated for accounting

purposes, to keep it separate, or isolated or not. It

is do they offer more than one service? And of

course, this comes from a time when we had B.C. Hydro

offering electric and gas, and you know, trains and

all sorts of stuff. And really, this is what that

section is designed to do. And segregation doesn’t

require a class of service. Utilities segregate costs

all the time, it is what they do.

Ms. Carmen gave evidence today about

everything is being kept separate and tracked, and so

we don’t -- first of all, we don’t need this construct

of a class of service just to keep things separate,

and second of all, it is truly twisting that section

around in the UCA, section 60 around, where really it

is simply if the utility offers a separate class of

service, offers more than one class of service, then

you should keep separate. That is effectively what it

says.

And of course, these costs are related to


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the natural gas business. As particularly with

prescribed undertaking 1, these costs are being

provided to customers to promote use of gas on the

natural gas system. This is like an EEC type of idea,

only it is building load, not reducing it. But it is

just as much part of the natural gas business. It is

not tied. These vehicle incentives aren’t tied to

fueling stations being offered by FEI, the issue about

classes of service is one that deals with these

fueling stations. It is not relating to throughput on

the system as a whole. So, in my submission, the idea

put forward has no merit, and that if the Commission

wishes to have costs segregated, the mechanisms that

have been put forward are more than suffice for that

purpose.

The last point I will touch on before I

wrap things up, and it will sort of segue way from

what I finished up on. It is in paragraph 28 of the

submission, it is dealing with the point that the

Commission can and should proceed here to provide

final approvals, not interim approvals, but final

approvals with respect to phase 1 of the proceeding

regardless of the outcome of other proceedings related

to NGT. And really this point is there is no need to

wait for the AES inquiry. If I can just put it in

simple terms, that is what this submission is saying,


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is you needn't be concerned with the fact that the AES

inquiry is ongoing, when it comes to these phase 1

expenditures. I will deal with phase 2 and 3 in the

afternoon. But, it really ties in to what I just

said, is that these incentives are not related to

those fueling stations. An AES Inquiry, the debate is

about the fueling stations when it comes to the

classes of service. So in my submission, the

Commission can proceed with confidence making the

orders sought, and that in doing so it can really

provide the requisite certainty that we all truly

require in order to make the regulation a success.

Thank you.

THE CHAIRPERSON: Thank you, Mr. Ghikas. Mr. Fulton?

MR. FULTON: Yes, B.C. Pensioners and Seniors

Organization et. al?


SUBMISSIONS BY MR. BRAITHWAITE:

MS. BRAITHWAITE: Yes, Tannis Braithwaite, BCPSO.

In my submission, Fortis has overstated the

restrictions that are placed on the Commission’s

jurisdiction by the regulation. I submit the

Commission’s jurisdiction is restricted only to the

extent that it’s explicitly ousted by the regulation

itself. It’s fair to say, I think, that the

regulation does make clear that the government sees a


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need for this program, and it sets out the maximum

amounts that can be provided under it for grants or

loans. But it doesn’t specify the form that the

program -- the form of the program design itself. It

leaves it open as to whether grants are provided, or

whether loans are provided. And it also leaves open

issues related to the prudency of specific investments

or specific grants or loans. In my submission, the

Commission retains jurisdiction to provide input or

instruction with respect to the structure of the

incentive programs that are provided, provided that

instruction is within the scope of what’s set out in

the regulation.

In my submission, the utility also

maintains an obligation to maximize the benefits of

any programs to ratepayers and to minimize the costs

and also to consider the impact of its actions on the

public interest. And these duties are not altered by

the regulation. And that the Commission’s duty to

ensure that those obligations are met is not altered

by the regulation.

In other words, BCPSO submits that the

Commission retains jurisdiction to require Fortis to

design programs that meet the objectives of being in

the public interest and maximizing benefits while

minimizing costs.


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It seems apparent that the purpose of the

regulation, as well as the interests of ratepayers and

residents of the province in general, are best served

by getting as many natural gas vehicles on the road

per dollar as possible. And part of what we say the

Commission should be doing is taking care -- or

rather, I guess, ensuring that Fortis is taking care

not to over-incent vehicle purchases.

