ONTARIO
ENERGY
BOARD
FILE NO.:
EB-2016-0152
Ontario Power Generation Inc.
VOLUME:
6
DATE:
March 7, 2017
BEFORE:
Christine Long
Presiding Member and Vice Chair
Ellen Fry
Member
Cathy Spoel
Member
EB-2016-0152
THE ONTARIO ENERGY BOARD
Ontario Power Generation Inc.
Application for payment amounts for the period from
January 1, 2017 to December 31, 2021
Hearing held at 2300 Yonge Street,
25th Floor, Toronto, Ontario,
on Tuesday, March 7, 2017,
commencing at 9:32 a.m.
---------------------------------------VOLUME 6
---------------------------------------BEFORE:
CHRISTINE LONG
Presiding Member and Vice Chair
ELLEN FRY
Member
CATHY SPOEL
Member
A P P E A R A N C E S
MICHAEL MILLAR
IAN RICHLER
Board Counsel
VIOLET BINETTE
LAWRIE GLUCK
JANE SCOTT
RUDRA MUKHERJI
Board Staff
CHARLES KEIZER
CRAWFORD SMITH
BARBARA REUBER
JOHN BEAUCHAMP
CHRIS FRALICK
Ontario Power Generation Inc.
(OPG)
IAN MONDROW
SHELLY GRICE
Association of Major Power
Consumers of Ontario (AMPCO)
MICHAEL BUONAGURO
JULIE GIRVAN
Consumers Council of Canada (CCC)
BRADY YAUCH
LARRY SCHWARTZ
Energy Probe Research Foundation
KENT ELSON
Environmental Defence (ED)
DAVID POCH
Green Energy Coalition (GEC)
SCOTT WALKER
Ontario Association of Physical
Plant Administrators (OAPPA)
RICHARD STEPHENSON
Power Workers' Union (PWU)
MIKE McLEOD
Quinte Manufacturers' Association
MARK RUBENSTEIN
JAY SHEPHERD
School Energy Coalition (SEC)
BOHDAN DUMKA
Society of Energy Professionals
(SEP)
MICHAEL JANIGAN
MARK GARNER
Vulnerable Energy Consumers
Coalition
I N D E X
O F
P R O C E E D I N G S
Description
Page No.
--- On commencing at 9:32 a.m.
1
Appearances
2
ONTARIO POWER GENERATION - PANEL 1C
P. Galloway, Previously Affirmed
2
Cross-Examination by Mr. Rubenstein
22
--- Recess taken at 10:48 a.m.
--- On resuming at 11:06 a.m.
45
45
Cross-Examination by Mr. Buonaguro
Cross-Examination by Mr. Poch
Cross-Examination by Mr. Yauch
45
62
70
--- Luncheon recess taken at 11:59 p.m.
--- On resuming at 1:11 p.m.
77
77
Preliminary Matters
78
Cross-Examination by Mr. Yauch
Cross-Examination by Mr. Tolmie
Cross-Examination by Mr. Richler
Questions by the Board
Re-Examination by Mr. Keizer
78
82
88
95
101
--- Recess taken at 1:54 p.m.
--- On resuming at 2:00 p.m.
103
103
ONTARIO POWER GENERATION - PANEL 2A(I)
J. Mauti, C. Fralick, R. Puch, Affirmed
103
Examination-In-Chief by Mr. Smith
Cross-Examination by Mr. Stephenson
Cross-Examination by Mr. Millar
103
105
116
--- Recess taken at 3:02 p.m.
--- On resuming at 3:20 p.m.
143
143
Cross-Examination by Mr. Tolmie
Cross-Examination by Mr. Rubenstein
165
170
--- Whereupon the hearing adjourned at 4:33 p.m.
189
E X H I B I T S
Description
EXHIBIT NO. K6.1:
Page No.
VECC COMPENDIUM.
EXHIBIT NO. K6.2: CROSS-EXAMINATION COMPENDIUM
OF MR. TOLMIE FOR OPG PANEL 1C.
3
82
EXHIBIT NO. K6.3: BOARD STAFF CROSS-EXAMINATION
COMPENDIUM FOR OPG PANEL 2A(I)
116
EXHIBIT NO. K6.4: CROSS-EXAMINATION COMPENDIUM
OF SEC FOR OPG PANEL 2A(I)
170
U N D E R T A K I N G S
Description
UNDERTAKING NO. J6.1: TO PROVIDE THE LOCATION
IN THE EVIDENCE OF THE RISK REGISTER DR.
GALLOWAY REVIEWED.
Page No.
62
1
1
Tuesday, March 7, 2017
2
--- On commencing at 9:32 a.m.
3
MS. LONG:
4
Good morning, everyone.
5
6
Please be seated.
Good morning, Dr. Galloway.
The panel continues to sit today in EB-2016-0152.
Mr. Keizer, are there any preliminary matters we need
7
to deal with this morning?
8
Preliminary Matters:
9
MR. KEIZER:
Yes, there are two.
The first is a
10
routine matter that we have filed Undertaking J2.8 and
11
Undertaking J3.4.
12
The second matter relates -- and I've advised my
13
friend from VECC with respect to this -- relates to some
14
items that are in VECC's compendium, and this isn't really
15
-- what I put my friend on notice is that after Dr.
16
Galloway looked at the compendium she identified that there
17
were pieces in the compendium that related to Kemper and
18
she alerted me, the fact that she currently is involved in
19
testimony and evidence with respect to the Kemper facility,
20
I believe, as well Vogtle.
21
that there may be issues with respect to confidentiality
22
that Dr. Galloway may encounter, and obviously this isn't
23
intended to curtail my friend's cross, but we will
24
obviously have to deal with it as the question arises.
25
as I've said, I've alerted my friend to that fact.
26
MS. LONG:
Okay.
And so I've alerted my friend
And
Ms. Khoo, what I intend to do, I
27
mean, we'll let Ms. Khoo go ahead with her cross-
28
examination.
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MR. KEIZER:
2
MS. LONG:
Yes.
And if Dr. Galloway has an issue with the
3
questions that are being asked we'll deal with them at that
4
time, and I will ask Dr. Galloway put on the record why
5
she's not able to answer the questions, and then, Mr.
6
Keizer, you can raise any concerns that you have and we'll
7
deal with each issue as it comes up in the cross.
8
9
MR. KEIZER:
No, that's fine.
intend.
10
MS. LONG:
11
MR. KEIZER:
12
MS. LONG:
13
MR. RICHLER:
14
APPEARANCES:
15
MS. LONG:
16
17
That's as we would
Okay.
Thank you very much.
Good.
Any other issues?
None from us, Madam Chair.
Okay.
Then, Ms. Khoo, can you begin your
cross-examination, please.
MS. KHOO:
Sure.
So first I wanted to apologize to
18
the panel for not introducing myself yesterday.
19
been quite a sudden transition, and so I thank everyone in
20
the room for bearing with me.
Oh, no problem.
This has
21
MS. LONG:
I should have asked you.
22
I wasn't sure.
23
in for Ms. Khoo representing the Vulnerable Energy
24
Coalition?
That's my fault.
So we have an appearance
25
MS. KHOO:
Yes, that's right.
26
MS. LONG:
Thank you.
27
ONTARIO POWER GENERATION - PANEL 1C
28
Patricia Galloway, Previously Affirmed.
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3
1
2
Cross-Examination by Ms. Khoo:
MS. KHOO:
Good morning, Dr. Galloway.
And thank you
3
for appearing today to answer our questions again.
4
established yesterday, I'm not going to challenge your
5
qualifications, and there are just a few things I wanted to
6
clarify.
7
what -- the confidential aspects of Kemper, but again, you
8
can mention if that happens to be the case.
9
As we
I don't think, hopefully, it will be cross on
So first you testified yesterday, and in your report
10
as well, that you found that OPG has reasonably and
11
prudently prepared for its execution of DRP; is that
12
correct?
13
DR. GALLOWAY:
14
MS. KHOO:
Okay.
15
MS. LONG:
Can I just stop you for one minute.
16
That's correct.
And throughout your report -We're
just checking that we have your compendium.
17
MS. KHOO:
Oh.
18
MS. LONG:
I do.
Do you have a copy?
19
need some extra copies.
20
Richler, if we can just mark it, please.
We might just
That's on our end here.
21
MR. RICHLER:
22
EXHIBIT NO. K6.1:
23
MS. LONG:
Okay.
24
MS. KHOO:
Thank you.
And Mr.
Yes, VECC's compendium will be K6.1.
VECC COMPENDIUM.
Thank you.
Please continue.
And throughout your report,
25
Exhibit D2, tab 2, schedule 11, attachment 3 you frequently
26
refer to industry standards and best practices.
27
be correct to say that you rely on such standards and best
28
practices as a basis for determining what is reasonable or
Would it
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1
prudent in managing projects?
2
DR. GALLOWAY:
3
MS. KHOO:
It would be one of the bases, yes.
Thank you.
Now, I would like to turn to
4
the table you provided in response to Undertaking JT1.24.
5
This is on page 10 of the compendium.
6
a number of projects in response to the request to identify
7
those within the last ten years of comparable scope to your
8
work for OPG; is that correct?
9
10
11
DR. GALLOWAY:
question, please?
MS. KHOO:
This table provides
I'm sorry, could you repeat the
I'm sorry.
This table, it's a response to the request
12
to identify the projects that you've worked on with work of
13
comparable scope to your work for OPG?
14
15
16
DR. GALLOWAY:
Yes, it is a response to the last ten
years that are comparable to scope.
MS. KHOO:
Okay.
That's correct, yes.
So I would like to go over some of
17
these, and again, as mentioned, if they run into the
18
limitations you have with respect to your other testimony
19
you can just raise that at the time.
20
So on page 12 of the compendium -- this one is about
21
Kemper County power plant -- you stated in the testimony
22
that MPC's management decisions and actions as to the
23
Kemper IGCC project fell within a zone of reasonableness
24
and were prudent.
25
26
27
28
Was this assessment based on industry standards and
best practices?
DR. GALLOWAY:
It was based on a number of things.
was based on industry best practices.
It
It was based on
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1
utility practice.
2
reasonably known by Mississippi Power Company as of March
3
31st, 2013, and it was also based on what was provided to
4
the commission in its CPCN and based on what the level of
5
effort at the time the utility undertook based on the
6
progress of Kemper up to its CPCN.
7
things that were based on that conclusion.
8
9
10
MS. KHOO:
It was based on what was known and
Those were all the
And these are all typical factors that go
into drawing a conclusion like that on these sorts of
projects?
11
DR. GALLOWAY:
12
MS. KHOO:
Yes.
Okay.
Thank you.
On page 17 of the
13
compendium, a New York Times article from July 2016 stated
14
that the Kemper County plant at that time was over two
15
years behind schedule, over 4 billion dollars above budget,
16
and still not operational.
17
article from Mississippi Today states that as of October
18
2016 the plant cost over double the original estimate and
19
was still not operational.
20
On page 32 of the compendium an
In light of that, do you stand by your original
21
assessment that management decisions for Kemper County were
22
within a zone of reasonableness and were prudent?
23
DR. GALLOWAY:
I would like to qualify the response.
24
As I'd indicated, the first response was the conclusions
25
were effective as of March 31st, 2013.
26
are in the two articles put forth are beyond March 31st,
27
2013 and are part of an ongoing review and will be part of
28
a prudence hearing that will be held later this year, and
The matters that
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1
therefore my analysis and conclusions relative to the
2
aspects so stated in these two articles is still under
3
review, and therefore I do not believe that I can comment.
4
MS. KHOO:
That's fair.
Thank you for that.
5
I will now turn to page 36 of the compendium, which
6
references your work for Duke Energy on the Edwardsport
7
plant.
8
states that your firm concluded that Duke acted prudently
9
in managing the project, and this assessment was based on
In the third paragraph from the bottom the article
10
the similar factors to those that you mentioned above with
11
respect to Kemper?
12
DR. GALLOWAY:
Yes, but again I think that the
13
conclusions must be put into perspective.
14
for Duke Energy on reasonableness and prudence was on
15
various aspects.
16
entire amount.
17
imprudence and disallowance on one aspect of Duke Energy's
18
management itself.
19
Duke Energy's EPC contractor.
20
found that Duke Energy was reasonable and prudent in its
21
management of the EPC contractor, we found that the EPC
22
contractor had taken actions that were deemed by us to be
23
unreasonable and imprudent to the tune of a range, I
24
believe it was 500 to 800 million dollars.
25
The conclusions
It wasn't on the entire project or the
Qualifying that, we did find some
We also found disallowance relative to
Those amounts, while we
We -- under testimony I so indicated to the commission
26
at that time.
It would be obviously up to the commission
27
as how to handle that under the statute, and there was also
28
allegations, I believe, that so cited in your compendium of
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1
2
fraud concealment and gross mismanagement.
So the commission found that there was no fraud
3
concealment or gross mismanagement and, relative to the
4
other matters, there was a settlement between the
5
commission and Duke, and relative to the 500 to 800 million
6
dollars the commission deemed that that was not a
7
responsibility of the ratepayers but that Duke could go
8
ahead and attempt to recover those in a separate action
9
against the EPC contractors.
10
11
12
So that is the basis of the reasonableness and
prudency.
It was within those bounds.
MS. KHOO:
Thank you.
So to clarify, reasonableness
13
and prudency was found on Duke's part, and then it was
14
because of the contractor that the project ended up going
15
the way it did in terms of the adverse consequences?
16
MS. GALLOWAY:
Except for I indicated there was one
17
other aspect.
I can't remember exactly the dollars.
It
18
was in the millions relative to a specific area on how they
19
handled grey water, and that particular aspect was deemed
20
by us to be imprudent on the actions of Duke Energy.
21
MS. KHOO:
Thank you.
22
MS. LONG:
Dr. Galloway, can you clarify for me the
23
distinction you're drawing between what your mandate was on
24
the Duke Energy project and Kemper project?
25
they were different scopes of work, one was more defined
26
than the other?
27
28
MS. GALLOWAY:
No.
Are you saying
So Kemper and Duke were both full
prudence audits for the entire aspect of the plant.
Duke
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Energy was ahead of Kemper in its building.
Kemper is
2
going through its final start-up and commissioning.
3
Energy's Edwardsport IGCC's plant was in its start-up and
4
commissioning aspects when the prudence hearing was held.
5
And so the review for both plants was looking at the
Duke
6
decision to build, the preplanning and execution, the
7
entire execution of the project, and also that involved the
8
actions of the EPC contractor as well.
9
The Kemper project was somewhat different, not in our
10
scope, but somewhat different in the fact that they did not
11
have an EPC contractor.
12
and they themselves took on the role of EPC contractor
13
through their parent company.
14
They had multi-prime contracting
They are one of the few utilities that actually have
15
their own construction management arm, and so they did
16
their own EPC contracting.
17
at their role in that EPC contracting management.
18
But yes, we would have looked
So their roles were very similar.
It's just that the
19
Duke proceeding is over and was finished, and the Kemper
20
proceeding is not over and has not yet had a prudence
21
hearing.
22
been prefiled testimony.
23
not been held yet at all, and that is going to be done
24
later this year.
The testimony that I have filed in Kemper has
25
MS. LONG:
26
MS. FRY:
The prudence hearing has actually
Thank you.
Just to be clear, for both of those
27
projects, the construction was essentially finished at the
28
point at which you did your prudence review, is that
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2
correct?
MS. GALLOWAY:
Correct.
The Kemper project was due to
3
the mandate from the commission is that when they pre-
4
approved the estimate, Mississippi Power Company had to
5
make annual filings of prudence.
6
an interim filing of testimony from everyone relative to
7
prudence.
8
was still ongoing because it was annual prudence reviews.
9
Before the hearings was held on that, the commission
So that is why there was
Up to the point of March 31, 2013, the project
10
changed its decision and made the decision, revised its
11
order that they would not hear prudence on an annual basis,
12
that they would wait until the completion of the project to
13
hold one hearing instead of annual hearings.
14
why no further testimony has been filed, an while the
15
prudence evaluation we are doing is still underway.
16
MS. LONG:
Continue, Ms. Khoo.
17
MS. KHOO:
Thank you.
18
19
And that's
I realize it's getting
repetitive, so this is the last one on the table.
On page 44 of the compendium, you testified before the
20
Florida Public Service Commission that the company behind
21
Levy County Nuclear Power Plant reasonably and prudently
22
implemented its management decisions.
23
On the page before that, similarly you testified that
24
PF's management decision was reasonable and prudent based
25
on information known, and that reasonably should have been
26
known by management at the time the decision was made.
27
28
Was that finding that PF's management decisions were
reasonable and prudent also in accordance with industry
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1
standards, best practices, and the standard factors that
2
you mentioned earlier in making this sort of assessment?
3
MS. GALLOWAY:
As I think I testified yesterday, Levy
4
was very, very different in the mandate from that of Kemper
5
and Duke.
6
that was the decision to continue with the Levy project on
7
a limited basis, with work only proceeding for its combined
8
operating license and the amendments to the contract that
9
were made in light of that decision.
10
It was an evaluation of only one decision, and
So the prudence review was only for that decision to
11
continue, defer work, and whether the amendments within the
12
contract were reasonable and prudent.
13
yesterday, that was the testimony that all of the parties
14
had stipulated to and agreed to, and the commission
15
adopted.
16
procedures and processes and the things you compare against
17
best practices.
18
was known or reasonably should have been known at the time
19
that the utility made its decision to undertake that, which
20
was more in light of the Nuclear Regulatory Commission and
21
what the Nuclear Regulatory Commission was doing relative
22
to review of the combined operating licenses in the United
23
States, the timing of those combined operating licences,
24
and other factors such as the demand for power, the need
25
for power, why Levy was still a good option based on the
26
economic circumstances at the time, and those would have
27
been the factors surrounding that particular decision.
28
And as I indicated
It was -- it wasn't a review of policies and
MS. KHOO:
It was the decision-making process on what
Thank you.
However, after that, so on page
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1
45 of the compendium, the Tampa Bay Times from August 2013
2
reported that Levy was shut down, and customers were on the
3
hook for $1.5 billion.
4
In light of that, I suppose, would you stand by your
5
original decision because it was limited in the scope as
6
you described?
7
MS. GALLOWAY:
Yes.
Plus it was, as I indicated,
8
based on the circumstances known at the time to the
9
utility.
Circumstances changed in many ways from the
10
nuclear industry all the way through economic conditions
11
and the price of fuel, with natural gas prices especially
12
plummeting, and all of those things resulted in different
13
circumstances that resulted in this decision that Duke
14
Energy made at that time.
15
MS. KHOO:
In relation to that project, is it true
16
that Jeffrey Lyash was the CEO of Progress Energy or Duke
17
at that time?
18
MS. GALLOWAY:
19
MS. KHOO:
20
current CEO of OPG?
That's correct.
This is the same Jeffrey Lyash who is the
21
MS. GALLOWAY:
22
MS. KHOO:
That is correct.
To confirm, of the projects we just
23
discussed, which seem to involve significant cost overruns
24
and were considerably delayed or shut down, in all those
25
cases at the time of the assessment, the assessment was
26
their management was reasonable and prudent?
27
28
MS. GALLOWAY:
No.
I think I've testified on Duke
that there was a significant disallowance that we found,
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one on both the utility and one on the EPC contractor of
2
the utility to -- I think our total disallowance was in the
3
range of 500 to 900 million dollars.
4
On Kemper, the testimony, yes, is still true up
5
through March 31st of 2013.
The conditions or any actions
6
taken by Mississippi Power after that time are still under
7
review, and no testimony has yet been filed.
8
And relative to the Levy project, again that was just
9
a contract basic decision that was accepted by all parties
10
11
12
13
14
15
16
to be reasonable and prudent.
MS. KHOO:
Thank you.
So the Duke finding was after
the fact of the actual project?
MS. GALLOWAY:
The project was still in start-up and
commissioning at the time of the prudence hearing.
MS. KHOO:
And the Kemper County assessment is still
under review?
17
MS. GALLOWAY:
18
MS. KHOO:
That is correct.
So would you agree that based on these
19
projects, that there seems to be a certain disparity
20
between the initial assessment at the time of
21
reasonableness and prudence and how these projects actually
22
turned out in practice?
23
MS. GALLOWAY:
24
MS. KHOO:
25
MS. GALLOWAY:
No, I do not.
Would you like to elaborate?
Well, prudence is -- in the U.S.
26
jurisdictional aspect is based on what was known, or
27
reasonably should have been known at the time a decision is
28
made.
That is how the commissions view all of the
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2
decisions.
The Mississippi commission has not obviously met or
3
heard any of the evidence yet.
4
Mississippi commission as to whether they deem the costs
5
reasonable and prudent.
6
It will be up to the
There is a distinction on the Kemper plant, of course.
7
The Kemper plant, which was a first of a kind in every
8
single aspect, the technology had never been built anywhere
9
before.
The plant had never been built anywhere before,
10
and there had never been a plant that agreed to do 65
11
percent carbon capture.
12
evaluated currently are against a lot of those knowns that
13
were known to everybody at the time the commission approved
14
the CPCN.
15
So the cost that are being
Also, there is a cap on the Kemper plant that both
16
parties agreed to because of the fact that the plant had
17
never actually been built before, so the ratepayers, the
18
customers, are protected.
19
costs of those costs over that, and the ratepayers that --
20
the proceeding that is about ready to go forward will be on
21
the exclusions, because there are exclusions to that cap
22
for which the utility and the commission have agreed will
23
be reviewed for prudence.
24
Kemper.
25
Southern Company has assumed the
So that is a difference on
On Duke there were provisions in the CPCN again, new
26
technology that had never been used, first-of-a-kind
27
elements of which both the commission and the utility
28
recognized.
There were some -- there were cost estimates
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that came in based on that that both parties knew would
2
probably occur due to those first-of-a-kind risks.
3
costs were approved by the commission.
Those
4
And so the prudence element that was being reviewed
5
was the cost over the second approved cost estimate, not
6
the first approved cost estimate, and it's those costs that
7
there was the issue of the EPC contractor's costs.
8
So those were two very distinct differences, and
9
again, on Levy everyone agreed that the first decision was
10
a reasonable and prudent decision at the time it was made.
11
MS. KHOO:
The fact of the matter is, however, that
12
even if the outcomes had valid reasons or valid change of
13
circumstances, even if a decision seems prudent and
14
reasonable before implementation, that won't necessarily
15
stop the project itself from running over budget and over
16
schedule in its actual implementation?
17
DR. GALLOWAY:
It all depends on the circumstances and
18
what was known or reasonably should have been known and
19
what was known at the parties at the time that a plant is
20
being built.
21
difference between both Kemper and Darlington and Duke and
22
Darlington is that in the Darlington refurbishment program
23
that there was an extensive pre-planning period and that
24
the design was complete, that they were able to have
25
lessons learned.
26
learned from other refurbishment projects and nuclear
27
projects and other megaprograms.
28
And as I had indicated yesterday, a very huge
They were actually able to take lessons
The difference in the jurisdictional aspect in the
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United States, as I was explaining yesterday, is that when
2
a utility applies for its certificate of public necessity
3
and need, the CPCN, it does not have the same luxury of
4
going through that.
5
percent design had actually been completed at the time.
6
They did not have fully established organizations.
7
did not run any type of probabilistic modelling.
8
not have their organizational structure in place, and there
9
was no lessons learned to be gained because the Kemper
For instance, on Kemper less than 10
They
They did
10
project had never been built before and the technology had
11
never been used before, so there was no way to gain any
12
prior knowledge.
13
original estimate was made.
14
And so that was the basis upon which that
The same is true for Duke Energy.
There also was no
15
probabilistic modelling done.
16
planning done.
17
lessons learned because again even though a different
18
gasification technology, the technology had only been done
19
on a very small scale, and not an expanded scale, and so
20
those were very different factors than what Darlington has
21
upon which that original estimate was made.
22
There was no extensive pre-
There was not the opportunity to again take
And everyone was quite aware at the time that this was
23
put up for the CPCN that you also had economic conditions.
24
The Department of Energy was encouraging utilities to take
25
advantage of the abundance of coal, which was a natural
26
resource in the United States.
27
energy, which was deemed to be viable with IGCC -- sorry,
28
integrated gasification combined cycle.
There was a push for clean
There was also
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1
investment tax credits that were being offered by the
2
government, and there was at that time, if everyone
3
remembers, natural gas prices were not low.
4
extremely high, and there was a desire for fuel diversity.
5
All of the parties, including the customers, the
They were
6
intervenors, and the utilities all at the time of the CPCNs
7
recognized that those types of risks were quite heavy,
8
could not be modelled, because there was no way to model
9
those risks because there was no subject-matter experts out
10
there that would be able to identify the types of risks
11
that might arise, and therefore everyone recognized that
12
there would be cost increases that potentially would occur
13
that could not be incorporated into that original cost
14
estimate.
15
So I think it's very important to judge what was known
16
and the pre-planning execution at the time of those two
17
plants to put in context what the final cost is today.
18
19
20
21
MS. KHOO:
Thank you.
I'm just going to see if my
colleague Mr. Garner has anything to add.
I believe that's everything for VECC.
Thank you very
much.
22
DR. GALLOWAY:
Thank you.
23
MS. LONG:
24
follow-on to that.
25
guess, on Kemper, for example, that there is not the same
26
pre-planning as has gone on for the DRP and other things
27
that were not done, and yet your opinion was that at the
28
time when your review -- it was reasonable.
Thank you.
Can I just ask a question, a
You've talked about the limitations, I
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Are you saying that it was reasonable based on -- that
2
it's situational based on what the current standard is that
3
such pre-planning -- there were no lessons to be learned,
4
that's just typical common practice that they wouldn't have
5
designed?
6
opinion?
7
Is that the context in which you came to your
I'm just trying to understand that.
DR. GALLOWAY:
Yes, the U.S. is much different in its
8
regulatory regime of what a utility does and does not do
9
before it makes its application to actually build a
10
project.
11
that utilities do not take under a lot of what I would call
12
planning per se before they apply for their CPCN, because
13
of the -- all the costs are at risk.
14
And the regulatory regime in the United States is
And so they do sufficient planning in order to come up
15
with a reasonable estimate with what I would call
16
qualifiers on -- based on the circumstances and what was
17
known at the time.
18
So when the commissions review those applications for
19
CPCN they also review those qualifications of what is known
20
at the time.
21
through what I would call the reasonable and prudence
22
review.
23
the commission hearing, the prudence hearing, and they talk
24
about whether that's a reasonable assumption or not a
25
reasonable assumption.
26
And so it's those qualifications that also go
Each of those qualifiers is actually discussed in
Just as an example on the Kemper project itself,
27
because it had never been done before, ever, one of the
28
issues that was raised in the CPCN hearing on Kemper was,
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was, for instance, the decision to go with the Department
2
of Energy's desire to put into place IGCC a good thing for
3
Mississippi and the state of Mississippi.
4
Part of what went into that look of whether that was a
5
reasonable assumption underlying the need to go forward
6
with the project included that Mississippi, for instance,
7
has a huge amount of coal.
8
was looking relative to the number of jobs that the project
9
would create.
10
It is a very poor state, and it
And so there were economic -- there were other factors
11
that the commission considered in that decision that did
12
not actually go to cost that the commission in its order --
13
and if you read the order you will see this -- that those
14
opportunities for the state of Mississippi and the fact
15
that the utility would pay -- be making big tax payments,
16
all of those were considered to be reasons that the project
17
should go forward.
18
And then there was also a recognition that, being a
19
complete first of a kind, that there may be increases that
20
would come forward and that, you know, there was a
21
discussion and actually an agreement between the commission
22
and a settlement and the utility of how those first-of-a-
23
kind types of risks would be handled.
24
And so the commission in the States for each of these
25
jurisdictions on a CPCN looks at -- they recognize that the
26
extent of pre-planning is not there.