We’ve heard evidence about the benefits

that are accruing to natural gas vehicle customers and

I appreciate that there are barriers to overcome to

inducing new customers to come up -- to come in and

adopt what is kind of a new technology. But it seems

like even having one LNG transportation customer has

had the desired effect. They have had 19 applications

for this go-around.

And we’re not convinced that the level of

incentives that are being provided are necessary to

get take-up of the program. We’d rather see the money

spread out more.

With respect to the issue of who the costs

of the program are recovered from, we don’t disagree

that there are some benefits to ratepayers in terms of

increased throughput on the system. But it does

appear clear that the majority of the benefits are

going to accrue to the natural gas transportation


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customers themselves. And the Regulation doesn’t

specify that the costs of the programs can’t be

recovered from those customers.

Those are the only points I’d like to make.

MR. FULTON: B.C. Sustainable Energy Association.

SUBMISSIONS BY MR. ANDREWS:

MR. ANDREWS: Thank you. Bill Andrews speaking here.

The BCSEA interest in the remedies that are

requested stems from the greenhouse gas emission

reductions that would follow from implementation of

the program that the prescribed undertaking in the

regulation. And I would add to that not only GHG

emission reduction benefits, but air pollution

reduction benefits.


For the record, BCSEA does not support

expanding natural gas into the passenger vehicle

sector. But that’s not an issue here today.

BCSEA’s interest also is in the protection

of intergenerational equity, and this is a factor that

arises in terms of the rate design.

BCSEA participated in all of the

Commission’s proceedings regarding natural gas

vehicles, going back to but not including the revenue

requirement negotiated settlement process in which

NGVs were first raised.


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In this process, BCSEA asked a number of

Information Requests and got responses. It’s

carefully looked at the responses and is satisfied

with them. Many of the questions went beyond the

immediate remedy requested and, as Mr. Ghikas has

said, that was very helpful. It was helpful to BCSEA

that the responses were forthcoming, so that we had an

understanding of the context.

In the result, BCSEA supports the

application as proposed by Fortis. I have listened

carefully to Mr. Ghikas’s submissions, and I endorse

them. They are -- I think they are quite useful and

in particular -- well, a few points that I would

emphasize. One is that there are two levels -- he

said two levels, and I’ll add a third. But two levels

to the way in which the Act and Regulation affect the

Commission’s decision-making on this application. The

one is at the jurisdictional level. There are certain

things that the Commission simply doesn’t have the

jurisdiction to do that it may have otherwise had.

For example, determining whether there is a need for

incentives for NGVs.

And then there is another category of

things where the Commission may have the jurisdiction

to do something, but it’s required to exercise that

jurisdiction in a way that will foster the purpose of


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the NGV incentive program. And so that applies when

decisions are being made, in my submission, about how

the regulation, for example, in its wording ought to

be interpreted. That is, if there are two

interpretations and one of them fosters the purpose of

the program, then that’s the one to be preferred.

The issue of what the Commission may do in

the post-2017 period has come up through staff IRs and

through a discussion today. And in my submission, the

notion that the Commission would exercise its future

jurisdiction, that is, in the post-2017 period, in

such a way as to undermine the decisions that it makes

now, would be -- to do with this program, would be

contrary to the purpose of the program, and that the

Commission therefore ought to be clear now that it’s

making decisions that are intended to be permanent and

not intended to be in a sense a stopgap that confirms

a situation until the end of 2017, at which point the

Commission already intends to jump in and revisit

these issues.

I say that that would be contrary to the

purpose because I have accepted, and BCSEA accepts,

that certainty on the terms of the grants is a key

component to getting successful uptake and achieving

the purpose.

So, another way to look at that point would


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be that if the Commission were, in the alternative,

inclined to make a decision today, that would in any

way raise the possibility of what’s called in the

computer world a back door of being able to re-open

these decisions in 2018, then the Commission really

ought to ensure that all of the costs are recovered

before 2018, so that the recipients of these grants

will know for sure that it is indeed a grant and not

going to be clawed back later.


In terms of the length of the deferral

account amortization, BCSEA supports the ten-year

proposal. As has been said, it’s a balancing process.

If it is lengthened, there are intergenerational

equity problems. If it is shortened, there may be a

rate impact problem. It seems to BCSEA that 10 years

is a reasonable way to split those two competing

factors. Though, as I say, if the Commission feels

that it has to do it this way, then all of the costs

should be recovered before 2018, if that is what it

takes to provide the certainty that these are indeed

grants if that is what they are characterized as.