27
those estimates will probably come back for a cost
28
increase, and if they do, it is those new conditions and
They recognize that
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circumstances that then will be reviewed, and whether the
2
utility took actions that were reasonable and prudent based
3
on the new circumstances that go beyond the original cost
4
estimate.
5
MS. FRY:
Let me turn it around a bit.
Obviously,
6
every project is individual, and you look at each project
7
at the particular stage when you are asked to come in and
8
opine.
9
So let me turn it around.
Of the projects that you're
10
referring to that you've dealt with in the past, which is
11
the one you would say is most similar to Darlington, in
12
terms of the circumstances of the project and the point at
13
which you were brought in?
14
MS. GALLOWAY:
As I indicated, most of the projects in
15
the States do not have this extensive preplanning.
16
fact, none of them have the extensive replanning and in
17
fact, probabilistic modelling comes in typically after the
18
project has been approved, when they go forth to look at
19
their cost estimate when they refine that cost estimate and
20
at that time, they will decide whether or not they need to
21
come forth to the commission for any types of increase.
22
In
But I will say that the Vogtle project probably has
23
some similarities in the fact that because the nuclear
24
regulatory commission in the United States was reviewing
25
these new designs that were going to be standardized
26
designs that presumably would make the cost of nuclear more
27
efficient and effective going forward instead of being one-
28
off designs, which is what was going on in the '70s and
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'80s.
2
different.
3
for these different types of reactor designs.
4
Each nuclear power plant was built completely
And so the NRC was looking at these licenses
So the AP 1000, for instance, is a particular design
5
that had to have NRC approval first before they could
6
actually build that.
7
Vogtle case, everything depended on the EPC contractor in
8
that case because, it's the EPC contractor that brings
9
forth that AP 1000 design, it is going to be managing it,
The EPC contractor -- and in the
10
it has to come up with the policies and procedures, and so
11
the risk profiling and the risk review was somewhat
12
different than here, but similar in some respects.
13
So the risks were modeled within the contract, because
14
the contractor held everything that was going to be done
15
versus the utility putting in the policies and procedures
16
and looking at the -- and having done the design first and
17
having the contractor basically come in and execute that
18
work.
19
In Vogtle, the EPC contractor was doing everything.
20
So the risk review looked at the risks within the contract,
21
and the contractor was responsible for looking at how those
22
risks were going to be modeled, or how the risk would be
23
assumed by them versus the utility.
24
went through the actual risk profiling that was done on the
25
contract and that is -- for instance, in our scope of work,
26
we looked at the risk on how the risk was modeled and how
27
it was included within the EPC contract, and that is what
28
the commission actually took on was they have their own --
So the prudence review
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it's called an independent monitor, but they had their
2
staff -- their consultant review the risks that were
3
incorporated within the contract.
4
We reviewed the risk as they were incorporated within
5
the contract.
6
indicate is that the contract was reasonable and prudent,
7
and that the risks within that contract were understood by
8
both parties including risks that might arise that would
9
result in a change order.
10
And then the -- what the order came out to
What the commission had to approve and did was that
11
should the risks that were unknown but covered within the
12
contractual provisions of the contract arise, then if those
13
conditions did arise, those conditions would come back to
14
the commission for review for those change order amounts.
15
And if they fell within the approved commission agreement
16
for those risks, those costs
17
and prudent.
18
would be deemed reasonable
So that is what has happened, is certain risks arose
19
under that contract.
20
contract.
21
settlement.
That settlement was put forth to the
22
commission.
They held a hearing on that, and the
23
commission so determined in its order that those costs were
24
part of the costs that would be applicable under the
25
contract in the change order provision, and approved those
26
cost increases.
27
28
They were provided for in the
The contractor and the utility came into a
MS. FRY:
Okay.
So if you were to summarize the key
similarities between the Vogtle project and how you came
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in, the point you came in, and the Darlington project, can
2
you just sort of name the key similarities you would see?
3
MS. GALLOWAY:
The risk review, but being different in
4
the way I just described it.
The planning organization
5
relative to the structure and the organizational structure
6
that was going to be set up on both sides to execute the
7
program.
8
manage the project, including the various metrics and the
9
reporting.
The policies and procedures that were in place to
The project control tools and who would be
10
responsible for undertaking those project control tools,
11
but whether the project control tools met best practices
12
and would allow for a successful execution of the Vogtle
13
project.
14
So I believe that even though the CPCN was limited and
15
they didn't do as extensive a planning here, the same
16
elements that we reviewed here we, reviewed there for that
17
for their CPCN filing.
18
in that respect.
So they would be very, very similar
19
MS. FRY:
Thank you very much.
20
MS. LONG:
21
CROSS-EXAMINATION BY MR. RUBENSTEIN:
22
MR. RUBENSTEIN:
Mr. Rubenstein, are you next?
Yes, I am, thank you very much.
I
23
would like to follow-up on your discussion at the end about
24
the Vogtle.
25
Just to clarify, if I'm looking at JT 1.24 -- and this
26
is page 10 of the VECC compendium -- it says that you
27
participated in the engagement, but did not file testimony.
28
What exactly was your role?
Who were you representing
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2
and what was the engagement that you had?
MS. GALLOWAY:
So Pegasus Global did file testimony.
3
The late Dr. Kris Nielsen actually filed the testimony in
4
the CPCN hearing that was the risk evaluation of the
5
contract, the history of the nuclear industry -- because I
6
think as I mentioned yesterday, Vogtle was the first
7
nuclear plant in twenty years to be built in the United
8
States, and served as the AP 1000 reference plant -- and
9
also to opine on the organization structure, the policies
10
and procedures, and project controls that were set in
11
place.
12
So Dr. Nielsen filed that testimony and testified in
13
front of the PUC hearing, and then the CPCN order was
14
developed.
15
did that evaluation.
16
that reviewed all of those aspects.
17
personally did not file and give testimony.
18
by Dr. Nielsen of the Pegasus Global Group.
I was part of the team, the Pegasus team that
19
MR. RUBENSTEIN:
20
MS. GALLOWAY:
21
22
There was a team of about five of us
It's just that I
That was done
What year would that have been?
Two thousand and -- I want to say 2008,
I believe.
MR. RUBENSTEIN:
My understanding, from documents and
23
testimony we've heard about Vogtle in this proceeding, is
24
that the project has gone significantly behind schedule.
25
believe OPG, in one of their documents, has stated it's at
26
least 39 months behind schedule.
27
understanding?
28
MS. GALLOWAY:
I
Is that your
Well, I believe again it goes to the
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1
points that I was just raising with the Board.
2
contract that was approved at the CPCN, it was recognized
3
that there may be certain risks that would arise that would
4
result in change orders.
5
of the contract.
6
Within the
Those risks did arise, were part
Those change orders included both the time extension
7
and the costs under the clauses.
That went through a
8
hearing last year and those additional costs, through the
9
settlement and additional extensions to the plant, were
10
deemed reasonable and prudent and approved by the
11
commission.
12
And relative to the cost, I think it's important to
13
understand from a transparency standpoint -- and I believe
14
that this information is very public; it's probably on the
15
Georgia Power website.
16
transparent in what they show.
17
there was an anticipation that there would be at the
18
completion of this -- they do have CWIP, as we talked about
19
yesterday, but there would be an anticipation that there
20
would be about a 12 percent increase in rates for the
21
Vogtle project.
22
number of -- from financing costs to looking at fuel prices
23
that that is now looked at to be -- going to be much lower
24
impact to the ratepayers, and so actually, even though the
25
costs are higher, the actual costs that will be borne by
26
the ratepayers will be much less than anticipated at the
27
CPCN.
28
Not for sure, but they're pretty
At the time of the CPCN
That now has been re-evaluated through a
MR. RUBENSTEIN:
So as I understand what you're saying
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is there was an expectation that there were going to be
2
scope changes in that project and Vogtle -- the sponsor of
3
Vogtle would have to return to the commission.
4
there was an expectation from the beginning.
5
DR. GALLOWAY:
That was --
Yes, because at the time of the CPCN in
6
2008 they didn't even have a combined operating licence
7
approved by the NRC yet, which everyone was fully aware of,
8
and no one can anticipate what the NRC may or may not do.
9
It's a completely unknown risk in the United States, and I
10
don't believe the combined operating licence was actually
11
given to Vogtle until 2012, so some four years later.
12
13
14
So those are the types of things that were built into
the contract and some of the risks that might arise.
MR. RUBENSTEIN:
When you say NRC you mean the Nuclear
15
Regulatory Commission?
16
DR. GALLOWAY:
17
MR. RUBENSTEIN:
Yes, I'm sorry.
So from your discussion with Vogtle
18
and the comments you were making with respect to the
19
comparisons that VECC took you to, am I to -- I want to
20
understand this.
21
legislative systems in each of the -- in the States, and
22
they each have their own unique circumstances.
23
I recognize in the U.S. different
Have you then ever done an engagement that is very
24
similar to this that is a -- you're asked to provide on a
25
forecast basis, essentially, that the budgeting, the
26
management control, the contingencies are all reasonable,
27
with the expectation that there will be no change orders,
28
that they shouldn't be -- the utility shouldn't come back
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to the regulator?
2
specifically?
3
Have you ever done anything like that
DR. GALLOWAY:
I'm a little bit confused by your
4
question.
5
clarification of exactly what you're asking me whether I've
6
done or not done?
7
Can you just give a little bit more
MR. RUBENSTEIN:
Sure.
I'll try to, at least.
I want
8
to understand if you've done something that is, at least in
9
my view, a little bit more precisely exactly what you're
10
asked to do in this proceeding.
11
mandate in this proceeding is you're being asked for this
12
project to comment on the reasonableness of the process to
13
develop the budget, the schedule, the contingency, the
14
program controls.
15
As I understand your
Have you ever done that for a project that has not
16
gone in -- is not planned to go in-service for a number of
17
years and there is an expectation from, I would believe,
18
the utility itself that it should not need to go back to
19
the commission, that there will -- it should not need to
20
make scope changes or material scope changes?
21
DR. GALLOWAY:
Well, yes.
I mean, again, there are
22
instances that are, I will say non-nuclear, because there
23
are not a lot of nuclear examples, okay?
24
the -- and so Bellefonte was a different situation.
25
government-run utility, and so it goes through completely
26
different proceedings.
27
28
I mean, Vogtle is
It's a
We did look at that decision-making, whether or not
they had the pre-planning and the policies and procedures
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set up to make that decision to go with 1 and 2 versus 3
2
and 4 at the time.
3
If I go to non-nuclear, though, there are several
4
examples.
5
transmission and distribution project for ATC company,
6
looking at the same thing of whether their initial policies
7
and procedures and government -- I mean, their structure
8
and governance was all according to plan.
9
executed and came in, I think, pretty much on time and on
10
11
For instance, we did a prudence evaluation on a
That project was
budget.
The Energy Strong program that we are an independent
12
monitor on, which is public-service gas and electric in New
13
Jersey, again, we were brought in at the very beginning of
14
the project, a joint mandate by both the commission and the
15
utility and rate council.
16
mandate was to precisely look at the structure, the
17
policies, the -- it's a megaprogram, by the way, as well.
18
It's about 1.2, 1.3 billion dollars, and it's made up of
19
four major different projects underneath.
20
look at the management structure, we were asked to look at
21
the organization, the qualifications of the personnel, the
22
planning, the schedule, the cost estimate, look at the
23
project control systems, the reporting.
24
we're being asked to look at here, we were asked, and we
25
were asked to report out on that, and we do report out on
26
that to both the commission and the utility and rate
27
council on a quarterly basis with an annual report as well.
28
And in fact, the next annual report review is tomorrow for
It's a three-party group.
Our
We were asked to
Everything that
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2
last year's review.
And to date, we have been monitoring that project for
3
three years now.
4
forecasted to come in ahead of schedule by as much as maybe
5
even a year, and it is forecasted to come in under budget.
6
The project is going to -- it's
And so we were asked to do the exact same thing that
7
we were asked to do here, except we were retained by all
8
three parties, and we are reporting out on that
9
continuously over the time.
10
And there will be a prudence hearing that will be done
11
at the conclusion of the project, which presumably we will
12
also be asked to testify.
13
So that was -- it's very similar to here, it's just
14
not a nuclear program.
15
a hardening of the system in order to protect it against
16
hurricanes and floods and those types of events that have
17
caused major outages in the state of New Jersey, because of
18
the types of storms that they have had over the years.
19
It's a -- it's -- Energy Strong is
The other example, of course, would be Crossrail that
20
I talked about yesterday, where Her Majesty's Treasury
21
asked us to come in and do a complete review of the risks,
22
and again the structure, the policies and procedures, the
23
project controls, and the whole setup for the Crossrail
24
system that was then prepared in a report that was given to
25
the treasury and then submitted to parliament.
26
MR. RUBENSTEIN:
27
DR. GALLOWAY:
28
MR. RUBENSTEIN:
But none for nuclear.
Excuse me?
But none for nuclear.
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DR. GALLOWAY:
Well, as I've indicated, the only
2
nuclear project in 20 years is the Vogtle nuclear project,
3
other than -- we're not working on SCANA, so I can't
4
comment on SCANA.
5
MR. RUBENSTEIN:
I want to ask you about -- if we can
6
turn to your report.
And I'm looking at page 13, and when
7
I use page numbers I'm using the page numbers in the top
8
right-hand corner.
9
asked to do, just to clarify what you were asked to do and
10
what you did not -- you were asked not to do and you have
11
not opined on.
12
I just want to understand what you were
And as I read the purpose of your testimony, and as I
13
read it, it says you were asked to provide an assessment,
14
an independent and objective assessment:
15
"...of the degree to which Ontario Power
16
Generation's plan and approach to execution of
17
the DRP, including the processes in place for
18
management of cost, schedule, program controls,
19
and the application of any contingency are
20
consistent with other ways megaprojects and
21
megaprograms of similar magnitude and scale,
22
complexity, have been carried out."
23
Am I reading that correctly?
24
DR. GALLOWAY:
25
MR. RUBENSTEIN:
That's correct.
And if we take that to sort of a
26
higher level, really, as I read your report, what you
27
opined on in your understanding, you looked at the
28
processes to develop the cost, the schedule, the program
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controls, the contingency, and you found them reasonable.
2
DR. GALLOWAY:
3
the structure as well.
4
5
MR. RUBENSTEIN:
And also looked at the organization and
And you found that they were
reasonable.
6
DR. GALLOWAY:
7
I indicated yesterday.
8
MR. RUBENSTEIN:
Yes, in light of all of the things that
So just to be clear what you weren't
9
asked to do and which you have not opined on, you have --
10
while you have determined that the processes and plans are
11
reasonable, the numbers that underlie them, have you -- you
12
have not determined that they're prudent.
13
DR. GALLOWAY:
14
MR. RUBENSTEIN:
Am I correct?
I'm a little bit -So I'll give you an example.
So you
15
talk about in your report that the process to determine the
16
cost estimate is reasonable.
17
the $12.8 billion is specifically a reasonable number or
18
the cost items that underlie the budget -- you haven't done
19
a line-by-line to review to make sure they're correct.
20
I correct?
21
DR. GALLOWAY:
You have not determined that
Am
Well, there is not a line-by-line
22
review done.
What we did review within the estimate is we
23
looked at the basis of estimate that was prepared by OPG
24
that is quite a detailed document that discusses how the
25
actual costs were developed, the source documents for those
26
costs, the actual estimates for the cost.
27
reviews of samples of some of those source documents to
28
ensure that the dollars that are composed of some of those
We did do
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elements follow through that cast basis of estimate, and
2
then would translate into the model for the P90 confidence
3
level.
4
We did look at the risk registers, for instance, which
5
have input into how the total cost is developed, relative
6
to whether or not the types of risks that were being looked
7
at were reasonable types of risks to be modeled and
8
incorporated within that.
9
Then we also looked at other independent reports that
10
were done based on the estimate and the risk, to look at
11
other subject matter experts that have done a much more in
12
depth review of those.
And that's the whole process.
13
So the process is what we did look at, but that
14
process does incorporate the review of actual samples of
15
how they went about the process to get those numbers and to
16
get the risks that go into the $12.8 billion.
17
So with that sampling and the way it's modeled, it
18
should be a reasonable number based on the reasonable
19
process, and the fact that it followed industry practices
20
and it followed all of the lessons learned and the
21
development of the actual cost estimates itself.
22
So based on those reviews, the inputs, and the
23
independent reviews of those inputs on those specific
24
dollar items, then the 12.8 was derived based on a
25
reasonable and prudent process.
26
MR. RUBENSTEIN:
Let me ask you about -- you talked
27
about you reviewed the risk register.
In doing so, as I
28
understood it, you opined that the process to determine how
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to -- which risks to include and how to value those risks
2
you think are reasonable.
3
Am I reading that correctly, that when you talk about
4
your review of the risk register, that's what you've done?
5
MS. GALLOWAY:
Well, we went through the risk
6
register.
7
with individuals as well to understand how those risks were
8
derived, how they were vetted, how they ensured all the
9
risks were captured.
10
Part of the reason we had reviews and interviews
I don't remember, sitting here today, exactly which
11
risks we probably talked about specifically from those risk
12
registers.
13
sampling, you know, how did you get that risk, how was that
14
looked at, how was it then incorporated.
15
merely going through the exercise.
16
doing the risk register proper, but getting down a little
17
bit more into the granulation how specific risks were
18
identified, how they were vetted, how they were then
19
incorporated into the risk register, and then how they were
20
modeled in the probabilistic risk model itself.
21
But did look at specific risks to inquire as a
MR. RUBENSTEIN:
So it wasn't
It was the exercise of
So did you verify -- as I understand
22
it, there are a thousand-plus risks in the risk register.
23
Did you look at each individual risk and determine that the
24
risk has been described appropriately, the probability is
25
being determined appropriately, the financial value or the
26
cost if it materializes has been appropriately determined
27
and is appropriate, and the scheduling cost -- essentially
28
the delay it may cause, the impact is correct.
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You didn't do that for each individual item?
2
MS. GALLOWAY:
As I indicated, we took a sampling.
We
3
did not look at each individual item.
We looked at
4
individual samples from the risk register, and then probed
5
those specific items to determine whether or not they did
6
in fact follow through the process of what we would expect
7
a reasonable and prudent individual and organization,
8
whether it be utility or another owner, or even a
9
contractor, what would be expected of how they would look
10
at those risks, cost those risks, and put those risks into
11
the ultimate model.
12
MR. RUBENSTEIN:
Am I correct that you -- I don't
13
think you were asked to, and I don't think you did.
You
14
were not asked to opine on the reasonableness of certain
15
cost overruns with respect to safety and improvement
16
projects, and facilities and infrastructure projects, any
17
prerequisite projects?
18
MS. GALLOWAY:
Not the actual cost itself, but how
19
those cost impacts were being used relative to lessons
20
learned, and how the lessons learned from those were being
21
incorporated into the DRP estimate, and also the policies,
22
procedures and management and how the DRP would be executed
23
going forward to minimize against the type of cost
24
increases that happened on the F&IP and SIO projects.
25
26
MR. RUBENSTEIN:
Thank you.
If we can turn to page
25, I'm reading from line 5, and you say:
27
"By utilizing the higher confidence number, e.g.
28
P90,the owner and stakeholders reduce a
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2
significant amount of risk due to cost overrun."
Do you see that?
3
MS. GALLOWAY:
4
MR. RUBENSTEIN:
Yes, I do.
You'd agree with me that by utilizing
5
a higher confidence level, the owner and stakeholders
6
increase the likelihood that the project will come in under
7
budget?
8
MS. GALLOWAY:
9
MR. RUBENSTEIN:
Yes.
And you say, and this is on line 19:
10
"Selection of a confidence level primarily is
11
reflective of the risk appetite of the owner."
12
Do you see that?
13
MS. GALLOWAY:
14
MR. RUBENSTEIN:
15
16
Yes.
Can you explain to me what you mean
by that?
MS. GALLOWAY:
So if you go back up to line 5 and 6,
17
it's specifically -- and this is what I was referring to
18
yesterday in my testimony -- by utilizing higher confidence
19
number, e.g. P90, the owner and stakeholder reduces a
20
significant amount of risk due to cost overruns.
21
The owner, and this is what we looked at here, has to
22
look at what the confidence level must be from both a
23
regulator and themselves, and whether or not those costs
24
that are going to be put forth are going to be reliable so
25
that the utility has some confidence that it will be able
26
to manage the project and the program here within that
27
envelope of risk to a certain degree of certainty that it
28
can meet its budget.
And at the same time, the regulator
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1
has confidence that the program will also be able to be
2
completed within a certain cost regime, because regulators
3
have to look into the future as to, over a compendium of
4
time, of where costs might be at some point in the future.
5
So it's important, from our review, that we look at
6
both stakeholder expectations and we look at the
7
circumstances of the risk, the complexities, the magnitude
8
and that we build in some of those risks within a
9
confidence level that allows management to manage a program
10
potentially at a lower confidence level, but having an
11
envelope to ensure the number that it's putting forth for
12
approval at a point of time which is years earlier than
13
completion, there is a much higher reliability in a.k.a.
14
confidence that the program will not go beyond that cost or
15
schedule, similar to what I was talking about with, for
16
instance, Crossrail yesterday.
17
MR. RUBENSTEIN:
I understand why OPG would want to
18
limit its risk.
19
ultimately have to pay for the cost overrun themselves.
20
They may be able to get approval and pass it on to
21
ratepayers, but they have to pay for it.
22
That makes sense to me as the owner.
I don't understand why ratepayers should have to pay
23
to deal with OPG's risk appetite.
24
understand that?
25
They
MS. GALLOWAY:
Can you help me
Again, when I indicated the -- the risk
26
appetite is looking at what both stakeholders are going to
27
have to put forward as a reasonable and reliable cost,
28
ultimate cost of a program.
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If you look at past megaprograms -- and this is what I
2
was alluding to yesterday -- in which other megaprogram
3
experts out there today have also now opined upon, is that
4
the cost estimates were too low and they were not reliable
5
because they did not adequately consider the types of risks
6
that is could arise that one cannot see today.
7
therefore, the probabilistic risk modelling is important
8
and the confidence level, depending on the magnitude, the
9
size, and the complexity of the project is important.
And
And
10
what is being found today relative to megaprograms is that
11
the stakeholders that are recognizing that, especially, I
12
will say, public stakeholders that do have to report out to
13
a customer, a ratepayer, the public at large, taxpayers,
14
whatever the megaprogram is going to be, that you want to
15
be able to have some assurance that when you tell your
16
customer, your taxpayer, the public of what something is
17
going to cost, there is now an expectation, and to prepare
18
for that expectation, and to be able then to manage so you
19
would come in at or even below that cost or schedule.
20
at the end of the day all stakeholders' expectations have
21
been met.
So
22
On lower confidence levels, it's, for instance, a P50
23
level, the AKA of that is there's a 50 percent chance it's
24
going to come in on time and on budget, but there is a 50
25
percent chance it's not.
26
risk if it's going to go over budget and over schedule and
27
a cost that neither the governments want to try to
28
reconcile of why that happened or even the utility or the
And that 50 percent is a huge
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owner building a project to say it's not a number that
2
we're comfortable because of the risks that we do not know
3
today that could happen.
4
risk modelling with all the risks that potentially could
5
occur and why you choose a higher confidence level on a
6
program of this size and magnitude and complexity.
7
MR. RUBENSTEIN:
That's why you do a probabilistic
So I understand from what you're
8
saying then that there is some benefit to coming in under
9
budget, right?
OPG doesn't need to explain to other
10
entities why it came in over budget.
11
inherent benefit for large projects to come in under
12
budget.
13
There is just an
Did I -- am I understanding that correctly?
DR. GALLOWAY:
I think when you plan a project of any
14
sort the goal from all stakeholders is to come in within
15
budget and within schedule.
16
or schedule that's all a bigger benefit.
17
to make sure that you meet the schedule and budget so set
18
at the beginning.
19
should be an expectation on any project.
20
If you can exceed that budget
But the goal is
That's an expectation on any project and
MR. RUBENSTEIN:
Well, I would have thought the goal
21
here is to determine the right budget and the right
22
schedule, it's not about setting expectations, necessarily.
23
DR. GALLOWAY:
Well, the expectations goes to how
24
you've planned the project.
This program was planned on a
25
P90 confidence level, meaning when they model the risks and
26
come out and look at those risks, they are looking at the
27
combination of all risks over four units that can accrue
28
and possibly arise over the entire tenure of the planning
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2
for this program.
That P90 confidence level means that if a good portion
3
of those risks arise, and they could, no one knows whether
4
they will or will not arise sitting at this point today,
5
then there is confidence that it is a reliable and a good
6
budget based on that risk modelling.
7
is showing.
8
9
That is what the P90
So there becomes an expectation that you will meet
whatever estimate that arise from that P90 modelling.
10
that's the expectation.
11
it's going to come in at 12.8.
12
that, that will be a benefit to everyone.
13
MR. RUBENSTEIN:
So
If it's 12.8, the expectation is
And if it comes in below
As I understood from your
14
examination-in-chief, you went back into your files and you
15
looked and you said, well, what other projects that I've
16
been involved in have a P90, and you were able to find two.
17
Did I understand that?
18
I believe the other one was the Bellefonte project?
19
DR. GALLOWAY:
There's the Crossrail project, and
Yes, I think I indicated yesterday I
20
did not remember -- first of all, we don't keep our records
21
based on what confidence levels or where things modelled or
22
don't model.
23
risk modelling at the time of the CPCN on either the Kemper
24
or the Duke project.
25
'70s and '80s risk probabilistic modelling did not even
26
exist, and so obviously those projects would have never had
27
one, because the modelling, the software, just wasn't in
28
place to do that.
I even talked about today that there was no
It just wasn't done.
Back in the
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When I have obviously been reading the testimony every
2
day, when I saw questions on the P90 I tried to think
3
whether or not there potentially was recent projects where
4
I did see that and records that I have, you know, available
5
to me.
6
it went through a very detailed risk modelling exercise.
7
do know that it had a confidence level.
8
remember the confidence level of the Crossrail project, so
9
I did check that.
I remember something on Crossrail, because I knew
I could not
Similarly, I remembered there was risk
10
modelling done for Bellefonte, and so I went back to
11
determine whether or not that also had a P90 modelling,
12
which I found that it did.
13
MR. RUBENSTEIN:
Do I take it -- you may not know
14
this, but do I take it that those were the only two that
15
you were able to remember or look up, that the majority of
16
projects don't use a P90?
17
I
DR. GALLOWAY:
I would agree that there are not very
18
many projects that use a P90.
It depends on the complexity
19
and the magnitude.
20
the same complexity and magnitude because one was a nuclear
21
project and the one was an 18 billion dollar project.
22
is part of the reason I went back to those files, because I
23
thought they were of the same magnitude and complexity.
24
I don't know whether some of the others did or did
The two that I mentioned I knew were of
That
25
not, because I didn't consider other projects to be of the
26
same size and complexity, so I did not go back to the files
27
to check.
28
MR. RUBENSTEIN:
And I am correct that your opinion as
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you've talked about earlier with respect to the DRP is
2
that, you know, this project has done more work leading up
3
to execution phase really than most projects?
4
DR. GALLOWAY:
5
MR. RUBENSTEIN:
Yes.
I want to ask you about -- briefly
6
about megaprojects and nuclear megaprojects.
7
heard from a number of OPG witnesses and from the
8
documentary evidence, and I think you've commented on it
9
indirectly, they have a habit of going over budget and over
10
11
As we've
schedule, or beyond schedule, correct?
DR. GALLOWAY:
I believe you have to look at the
12
circumstances at the time.