The last point I’d like to make is just

that the government’s direction here with this program

is clear, and to add a point to what Mr. Ghikas said,

is that this regulation didn’t come out of the blue.


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It followed previous Commission decisions regarding

various aspects of NGV and natural gas service, and so

on.

So that is to me a factor that the

Commission ought to take into account in interpreting

the fact that this regulation was issued and the

government’s intention with the regulation. That is,

the government was not simply coming up with

something, as I say, out of the blue. It was

responding to the way that things were developing, and

I am not saying that it overturned previous decisions,

that is not the issue. The point is that the

government intentionally, and I say narrowly, defined

certain things that it wanted as a matter of law to be

done, and for certain purposes, and that is what it

has done, and in my submission, and in conclusion, the

remedies that are requested by Fortis here on phase 1,

achieve that intention, and are what the Commission

ought to do. Thank you.

MR. FULTON: Commercial Energy Consumers Association of

British Columbia?

SUBMISSIONS BY MR. WEAFER:

MR. WEAFER: Thank you, Mr. Fulton, Chris Weafer speaking

for the CEC.

Mr. Chairman, as you are probably aware,

the CEC has been involved in the processes around NGV


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vehicle incentives since 2009, since the matter was

first brought forward by Fortis, and our record to-

date has to have been fairly supportive, and in fact

aggressively supportive of natural gas vehicle

incentives, and we are pleased we are here today to

speak to this. It has been a lengthy process. There

has been both regulatory and legislative investment by

Fortis and by stakeholders, and we will agree with Mr.

Ghikas’ last comment first, which is that this is an

opportunity today to create some certainty, and we

commend the Commission for embarking on the streamline

process and the streamline review today. We found it

quite helpful, and a useful process, and we will turn

to you for the decision and look forward to that.

We are all, I think, all participants,

acknowledge that the GGRR creates a need for the

natural gas vehicle incentives, and specifically

provides for cost recovery by the utility, that is

common ground. The primary issue that is on the table

we think is, as Mr. Ghikas says, the lens with which

you look through this, and Mr. Ghikas is focused on

the positive lens, and we agree with that. But it

also has to focus on the good rate making principles

lens, and the matters which are within your control

and your jurisdiction, are areas where you can look at

the positive lens, but you need to make sure you are


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fair to the customers who ultimately will pay the

bills.

We do agree with the Fortis submission with

respect to the components of costs that they’ve

identified. And we agree with their submission with

respect to the need for deferral accounts. So, let's

move to sort of the two fundamental points of -- one

is disagreement, and one is qualification I think.

With respect to the deferral account, the

CEC endorses a 20 year deferral account for the 20-

year amortization period for the deferral account.

And there is a number of good reasons for that. When

the investments around in this market transformation,

that ratepayers are being looked to pay for, are long

term, have long term implications, the investments in

LNG production upgrade has certainly a longer life

than 10 years. The life of the market and the

investments in the market will have impacts for closer

to 20 years than for 10 years, particularly if you

look at this matter through a positive lens, as the

company is asking you to do. They are asking you to

look at this as it is going to be successful. And if

that is to be successful, then there is a longer term

impact and therefore the amortization period of the

costs should be over the longer term and we say 20

years.


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Illustrative is the company’s response to

CEC IR 1.1.5, which they refer to in slide 19 today,

which looks at a net delivery rate reduction of 5.6

percent by 2030. So, they are in their evidence

acknowledging that the benefit will string out to

2030, and therefore the cost that ratepayers are being

asked to pay should also in fairness be allocated over

that expected period of time.


And so other areas that look to the long

term, certainly the government in passing the

regulation wasn’t expecting a short term reduction in

GHG, the impact is to be long term, and therefore, the

10 year period is not sufficient. The investment --

the regulation supports a long term reduction in GHG

emissions, which is one of the reasons the CEC

supported this initiative in the first place.

I think, and if you look at the record this

morning, the discussion Mr. Craig had with Fortis

also, in terms of the company’s responses to his

questions, support the longer amortization period, and

I'd encourage you to reread those discussions on the

transcript when produced.

Lastly, what if we are wrong? And what if

over the course of the next five years we see that the

positive lens was cracked and it is not successful.