I do believe that, yes, the --
13
from the original cost estimate to where they are now, the
14
ones in the '70s and '80s obviously were under different
15
circumstances.
16
being actively built in the United States anyway to do
17
comparisons on.
18
what those original estimates were and what the conditions
19
and qualifications were.
20
MR. RUBENSTEIN:
There is only three today that are out --
And I think I've already testified as to
I'm not saying that the reasons for
21
the over budget or why they went behind schedule were
22
imprudent, but just generally megaprojects, and made a
23
career helping utilities work towards solving this problem,
24
I think, you know, that they've gone over budget and
25
they've gone over schedule, they have a chequered past in
26
that regard, at a high level.
27
28
DR. GALLOWAY:
But I don't think it's fair, because
there is not a fair comparison of how the original
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estimates were developed.
2
developed on P90 modelling.
3
same pre-execution planning.
4
The original estimates were not
They weren't developed on the
Had they done the same type of pre-execution planning
5
and they done risk probabilistic modelling, the initial
6
estimate would have been much higher, and if the initial
7
estimate had been much higher their results may be much
8
different than they are.
9
So I don't think it's a fair-to-fair comparison to
10
look at what the initial estimate was and where they've
11
ended up, because they're not apples-to-apples as to how
12
the original estimate was initially developed.
13
MR. RUBENSTEIN:
So let me go back to page 13 of your
14
report, where you were asked what your -- essentially your
15
task was.
16
processes in place for cost, schedule, program controls,
17
and the application of the contingency to ensure that they
18
are consistent with the way other megaprojects and
19
megaprograms of similar magnitude, scale, and complexity
20
have been carried out.
And you were to make an assessment of the
21
So would I be -- so do I understand what you're
22
essentially doing is you're -- you looked at what OPG did
23
and you compared it against, well, what is everybody else
24
doing, and that's how you come to the assessment that OPG
25
is doing a much better job than most other projects.
26
DR. GALLOWAY:
Yes, I mean, it was -- we looked at the
27
industry standards.
We looked at other megaprograms, ones
28
that are underway, ones that have been completed in the
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past, and we looked at utility industry best practice.
2
Those are the three items that we used to valuate the
3
reasonableness and prudence of what's going on in the
4
Darlington refurbishment program.
5
MR. RUBENSTEIN:
So if other utilities and other
6
projects and other megaprojects, as you were saying, maybe
7
didn't have the best comparison, they didn't do as much
8
budgeting, and so they end up going -- at least maybe on an
9
apples to oranges comparison -- over budget.
10
Is it maybe true that the way those megaprojects and
11
megaprograms in the past are actually not the best way to
12
compare.
13
be a better way to do it?
14
We shouldn't look at these projects; there should
MS. GALLOWAY:
I think that as I so indicated
15
yesterday, that's one of the areas where Mr. Roberts and I
16
agree that each megaprogram -- there are so many different
17
variables that go on between projects that make them
18
unique, that it's not possible do an apples to apples
19
comparison between a megaproject and a megaprogram.
20
However, as I also indicated yesterday and again this
21
morning, is that what the global construction industry as a
22
whole and both governments and owners and financers are
23
learning is that there's a lot of elements of why
24
megaprojects have gone over their initial schedule and
25
budget, that we as an industry are learning from.
26
For instance, doing a probabilistic modelling, going
27
to P90 confidence level for these very large projects is
28
something that we are learning, when you do megaprojects,
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that you should do more of.
More pre-execution planning
2
would assist greatly in having the megaprograms be
3
successful, from both a cost and a schedule perspective.
4
This is something that Mr. Flyvbjerg, for instance,
5
has come out I think even last year in an article that he
6
prepared, that we are learning from megaprograms and how
7
they were executed, and the very things I just talked about
8
are things that different entities are now using, and that
9
there is going to be a higher probability of success for
10
these megaprograms as they apply these types of lessons
11
learned from megaprojects in the past.
12
MR. RUBENSTEIN:
If we turn to page 22, here you're
13
discussing -- this is with respect to is the setting up
14
your discussion of cost management, and you were asked
15
about the industry standards you use.
16
talk about the government accountability office, at GAO,
17
you talk about the AACE basis.
18
19
20
And as I see, you
Am I correct that those are the industry standards
that you are looking at?
MS. GALLOWAY:
We looked at Project Management
21
Institute, we looked at AACEI, we looked at the U.S.
22
government accounting, and then with the experience that I
23
have in the utility industry, obviously utility industry
24
best practices as well.
25
MR. RUBENSTEIN:
When we turn to page 30 where you're
26
talking about schedule management, again you're looking at
27
the Project Management Institute, you're talking about the
28
AACE, and you're talking about the government
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2
3
accountability office.
Those are the industry standards you're making the
comparison to?
4
MS. GALLOWAY:
And utility best practices.
5
MR. RUBENSTEIN:
Are there industry standards for
6
schedule development applicable to megaprojects?
7
and AACE, along with other entities such as GAO."
8
That's what I am reading of what you've --
9
MS. GALLOWAY:
"Yes, PMI
Right, and at the very beginning of
10
what you've read me on the initial pages comparing to other
11
megaprograms and megaprojects, it goes into the utility
12
best practice of other megaprograms and megaprojects of
13
what the utility industry has done in its planning.
14
one of the aspects that's also within this.
15
That's
That's not, quote, a written standard, which is why
16
it's not included in this answer.
17
evaluation process as outlined earlier in what we were
18
comparing to.
19
MR. RUBENSTEIN:
But it's part of the
Then if I go to page 34, where you
20
are talking about reporting -- sorry, you're talking about
21
reporting management.
22
Management Institute best practices.
23
that.
24
MS. GALLOWAY:
Here you're utilizing the Project
I see a reference to
It would be one of the references.
But
25
again, it would be the same industry standards from Project
26
Management Institute, what is also from AACEI utility best
27
practices, those would be all the same standards we would
28
be evaluating against.
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MR. RUBENSTEIN:
When I go to page 25 and you talk
2
about the contingency, am I correct -- is there an industry
3
best standard of the confidence level you should choose, or
4
is that strictly your industry experience that you're
5
drawing your views from?
6
MS. GALLOWAY:
I think I include in my testimony that
7
there is not an industry standard relative to the choosing
8
of a confidence level, that it is unique to each project
9
and it depends on its magnitude, complexity, size, and the
10
11
risk that it's looking at.
I think I've made that statement in my testimony that
12
there is not, quote, a standard for choosing a confidence
13
level.
14
15
16
MR. RUBENSTEIN:
Thanks very much.
Those are my
questions.
MS. LONG:
Thank you, Mr. Rubenstein.
I think we'll
17
take our morning break for fifteen minutes, and then, Mr.
18
Buonaguro, you can proceed.
19
--- Recess taken at 10:48 a.m.
20
--- On resuming at 11:06 a.m.
21
MS. LONG:
22
CROSS-EXAMINATION BY MR. BUONAGURO:
23
MR. BUONAGURO:
Mr. Buonaguro.
Thank you.
Good morning.
Good
24
morning, Dr. Galloway.
25
counsel for Consumers Council of Canada, and I have some
26
questions for you.
27
28
My name is Michael Buonaguro.
I'm
First I would like to follow up on some of the
information you gave about the Kemper project.
That's what
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I'm going to call it, the Kemper project.
2
mentioned that March 31st, 2013 was the last time you were
3
directly involved in reviewing that project pending the new
4
review of the project, the new prudence review, I think you
5
referred to.
6
DR. GALLOWAY:
You had
No, I am currently still reviewing.
7
It's just the pre-filed testimony that was filed was only
8
as of March 31st, 2013.
9
MR. BUONAGURO:
Right.
So your -- when you were
10
referred to your opinion on the Kemper project it was the
11
point-in-time opinion of March 31st, 2013?
12
DR. GALLOWAY:
13
MR. BUONAGURO:
Yes.
And so just for comparison purposes,
14
your point-in-time review of the DRP, I think you've
15
mentioned yesterday, I think it was to Mr. Stephenson,
16
would be July 31st, 2016?
17
DR. GALLOWAY:
18
MR. BUONAGURO:
Correct.
Right.
So it's the same sort of
19
thing, things that happened after that date you obviously
20
haven't reviewed, so for example, whatever OPG has done
21
since July 31st of 2016 you don't have an opinion on.
22
DR. GALLOWAY:
23
MR. BUONAGURO:
Correct.
Okay.
And you said something
24
interesting about Kemper.
25
- that March 31st, 2013 date related to an annual review of
26
the Kemper project that you used to do?
27
28
DR. GALLOWAY:
And you said, I think the last -
So in the CPCN order on Kemper the
commission had indicated that it was going to set up an
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1
annual prudence review to review matters annually and make
2
a determination on prudence annually.
3
in, and then the commission changed its decision, came out
4
with a new order, and indicated that it was not going to
5
review prudence on an annual basis and it would wait until
6
the project was completed to hear prudence.
7
MR. BUONAGURO:
Okay.
The pre-filings went
So maybe I can follow up.
How
8
many years of annual review actually happened, or are you
9
telling me none happened?
10
11
12
DR. GALLOWAY:
None happened.
There have been zero
prudence hearings on Kemper to date.
MR. BUONAGURO:
Okay.
That explains a lot then,
13
because the way it came up earlier it sounded like it had
14
been going on and it stopped, but you're saying it actually
15
never really got started.
16
DR. GALLOWAY:
17
MR. BUONAGURO:
18
DR. GALLOWAY:
19
The prudence review, that's correct -On an annual --- never been a hearing to date
since --
20
MR. BUONAGURO:
21
DR. GALLOWAY:
22
MR. BUONAGURO:
Okay.
-- the CPCN hearing.
Thank you.
And I want to lead into my
23
questions in general with something I heard yesterday if I
24
could.
25
154, from -- I don't know what volume number it is, sorry
26
-- volume 5.
27
Starting at line 26 of page 153.
28
This is from the transcript, page 154 -- or 153 to
It's going to come up on the screen.
So I pick up part of your answer there, and you say:
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"And that is why the megaprograms that are taking
2
what I would call a more realistic view of having
3
as much information as they reasonably can based
4
on what is known at the time and modelling that
5
from a probabilistic standpoint that the financer
6
of the megaprogram, whether that's a private
7
entity, an investment bank, an owner, a
8
commission, gives them a higher confidence of
9
what they know and ultimate cost may be, and they
10
can then make better informed decisions knowing
11
what that ultimate cost may be."
12
So I took that to mean in the context of this case --
13
and we're talking about the OPG's use of a P90 for the DRP
14
-- and I'm going to talk in terms of Unit 2 cost, as
15
opposed to the entire program costs if I may.
16
we're talking about the DRP Unit 2 costs projected of 4.8
17
billion dollars to go into service in 2022 -- sorry, 2020,
18
I believe, the P90 basically tells everybody, don't be
19
surprised if it comes into 4.8 billion, because there's a
20
lot of things that are going to happen between now and then
21
that we've modelled using the Monte Carlo simulation, so on
22
and so forth, but hopefully it will come in under, and if
23
it goes over there's going to have to be pretty good
24
reasons for it.
25
here; is that fair?
26
So when
That's sort of how I took what's going on
DR. GALLOWAY:
Well, the P90 confidence modelling was
27
done on four units, not on just one unit.
And so all of
28
the units, of course, with how they are interconnected and
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the risks are all modelled on a four-unit basis.
2
would be difficult for me to opine specifically on, quote,
3
how those risks may be separated out, because I don't think
4
you can easily separate out the models since it was on four
5
units.
Okay.
And so it
6
MR. BUONAGURO:
So thank you for that.
7
I had understood, and perhaps I misunderstood, that
8
you had said something about what you were asked to do, and
9
you talked about allocation, and I had assumed that that
10
meant the allocation of the contingency.
11
Are you telling me that you don't have an opinion
12
about how OPG has allocated the contingency amount of $1.7
13
billion between the units?
14
DR. GALLOWAY:
We looked at it from an entire program.
15
So the contingency as it applied in the P90 model for the
16
entire program, and not specific to, quote, Unit 2.
17
MR. BUONAGURO:
Okay.
Fair enough.
You're aware,
18
though, that they've allocated for the purposes of rate-
19
setting 700 million or so of contingency to Unit 2?
20
DR. GALLOWAY:
21
MR. BUONAGURO:
22
23
Yes.
And again, I've rounded it up.
It's
changed slightly, but -- thank you.
And I think, though, from what you're saying and what
24
I had understood about contingency in the first instance,
25
when the company comes with a completed Unit 2, hopefully,
26
in 2020, if the total amount for Unit 2 isn't 4.8, it could
27
be more than 4.8, because more than the allocated, quote
28
unquote, amount of contingency occurred as Unit 2 is being
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built, but it also could be less, because less of the
2
allocated contingency could have occurred in relation to
3
Unit 2.
4
5
6
Those are both reasonable scenarios?
DR. GALLOWAY:
Yes, projects could come in before and
under.
MR. BUONAGURO:
Yeah.
And then if we talk more
7
holistically on the 12.8 billion and the $1.7 billion of
8
contingency for the entire project, contingency may not
9
come to fruition in that amount.
10
It might come in lower.
And hopefully it comes in lower, right?
11
DR. GALLOWAY:
12
MR. BUONAGURO:
Yes.
Okay.
Now, I want to talk briefly
13
about imprudence, because a lot of your evidence that --
14
or, sorry, I should say a lot of the examples of evidence
15
that you've given in the past related to what I would call
16
ex post facto prudence reviews; is that correct?
17
DR. GALLOWAY:
18
MR. BUONAGURO:
Yes.
Where you've looked at how a company
19
has managed a project to completion and then asked for
20
approval of costs, and part of the review of those costs is
21
to see if any of the costs incurred were actually
22
imprudently incurred?
23
DR. GALLOWAY:
Yes, but with the caveat of it's not --
24
in hindsight it's not an after-the-fact review per se,
25
because under the prudence statute in the U.S., the
26
jurisdictions, is that every decision that is made has to
27
be looked at and evaluated and it has to be looked at in
28
the time that it was made based on what it was -- what was
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known or what reason it should have been known at the time.
2
So it's not like you have the ability on five years to
3
say, well, that decision, actually, after five years
4
doesn't look like it was a good decision.
5
in the context of when the decision was made and what was
6
known.
7
MR. BUONAGURO:
Fair enough.
It has to be put
The difference being,
8
though, that because you're not able to sit with the
9
company and watch them make decisions in real-time, you
10
have do it after the fact, but I understand what you're
11
saying.
12
not is in the context of the time they're making the
13
decision and what they had available to them at the time of
14
the decision.
15
The measure of whether they're being reasonable or
DR. GALLOWAY:
Yes, but just to correct one -- I think
16
your prior question was, our prudence reviews are always de
17
facto after the fact.
18
Vogtle this morning, those reviews was on the CPCN, so that
19
was in the exact scenario as here, as I relayed to the
20
Board.
21
I want to -- as I talked about with
So the project had not gone forth to an execution yet
22
at all.
23
prudence review was done on the pre-execution planning for
24
Vogtle.
25
It was seeking approval to go forward, and so that
MR. BUONAGURO:
Thank you.
But I'm assuming that any
26
-- whenever you do that type of review, you're always
27
limited at the point in time, right?
28
you haven't -- and not presuming to evaluate all the
As we talked about,
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decisions that OPG makes from July 31st forward and bless
2
them as prudent in advance.
3
31st, 2016, based on what they're planning to do, it looks
4
good, it looks prudent.
5
DR. GALLOWAY:
You're saying that as of July
And how they are planning to actually
6
implement and go forward with the execution.
7
just the establishment of what they have in place, but
8
actually their plans for execution and their understanding
9
of those plans on how they will implement the policies,
10
procedures, and processes.
11
is true here.
So it's not
That was true in Vogtle, and it
12
So you're looking at, and I think I so opined, that
13
based on that approach, based on the interviews with the
14
project personnel who will be responsible for executing the
15
program, that plan would favourably position OPG for a
16
successful execution.
17
18
MR. BUONAGURO:
That's assuming that they execute in
accordance with their plans.
19
DR. GALLOWAY:
20
MR. BUONAGURO:
Yes.
I think that's what Schiff Hardin's
21
evidence raises the issue of, which is that planning is
22
great, and I think they generally agree that the planning
23
is done well, but it's the actual execution of those plans
24
over the next four years which may or may not result in
25
imprudent costs, right?
26
DR. GALLOWAY:
True.
But I think Mr. Roberts and I
27
both agree that the process and the tools that are in place
28
are reasonable and prudent, and if executed in accordance,
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2
should allow for a successful execution of the DRP.
MR. BUONAGURO:
If we come to 2020 and the project
3
comes into service, and the dollar value for the DRP is as
4
budgeted, the $4.8 billion, are you saying that we know for
5
sure that that does not include any interim costs?
6
DR. GALLOWAY:
I don't think I can answer that sitting
7
here today.
8
one has the ability to evaluate.
9
10
11
Those are actions in the future for which no
MR. BUONAGURO:
I fully expected that to be your
answer; I'm just making sure.
Now, in order to determine whether or not there's
12
imprudent costs built into that final cost, I assume this
13
Board, if it were so inclined, would have to look at the
14
evolution of the project and decision-making and
15
essentially do a prudence review of the project to
16
distinguish between costs that are what I might call true
17
contingency costs -- i.e., costs that were identified and
18
responded to and mitigated, but still incurred -- versus
19
costs that resulted as a result of imprudent decision-
20
making or execution by OPG.
21
That sort of analysis would have to be done in order
22
to separate out prudent costs versus imprudent costs,
23
right?
24
DR. GALLOWAY:
Again, in the pre-approval of a cost
25
estimate -- I mean, no one goes into pre-planning assuming
26
that you're going to be imprudent.
27
fraud or issues of concealment, both items of which even
28
the commissions and jurisdictions in the United States
But barring things of
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would say if those happened, then those particular costs
2
would not be allowed even if they were under a particular
3
cost.
4
But the pre-approval of the cost estimate is deemed to
5
be reasonable and prudent and encompasses a contingency to
6
cover risks that could happen, and if a utility comes in at
7
that cost, those costs would go into rate base as pre-
8
approved but for actions of fraud or concealment.
9
MR. BUONAGURO:
I see.
So if this Board approves
10
$4.8 billion for Unit 2 and the project comes in at
11
$4.8 billion or less, you're suggesting that the only
12
disallowance of any of that amount would have to relate to
13
-- I think you said fraud or concealment?
14
DR. GALLOWAY:
That would be up to the Board on
15
however they decide to look at those costs.
16
be for me to tell the Board what to do.
17
MR. BUONAGURO:
That wouldn't
I'm following up on what you said.
18
You said pre-approval of a cost usually means that when
19
they come in for -- when the final costs are incurred and
20
the costs are at or below budget, then it's fraud or
21
concealment?
22
23
24
DR. GALLOWAY:
That's the way the jurisdictions in the
States handle it, yes.
MR. BUONAGURO:
If that were the way it worked here
25
and the Board remained concerned it wants to distinguish
26
between what I call contingency amounts -- so contingency
27
amounts meaning amounts that don't necessarily relate
28
specifically to a contract, but relate to the risks they
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identified and came to fruition and caused that -- some
2
part of that 700 million budgeted amount versus costs that
3
actually were imprudently incurred, in terms of failing to
4
identify risks that they should have identified, or not
5
reacting appropriately to a risk, the solution would be to
6
lower the amount that's pre-approved?
7
DR. GALLOWAY:
I think you would have to look at the
8
circumstances.
I think based on the premise you put
9
forward is not enough facts to ascertain.
There's
10
considered in prudence a zone of reasonableness.
11
not necessarily a -- there is not an optimal response.
12
There is not a preferred response.
13
There is
There are different responses that management can take
14
depending on the circumstances at the time, which is why
15
you have to look at the circumstances at the time.
16
the examples that you gave, if they -- what would appear to
17
be an inappropriate use to a risk would have to look at all
18
the facts at the time on the circumstances of why that may
19
appear to be an inappropriate risk, but based on other
20
factors, would still fall within a zone of reasonableness
21
which would have been covered within that contingency
22
aspect for the estimate.
23
MR. BUONAGURO:
Fair enough.
So even
But my point is that
24
that examination would take place after the fact.
25
a difference between what you told me, I think, about the
26
impact of a pre-approval of a budget versus part of a
27
budget that isn't pre-approved.
28
Maybe I can attack it this way.
There's
If the pre-approved
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budget is 4.8 billion and the costs come in at 5.5 billion,
2
presumably there's going to be -- we know there's going to
3
be a request from OPG to recover the impact of that
4
additional .6 billion dollars in spending, and the
5
examination by the Board is going to have to look at
6
whether or not that extra cost was prudently incurred,
7
correct?
8
9
10
DR. GALLOWAY:
I assume.
I'm not sure how this Board
works in this jurisdiction, but I would presume so.
MR. BUONAGURO:
Right.
And in that instance, would
11
the same limitations on the prudence review be in place
12
that you were talking about?
13
fraudulent or concealment?
14
DR. GALLOWAY:
It would only be if they were
I don't know.
I'm not familiar with
15
what this Board -- one, what OPG will ask, what this Board
16
will opine upon, and how that relates to the overall 12.8-
17
billion-dollar estimate.
18
As I indicated, the risks and the costs are all done
19
on a probabilistic modelling of all four units, and so a
20
cost overrun on Unit 2 may potentially, based on the
21
lessons learned from Unit 2 that resulted in those cost
22
overruns, may be applied to the later units that
23
potentially costs could be reduced in later units, so
24
within the overall contingency of the $12.8 billion, the
25
entire program still comes in on budget.
26
So it is with those considerations that would need to
27
be looked at relative to any overage on Unit 2, because it
28
can't be looked at in isolation on the total cost of the
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program because that -- the way the cost overruns and
2
under-runs are modeled are on the four unit process, not an
3
individual unit basis.
4
MR. BUONAGURO:
Thank you.
My point being, though,
5
that the exercise would have to be done.
6
look at what actually happened in order to make the
7
determination of whether or not there was imprudence, or
8
whether it was simply an appropriate contingency event or
9
contingency cost?
10
DR. GALLOWAY:
You would have to
There's a lot of factors.
I'm not sure
11
I can totally answer your question, because I don't know
12
the facts and the circumstances that may arise 4 to 5 years
13
from now.
14
MR. BUONAGURO:
Thank you.
I want to take you to page
15
34 of your evidence briefly, Exhibit D2, tab 2, schedule
16
11, attachment 3, page 34.
17
I am looking at the bullet points under what types of
18
information is typically provided -- I guess that should
19
have been what types of information are typically provided
20
in performance or progress reporting.
21
I'm looking at the bullet points and most of them, I
22
think I can fit under reporting that OPG is proposing to do
23
on an annual basis with respect to the DRP.
24
that sticks out to me is the current status or risks and
25
issues.
26
the reporting proposal by OPG with respect to the DRP, did
27
you?
28
But the one
Did you review -- I think you said you reviewed
DR. GALLOWAY:
Yes.
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2
3
MR. BUONAGURO:
And did you see them proposing to
report on current status or risks in issues?
DR. GALLOWAY:
I believe that I saw a dashboard type
4
of proposal where you have -- and it's very commonly used
5
nowadays on megaprograms, where you have, like, colours,
6
you have green, yellow, red, red being risks that are
7
critical risks that could impact cost or schedule, yellow
8
that means they might, and green meaning they probably
9
don't have any impact.
10
I believe I saw some type of dashboard reporting that
11
would on a macro level present overviews on risks and risks
12
that were occurring to the project.
13
14
MR. BUONAGURO:
You note in the evidence in the
preface to the bullet points, you say:
15
"PMI notes that more elaborate reports may
16
include..."
17
Bullet, bullet:
18
"...current status or risks and issues."
19
Can you give an example of where that's occurred in
20
21
another context?
DR. GALLOWAY:
It's occurring on Vogtle.
It's
22
occurring on Kemper.
23
program that we're doing the independent monitoring on.
24
MR. BUONAGURO:
It's occurring on the Energy Strong
And what's the depth of detail in
25
those reports on the current status of risks and issues?
26
Is it --
27
DR. GALLOWAY:
28
MR. BUONAGURO:
It's the dashboard that I talked about.
That's it?
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DR. GALLOWAY:
Yes.
There's not more detail that is
2
provided in those particular annual reports.
I mean, us as
3
the independent monitor, of course, look at more detail
4
that the utility is actually using to look at those risks
5
by looking at the risk registers and whether or not they
6
are actually determining whether risks are retired or
7
whether new risks have arisen and how they've been looked
8
at and how they've been viewed, and then ensuring that that
9
information rolls up to that dashboard type of a review,
10
which is what we consider appropriate for a senior
11
management and Board review of how the project stands
12
currently to risks and issues.
13
MR. BUONAGURO:
So if the Board were interested in an
14
annual report versus -- of that level of detail, that's the
15
sort of reporting that would have to be done to the Board,
16
the OEB, as opposed to the -- I can't remember what you
17
called it -- the dashboard amount, which is what is given
18
to the public?
19
DR. GALLOWAY:
No, no, no, no, no.
What I meant by
20
the dashboard, that is the level of reporting that is given
21
both to senior management of a utility, given to its Board,
22
and given to the commission.
23
typically provided, is that dashboard overview.
24
25
26
27
28
MR. BUONAGURO:
That is the level that is
So who is the target audience for what
you just described to me in terms of the level of detail?
DR. GALLOWAY:
The risk -- which level of detail are
you talking about, the dashboard or the risk registers -MR. BUONAGURO:
The more detailed one.
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DR. GALLOWAY:
That's the project management level, so
2
these are the people that are actually in this instance
3
managing the bundles, the project bundles.
4
looking at the detail of the risks, and they would be the
5
ones looking at whether risks have retired, risks have
6
arisen, they would be working with the risk management
7
organization that has been established for the DRP.
8
would be doing that detail-level process and they would be
9
handling that detail level and then rolling up the level as
10
11
They would be
They
it goes higher up through the organization.
MR. BUONAGURO:
My understanding then from what you
12
just said, that's the level of detail that you require in
13
order to ensure that the company is managing the risks
14
appropriately?
15
DR. GALLOWAY:
16
little bit more --
17
MR. BUONAGURO:
18
DR. GALLOWAY:
19
MR. BUONAGURO:
20
21
Which level?
Again, can you just be a
The more detailed level, before -The more --- it gets transformed into a
dashboard.
DR. GALLOWAY:
So the more detailed level, the risk
22
register and the risk monitoring is laid out quite in some
23
detail in OPG's policies and procedures, along with the
24
different levels within the organization that will be doing
25
different tasks along that line.
26
this case for the program is quite detailed and has the
27
mechanism of retiring risks and putting new risks on and
28
evaluating the cost and schedule impacts of those risks
So the risk register in
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2
through its risk assessment.
And that is what was in place when I -- we did our
3
review and was being implemented when we did our review,
4
and I would assume would continue to be implemented and in
5
use as it was at the time of our review.
6
MR. BUONAGURO:
Thank you.
One last question, and I'm
7
only asking it because there was some cross on this in
8
panel 1B.
9
In terms of the risk register, is the risk register
10
that you actually identified as part of your analysis on
11
the record already?
12
are risk registers on the record, but as we understood it
13
through the cross-examination, they are a point-in-time
14
document; i.e., if you print it today versus you print it
15
four months ago, they will look very different.
16
wondering if the one that you reviewed is actually on the
17
record.
18
DR. GALLOWAY:
19
MR. BUONAGURO:
I ask that because I understand there
So I'm
I have no idea.
Okay.
So the one undertaking I would
20
ask is that the risk register that you actually reviewed
21
would be added to the record.
22
MR. KEIZER:
I believe it already is on the record.
23
MR. BUONAGURO:
24
MR. KEIZER:
25
MR. BUONAGURO:
26
MS. LONG:
27
MR. KEIZER:
28
MR. BUONAGURO:
Thought it might be.