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There is always an opportunity for the company to come

back and say, we think we need to shorten this

amortization period. We do not argue that they

shouldn’t recover, we are just saying that the

recovery time could be shortened if we find that the

company has not been successful in achieving the

market transformation and this goes off the rails and

the recovery time should be shortened. But let's

assume that it is going to be successful as opposed to

a failure, and so we’d support the 20 year

amortization period.

Leaving that topic, and turning to the

allocation issue, and there has been much discussion

in terms of the NGT customers contribution to this,

and as we understand the primary -- I mean, firstly,

as we understand it, the NGT customer is about .6

percent of the load, so while they are making a

contribution, they are a small part of the load, but

they are getting the significant part of the benefit

of this program and the incentive. So, we acknowledge

that on the starting point, it may be a disincentive

to allocate more than .6 percent of the cost of this

program to those customers that are getting the

benefit, but we don’t accept the logic of the company

that the NGT -- the natural gas vehicle incentive

program is akin to the EEC type programs.


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The EEC programs are generally available to

all customers and are wide scoping programs. To the

contrary, the natural gas vehicle incentives are to a

very limited and specific set of customers. So, we

would ask, in making your decision, that you leave a

regulatory alternative to look at this program and its

success and at a later point in time, assuming

significant take-up of the opportunity, and the

positive lens outlook, that the Commission retains an

opportunity to revisit during revenue requirement

proceedings a change in the allocation of the costs of

this program to those customers who are specifically

and significantly benefiting from it.

Those are my submissions, Mr. Chairman.

MR. FULTON: Ministry of Energy, Mines, and Natural Gas?

MS. IANNICIELLO: Yes, hi, can everyone here me?


SUBMISSIONS BY MS. IANNICIELLO:

MS. IANNICIELLO: Great, so our submission is just that the

Province’s current position with respect to the

Greenhouse Gas Reduction Regulation and utility

prescribed undertakings that are defined in that

Regulation are within the public realm through the Clean

Energy Act, the regulation itself, our press releases

and the province’s submission to the AES inquiry.

That being said, if the Commission requires


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further clarification on the Province’s position and

intent, and the Commission can provide specific

questions that require clarification, we will consult

with our counsel and the Province will provide a

response as quickly as possible following this oral

hearing.

That concludes our submissions.

MR. FULTON: Reply?

MR. GHIKAS: Nothing in reply, Mr. Chairman.

THE CHAIRPERSON: Okay, I think that then brings this

proceeding to a close, and I’d like to thank everybody

for their participation. It is 3:10, and we do have

another important item on the agenda. It would be

interesting to just get a quick sense of perhaps the

number of questions that people have in connection

with the phase 2, just so that we can do some planning

on time.

Let me start, though, with how long will

your presentation be?

MR. STOUT: Doug Stout. What we propose, and we’ve

handed out earlier, I think given what we’ve gone

through this morning, or this morning and this

afternoon, we can probably cut that down to about half

the presentation and just deal with specific facts

rather than any of the preamble. So probably 20

minutes I think we should be able to do.


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THE CHAIRPERSON: Twenty minutes? What sort of

questioning, in terms of volume, do people have? Let

me start just simply going around the table, starting

with commission staff. Do we have a lot of questions?

MR. NAKONESHNY: About a third at most.

THE CHAIRPERSON: Sorry?

MR. NAKONESHNY: About one third, compared to --

THE CHAIRPERSON: A third of the ones we had before?

MR. NAKONESHNY: Phase 1. Yes.

THE CHAIRPERSON: Carrying on down?

MR. ANDREWS: I don’t have much. If I did, it would be

clarification type questions.

THE CHAIRPERSON: Okay.

MR. WEAFER: Very few, Mr. Chairman, very few questions.

THE CHAIRPERSON: Okay.

MS. BRAITHEWAIT: I have very few as well.

THE CHAIRPERSON: Okay, well I think we can probably

dispose of the second matter. We will probably have

to work a little bit late, but I think it is probably

reasonable to continue on.

Do people want a short break at this stage?

Five minutes? Okay, well let's have a five minute

break. That would mean we’d resume about quarter

after, and we will get off right away with phase 2,

thank you.

(PROCEEDINGS ADJOURNED AT 3:11 P.M. )

volume 1...2012/10/24 · presentation, of phase 1 of the application. and that again is prescribed...

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