I don't know the exact exhibit number -If it's not -- if it's not --
You'll direct to us that?
Yes.
Perfect.
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2
MS. LONG:
All right.
Can we just mark that just so I
don't lose track, please.
3
MR. RICHLER:
4
UNDERTAKING NO. J6.1:
5
EVIDENCE OF THE RISK REGISTER DR. GALLOWAY REVIEWED.
6
MR. BUONAGURO:
7
MS. LONG:
8
Mr. Poch, we have a hard stop today at noon.
9
MR. POCH:
10
That will be Undertaking J6.1.
TO PROVIDE THE LOCATION IN THE
Thank you, those are my questions.
Thank you, Mr. Buonaguro.
That should be fine, Madam Chair.
If I
don't notice the clock, please interrupt me.
11
MS. LONG:
I will do that, thank you.
12
CROSS-EXAMINATION BY MR. POCH:
13
MR. POCH:
First of all, just a few questions that
14
have arisen from your discussion so far.
15
AP1000 a few times.
16
design?
17
DR. GALLOWAY:
18
MR. POCH:
You've mentioned
I take it that's the Westinghouse
Yes.
And Westinghouse was -- that part of
19
Westinghouse was bought by Toshiba a number of years ago;
20
is that correct?
21
DR. GALLOWAY:
22
MR. POCH:
That is correct.
And I read recently that -- correct me if
23
I'm wrong -- that Toshiba has decided to get out of the
24
nuclear business.
25
DR. GALLOWAY:
26
MR. POCH:
I've read the same thing.
Right.
Secondly, just in terms of your
27
discussion with Mr. Buonaguro a few minutes ago, I just
28
want to make sure I understand -- make sure we're on the
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same page.
2
reasonable at this time, it's going to go into rate base in
3
2020, and that only any variance from that will be
4
examined, would you agree that one possibility is OPG could
5
proceed, come in at 4.8, but have imprudently allowed, say,
6
300 million dollars' worth of costs, yet that was
7
fortuitously offset by 300 million dollars' worth of
8
contingency at the P90 level that didn't materialize and we
9
would never know that?
10
11
If this Board were to agree that 4.8 is
That's a risk with that approach.
Would you agree?
DR. GALLOWAY:
I don't know the circumstances upon
12
which the Board has laid out its review, and further,
13
again, I think as I was given the answer to the example
14
earlier on when something was deemed -- appeared imprudent,
15
that that actually would have to be looked at at the
16
circumstances at the time.
17
MR. POCH:
Of course we can -- I understand your
18
point.
I'm just saying your client in this case, OPG, has
19
proposed the mechanism I've just described to you that it's
20
4.8 absent, you know, fraud or, you know, extreme
21
situations like where there's an allegation of fraud, for
22
example.
23
subsequently get to evaluate prudence of the 4.8.
That's the end of it.
The Board won't
24
Would you agree that if that scenario was adopted by
25
this Board -- and I agree with you we don't know what the
26
Board will decide -- but if it were to be the approach,
27
that there is this risk?
28
DR. GALLOWAY:
You know, that is why the -- in the
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U.S. the jurisdictions have taken the cost of pre-approval
2
of an estimate absent fraud and concealment, and, yes, if a
3
utility comes in within that estimate, that is the pre-
4
approved cost, and that is what the commission will allow.
5
6
7
I don't know what this Board will allow, but that is
the practice in the United States.
MR. POCH:
So in the States a Board in that situation
8
where they've pre-approved something years before, as long
9
as it meets that price they're not going to -- they don't
10
ask whether the eventual sum was a product of imprudence
11
being offset by good fortune or not?
12
content to let it lie; is that --
13
DR. GALLOWAY:
They're just, they're
I think they look at it from the
14
contingency level and building in that things may happen
15
that cannot be predicted at the time of the pre-approval,
16
and as long as again the project comes in within the pre-
17
approval it has been accepted.
18
over -- provided there is not a program where it has to be
19
looked at the overall cost of the program, then those
20
overages are what is being looked at.
21
It is the costs that go
I think, for instance, on Vogtle, if you were to look
22
at the commission's order, that's exactly what the
23
commission order said in Vogtle, that if the cost of the
24
unit came in -- 3 and 4 within the initial certified cost,
25
that any costs up to that would be approved and anything
26
over that would have to come back, which is the exact
27
mechanism they went through when it was increased, and that
28
hearing has just finished a few months ago.
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MR. POCH:
Right.
So that -- I think we're in
2
agreement that that's what goes on, and that one of the --
3
the price we pay for that approach possibly is that there
4
could be imprudence which never sees the light of day,
5
because it's offset by contingencies not materializing.
6
It's entirely possible?
7
DR. GALLOWAY:
With the caveat of that's the cost and
8
the risks that were looked at, that were built into the
9
price and but for fraud and concealment, there is a built
10
11
in risk for that entire cost that's pre-approved.
MR. POCH:
I understand what you're saying.
But I'm
12
concerned about the contingency -- something that wasn't
13
built into the price, that wasn't built into the
14
contingency allowance, wasn't identified as a risk, and was
15
imprudently incurred.
16
DR. GALLOWAY:
I don't know if I can actually answer
17
the question, because the risk mechanism that is looked at
18
covers everything up to a point cost which is asked for the
19
pre-approval.
20
indicated, the fraud and concealment, that total cost would
21
be approved.
22
23
24
MR. POCH:
And again, within the exceptions as I've
Okay.
I think I can leave it there.
I
think the situation is clear.
If you turn up L 4.3, schedule GC 5, we asked you
25
about the history of your involvement in nuclear projects,
26
and your corporation involvement is referred to there.
27
I take there has been some -- I think you refer to some 55
28
nuclear projects that Pegasus-Global has been in some
And
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fashion involved in.
2
DR. GALLOWAY:
3
MR. POCH:
Yes.
If we turn to 4.3, schedule 15, SEC 40,
4
there's a chart attached as attachment 1, and I think you
5
referred to this earlier.
6
7
There's 29 projects there where you personally have
testified or issued a report.
8
DR. GALLOWAY:
9
MR. POCH:
Or been participatory in the analysis.
Right, that involved nuclear.
Of all these
10
projects you're aware of, and the ones you're aware of but
11
weren't personally involved in or corporately involved in,
12
including the ones in Canada, if we were to look at the
13
cost and schedule estimates that is were provided 5 years
14
in advance of the expected in-service date, would you agree
15
that virtually in the nuclear world, the vast majority end
16
up coming in either above cost, delayed in schedule, or
17
both?
18
DR. GALLOWAY:
They have, based on what I had
19
indicated previously, that they did not have the benefit of
20
doing the P90 confidence level and the type of pre-
21
execution planning.
22
estimating basis, there is a high likelihood that several
23
of these would have come in within the budget and schedule.
24
MR. POCH:
Had they been done on a P90 cost
But in fact, there haven't been any nuclear
25
projects done in the way you just described?
This is the
26
brave new world where you're trying to learn from other
27
activity, other areas of activity that probabilistic
28
estimation is helpful, for example?
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DR. GALLOWAY:
Right.
As I had mentioned -- well,
2
Bellafonte is different; it's on here.
3
on a P90 basis.
4
on TBA relative to the decision not to proceed.
5
Bellafonte was done
Other circumstances relative -- economics
But most of these, except for Vogtle 3 and 4 and Levy
6
and of course Darlington, all the other were done before
7
probabilistic modelling was even in effect.
8
no opportunity to do such probabilistic modelling.
9
So there was
So you're only looking at the Levy unit, which we've
10
already talked about and was decided to not to go forward.
11
Bellafonte in the same situation, and Vogtle 3 and 4 is the
12
only other one on this chart, and I believe we've discussed
13
that in the contract risk reviews.
14
units are tracking under the current re-approved estimate.
15
16
17
MR. POCH:
And currently, the
But not near the original estimate when the
project was first approved to go ahead by the regulators?
DR. GALLOWAY:
Again, that was under the understanding
18
by both the commission, the intervenors, and the utility
19
that there would be costs and risks that would arise that,
20
if they did, would go into a re-approved certified
21
estimate.
22
approved.
23
And that's what occurred, and was what has been
MR. POCH:
Now, in terms of your review of OPG's
24
project, we've heard there's thousands of items in the risk
25
registry, for example.
26
I take it -- am I correct in my understanding that it
27
wasn't part of your mandate to go and look at the zirconium
28
tube replacement and decide if they caught all the possible
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technical risks?
2
exercise, you've done your best to identify those risks,
3
you're tracking them, you dealt with them in the contracts,
4
and so on.
5
Your mandate was to say you've done an
Is that fair?
DR. GALLOWAY:
No, I think I indicated before we did
6
some sampling of the risks in the risk register, to follow
7
back the roots of those risks, how they were identified,
8
how they were vetted, how they were put in, how the costs
9
in the schedule risks were determined and how they fit into
10
the model.
11
And then we reviewed detailed other reports by subject
12
matter experts that did do the in-depth deep dive review to
13
see what they reviewed and how they made their findings and
14
opinions, based on the deeper dives of those other risks.
15
MR. POCH:
I understand you've looked at the risks
16
that have been identified, and seen they've been tracked
17
through and included either in the base forecast or
18
contingency, what have you.
19
risks that weren't identified.
20
21
22
I guess I'm talking about
You didn't attempt to, did you, look and see if there
were risks that simply weren't identified at the outset?
DR. GALLOWAY:
That was part of the interviews of the
23
process of how they went about identifying the risks, how
24
many groups or sessions, risk sessions, risk workshops
25
which are typically the way you look at risks.
26
You have different workshops with subject matter
27
experts that identify risks.
You then have vetting of
28
those risks by other subject matter experts, which was
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2
performed here.
So we looked at the process of the risks and how they
3
were identified, and by whom, and by how many types of
4
individual groups.
5
different levels of input in the multitude of subject
6
matter experts, and internally and externally, we thought
7
they had captured reasonably all of the input of all
8
possible risks that could be reasonably identified.
9
10
MR. POCH:
What is your understanding of OPG's mandate
from the government with respect to this project?
11
DR. GALLOWAY:
12
MR. POCH:
13
understand it?
14
15
16
And through that process of the various
What do you mean by their mandate?
What's their marching orders, as you
DR. GALLOWAY:
To refurbish the Darlington four units
so they have another 30 to 35 years of life extension.
MR. POCH:
And OPG has gone about this with the
17
contracts and the allocation of work in-house versus
18
contractors and so on, and you've looked at all that.
19
I can inform you one of the -- part of the mandate was
20
to minimize commercial risk.
21
see if they got other bids with other contractual
22
arrangements where they outsourced more of the risk?
23
DR. GALLOWAY:
Did you go back and look to
We looked at the contracting
24
methodology.
But as I indicated, we were not asked to look
25
at the terms and conditions of how those contracts were
26
actually selected and negotiated.
27
company, I believe.
28
MR. POCH:
That was done by another
So the government wanted -- gave OPG some
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instruction in terms of how it wanted to see risk and cost
2
traded off.
3
responded to that?
4
DR. GALLOWAY:
5
That would be embedded in the terms and
conditions of the contracts, and we did not evaluate that.
6
7
You're not opining on the manner in which OPG
MR. POCH:
Thank you.
Those are all my questions.
Thank you, Madam Chair.
8
MS. LONG:
Thank you, Mr. Poch.
9
Mr. Yauch, do you want to get started?
10
CROSS-EXAMINATION BY MR. YAUCH:
11
MR. YAUCH:
12
DR. GALLOWAY:
13
Sure.
Good afternoon.
Good afternoon.
It's not afternoon
yet.
14
MR. YAUCH:
It feels like it.
15
[Laughter]
16
Start on page 2 of your report.
So I'm going to take
17
you through a couple documents and then I'll ask you a
18
question.
19
DR. GALLOWAY:
20
testimony or --
21
MR. YAUCH:
22
DR. GALLOWAY:
23
MR. YAUCH:
24
DR. GALLOWAY:
Yes, of your testimony.
Or page 2 of my report?
Of your testimony.
25
exhibit number?
26
MR. YAUCH:
27
DR. GALLOWAY:
28
Page 2, meaning page 2 of the filed
I gave the --
But is it the page number or the
Page 7 of 122 or page 2 of -Thank you.
Thank you.
I just want to
make sure I'm on the right page.
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MR. YAUCH:
Okay.
That's fine.
So in it, I'm line
2
12, and you go through this in other parts of your
3
documents, you say OPG was active in issue resolution.
4
I take that in your review of the company you found that
5
OPG found -- encountered problems when it was doing work
6
and took all the necessary steps to solve those problems.
7
Is that a correct way to characterize what you found?
8
DR. GALLOWAY:
9
MR. YAUCH:
10
11
12
13
14
15
16
So
I'm sorry, what --
On line 12.
DR. GALLOWAY:
-- I'm trying to look on page -- on
line 12, and I don't see that statement.
MR. YAUCH:
"And active in issue resolution."
Am I
not seeing it?
DR. GALLOWAY:
Oh, I see.
"And active and issue
resolution"?
MR. YAUCH:
Yeah.
And you expand on it later in page
17
52, but essentially I'm going to characterize what you
18
said.
19
problems as it encountered them when it came to Darlington
20
work?
21
You found that OPG did a good job at solving
DR. GALLOWAY:
I think I've talked in the context of
22
the lessons learned that they took from the refurbishment
23
projects and the other nuclear projects and the other
24
megaprograms and they reasonably applied those lessons
25
learned into the execution -- pre-execution planning for
26
the Darlington program.
27
28
MR. YAUCH:
Okay.
compendium for 1A.
So if you can go to page 39 of my
So this was an audit report.
If you
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scroll down a little bit, it's highlighted.
And the
2
auditor -- this report was done at the same time you did
3
your report, and it said there was a cultural tolerance for
4
acceptance of work --
5
MS. SPOEL:
Exhibit number of that 1A compendium?
6
MR. YAUCH:
I forget the exhibit number.
7
MS. SPOEL:
Oh.
8
MR. YAUCH:
Thank you.
9
10
Oh, I have it.
It's 1.4 -- K1.4.
So this auditor at the same
time found that there was a cultural tolerance for
acceptance of work delays, and it said:
11
"This tolerance for work delays is being enabled
12
by a leadership team."
13
So I was curious what they found compared to what you
14
found, and if you can comment on why you didn't see these
15
sorts of issues that this other auditor found?
16
DR. GALLOWAY:
Well, first, the Refurbishment
17
Construction Review Board and I have been active in review
18
boards as well.
19
be critical, to try to find ways that you can catch
20
potential issues early so that they don't manifest
21
themselves into cost and schedule impacts.
22
this report in that context, having been in their shoes
23
similarly for other programs.
24
The mandate for those review boards is to
And so I take
And when they're talking about work delays from the
25
enabled leadership team, I mean, that's a finding that they
26
have at the time.
27
same context or response to what we were previously talking
28
about in the incorporation of lessons learned from the
I don't think that's the same -- in the
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other programs that were incorporated into the pre-
2
execution planning here.
3
they're looking at and their schedule adherence.
4
This is a point in time that
At this point in time in July the schedule was -- the
5
final schedule was still under development.
6
our review the final integrated schedule was planned to be
7
complete in August and September, and so I believe that
8
they were probably trying to assist them, and from what I
9
can just gather from looking at their report very briefly
10
as to looking at ways as they're doing that work planning
11
to ensure that again the processes and the procedures that
12
they have in place will be emphasized and persons trained
13
on those and that these types of reflections will be picked
14
up before that schedule completion is finished.
15
MR. YAUCH:
At the time of
So you said that the construction review
16
board was a bit more critical than what you were tasked to
17
do.
18
leadership team of OPG to see if they were able to meet the
19
deadlines that they were tasked to meet.
20
difference between the two audit reports?
21
So you weren't tasked to critically look at the
DR. GALLOWAY:
Is that the
Well, again, I'll try to be a little
22
bit more clear.
A construction review board on any program
23
is tasked to come in at a point in time and to look at
24
items at points in time that may be occurring to pick
25
similarly as we are doing as the independent monitor on the
26
Energy Strong program for PSE&G to find, even if they're
27
isolated incidences, to find things that they want to bring
28
to the senior leadership and the program management's
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attention so that the types of things that they are
2
potentially seeing at a point in time can be either
3
corrected or whether the policies and procedures need to be
4
revised so that there is better clarity with who will be
5
following those to minimize these point-in-time
6
observations.
7
The part that -- the analysis and the scope that we
8
were undertaking was that we were looking at the policies
9
and the procedures and the processes and the organization
10
and the structure to ensure that those met industry best
11
practices and were put in such a way that if implemented
12
would allow for successful execution of the program.
13
So there are differences in what the construction
14
review board is being asked to do versus what we on the
15
reasonableness and prudence of the actions taken by OPG.
16
There's different mandates between both of these exercises.
17
MR. YAUCH:
Okay.
Thank you.
If you can go to page
18
41 of that compendium.
Just to follow up on this, just go
19
down, that bullet point under point 3, it says:
20
"Management behaviour when schedule expectations
21
are missed is weak."
22
So as a follow-up of what you said earlier, your group
23
just looked at whether OPG had the process in place and the
24
construction review board looked at whether they were able
25
to meet those processes, correct?
26
between the two?
27
28
DR. GALLOWAY:
in place.
That's the difference
No, we went beyond just whether they're
As I indicated, we then took on interviews of
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project personnel as to their understanding of what those
2
policies and procedures and processes were, their
3
understanding of how they were to be implemented, their
4
current implementation of those policies and procedures,
5
and the reasonableness of their understanding and their
6
implementation of those.
7
These are point-in-time observations of -- which is
8
typical of, again, a construction review board.
To
9
identify I would have to, for instance, look at the
10
specifics that they are talking about.
11
reports would be very similar to our independent monitoring
12
reports, that it doesn't dive down into the detail in the
13
report, but in their discussions with management, they may
14
be talking about a few activities, they may be talking
15
about a particular area, and you would have to look at the
16
specifics behind this bullet to see whether or not that's a
17
programmatic concern or whether it is a particular specific
18
area concern with particular people on particular
19
activities.
20
for me to ascertain what this bullet is referring to.
21
I mean, their
Without that knowledge it would be difficult
MR. YAUCH:
No, but in your report you actually never
22
questioned management's behaviour to meet schedules.
23
didn't find that as a problem.
24
DR. GALLOWAY:
You
No, I believe that we did, especially
25
in respect to the pre-execution projects that were trending
26
over schedule and over budget.
27
the reviews with OPG personnel to understand why, to
28
understand why those potentially had different processes
We specifically went into
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for which they were being managed, the lessons learned from
2
those and how they were being incorporated into the new
3
policies and procedures.
4
So yes, we were looking at where things stood against
5
certain schedules for different projects that were
6
underway, and how OPG was reacting to those particular
7
delays, to some of those pre-execution projects.
8
9
MR. YAUCH:
In regards those pre-execution projects,
in your evidence -- and OPG has sort of maintained this
10
point as well -- that those weren't done how refurbishment
11
is going to be done, so we shouldn't compare the two.
12
the same time, the way in which we did the refurbishment
13
planning was with this statistical model, the Monte Carlo
14
model.
15
At
But in your evidence, you also say that those early
16
projects were essentially guinea pigs for what comes Next,
17
that a lot of groups do these early projects to see how
18
things go.
19
But from the Board's point of view, we can't actually
20
look at whether those are going to be any indication of how
21
the rest are going to go, because they were done
22
differently.
23
they're just a different project, correct?
24
25
26
So in a way, they weren't really guinea pigs;
DR. GALLOWAY:
question.
There's a lot of presumptions in your
But let me try to break that down a little bit.
It is correct that those early projects were not done
27
to the same policies and procedures that were developed for
28
the Darlington refurbishment program.
They were done to
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the projects and modifications, policies, and procedures
2
that had been existing at the time.
3
The same was true for some of the contracting
4
practices.
Those projects -- decisions were made to
5
execute those to have them completed, but there was also
6
lessons learned from that.
7
working in the policies and procedures that needed to be
8
incorporated in the policies and procedures for Darlington
9
to minimize, to be able to ascertain what potential delays
For instance, what was not
10
might be earlier to minimize against this, to look at the
11
lessons learned from the contracting strategies to be able
12
to incorporate that into different contracting strategies
13
for Darlington.
14
So yes, while they were done under different policies
15
and procedures and contracts, how those panned out were
16
lessons that were in fact incorporated in the policies,
17
procedures and contracting models on the Darlington
18
refurbishment program in order to minimize and/or eliminate
19
the issues that arose on the pre-execution projects.
20
21
MR. YAUCH:
break now?
22
MS. LONG:
23
MR. YAUCH:
24
MS. LONG:
25
Do you want me to keep on going, or take a
Is this a convenient time?
Yes, I can stop now.
Thank you very much.
We are going to break
and be back at 1:05, please.
26
--- Luncheon recess taken at 11:59 p.m.
27
--- On resuming at 1:11 p.m.
28
MS. LONG:
Mr. Keizer.
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PRELIMINARY MATTERS:
2
MR. KEIZER:
Madam Chair, just one preliminary matter,
3
and that is related to the undertaking given this morning,
4
6.1, and the location of the risk register that was
5
reviewed by Pegasus is at issue 4.3, Staff 73, attachment
6
7, pages 21 to 235.
7
MS. LONG:
8
MR. KEIZER:
9
MS. LONG:
Thank you very much for that.
Thank you.
Mr. Yauch, are you ready to proceed?
10
CROSS-EXAMINATION BY MR. YAUCH:
11
MR. YAUCH:
12
MS. LONG:
13
MR. YAUCH:
Good afternoon.
I think it's afternoon --
Good afternoon.
-- now.
I just have two areas left to
14
explore.
15
Monte Carlo model.
16
to you about this, and it's been the centre of a lot of
17
discussion.
18
So the first one is the -- it's the idea of the
And I know a lot of people have talked
As far as I can tell, this is the only nuclear project
19
that's ever been built that has used this type of model to
20
estimate the cost and the contingency involved with it,
21
correct?
22
DR. GALLOWAY:
To my knowledge that would be correct.
23
I haven't analyzed the nuclear plants in Europe to know
24
whether or not that is the case.
25
MR. YAUCH:
So during this application, these five
26
years, Unit 2 will be completed, so at the end of this,
27
this will be the first time, or maybe midway through, that
28
this Board and the public in Ontario and the public
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worldwide will see whether a Monte Carlo model can actually
2
tackle the nuclear industry and control costs, whereas in
3
the past we weren't able to control the costs in the
4
industry, correct?
5
will actually play out when it comes to a nuclear project.
6
DR. GALLOWAY:
This is our first live look at how this
Relative, if you want to take nuclear,
7
correct, but there are other megaprograms with the same
8
magnitude and complexity that are underway under this
9
probabilistic model.
10
MR. YAUCH:
So you don't think the nuclear industry is
11
a statistical outlier when it comes to infrastructure
12
projects and it falls in the complexity of other groups.
13
14
DR. GALLOWAY:
I think the Crossrails project is even
more complex than the Darlington refurbishment program.
15
MR. YAUCH:
Okay.
So I just have one last area.
If
16
you can go to page 5 of your testimony, or page 10 of 122,
17
depending on how you see it.
18
metrics, and from what I gather you looked at all the
19
metrics that OPG had laid out in this application and you
20
said, yes, these meet industry standard?
21
DR. GALLOWAY:
22
MR. YAUCH:
So at the top you talk about
Yes.
And OPG didn't go above and beyond, or is
23
it -- it just stayed within line of what you'd expect for
24
the number of metrics on a project of this complexity?
25
DR. GALLOWAY:
I think that I've laid out how they
26
will be addressing those metrics is certainly commendable
27
and in some aspects was maybe more than you would expect to
28
see.
I think given the complexity of the program that was
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appropriate.
2
conform with what is identified in the industry best
3
practices and they are following along the lines of
4
industry best practices.
5
But the metrics that they have in place do
MR. YAUCH:
Okay.
So if you can go to Energy Probe
6
compendium 1A and page 38.
This is again from the
7
construction review board.
I'll wait for them to bring it
8
up.
9
And right under recommendation number 3 they say:
10
"While the project ask have a large number of
11
metrics, they do not consistently provide an
12
accurate, integrated picture of project health."
13
So the review board seemed to find, yeah, the metrics
14
were there, but OPG didn't actually -- the metrics weren't
15
providing OPG or the public at this point an accurate
16
picture of what was actually happening.
17
as well?
18
DR. GALLOWAY:
Did you find that
Again, being a point in time that this
19
was taken, I believe, for instance, when I talked about
20
schedule, that the schedule, which is a metric, the
21
schedule was underway, being completed, and the integrated
22
schedule was not planned to be done until August or
23
September, so relative to those scheduled metrics they
24
would not be the integrated picture in July of 2016, which
25
is something that they were working on.
26
So whether or not the construction review board saw
27
that at the point in time and made a recommendation, I
28
again don't know the underlying reason of this, but we did
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find that the schedule, by not being yet complete, but
2
being completed, you wouldn't have the ability to do an
3
integrated view of July of 2016 on those metrics because
4
the integrated schedule had not yet fully been completed
5
and was planned to be so in August and September.
6
MR. YAUCH:
Now, did your group take a metric -- a
7
sample of metrics and then dive deep in them and see if the
8
actual health or schedule or cost of the project actually
9
aligned with the metric?
Did you take a deep look at each
10
one and see if what they were telling the company was
11
actually true?
12
DR. GALLOWAY:
Yes, as I had indicated, we did some
13
sampling, and so relative to, for instance, you know,
14
progress, we would ask to see how they were measuring that
15
at the time that they were reporting in light of the
16
schedules at the time.
17
see the process and the numbers and how they were producing
18
those metrics to understand that that was not only
19
following the processes in the procedures, but that
20
actually it was reflecting a metric that was reflective of
21
the information that it had at the time.
22
MR. YAUCH:
The same for cost.
We wanted to
Did you find overall the metrics were
23
correct, that what they were saying was actually happening,
24
or unlike the review board, which found that wasn't
25
actually happening?
26
DR. GALLOWAY:
Well, again, the review board is a
27
point in time, and when it says "integrated", as I
28
indicated, since the schedule was not yet complete, you
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2
wouldn't have an integrated picture of those metrics.
So without knowing what they were particularly talking
3
about, I would not be able to comment whether our findings
4
are different or they are of the same finding.
5
MR. YAUCH:
Those are my questions.
6
you very much.
7
MS. LONG:
8
CROSS-EXAMINATION BY MR. TOLMIE:
9
MR. TOLMIE:
Thank you.
Thank you.
Mr. Tolmie.
Thank you, Madam Chair.
10
Tolmie, Sustainability Journal.
11
very brief point that I would like to make.
12
13
MS. LONG:
a compendium here, 1C.
And I have -- this is a
Is this something that --
MR. TOLMIE:
15
MS. LONG:
16
MR. TOLMIE:
17
MS. LONG:
18
MR. RICHLER:
19
EXHIBIT NO. K6.2:
20
TOLMIE FOR OPG PANEL 1C.
21
MS. LONG:
23
My name is Ron
Mr. Tolmie, just before you proceed, I have
14
22
Thank
That's correct.
-- are you planning to file that?
Yes.
Yes?
Okay.
Can we mark that, please?
Madam Chair, that will be Exhibit K6.2.
CROSS-EXAMINATION COMPENDIUM OF MR.
And Dr. Galloway, do you have a copy of
that?
DR. GALLOWAY:
You know, I thought I did, and for some
24
reason it must be the only piece of paper I did not bring
25
with me, and I do apologize.
26
MS. LONG:
All right.
27
DR. GALLOWAY:
28
MS. LONG:
Let's just make sure --
Thank you.
-- everyone has a copy.
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MR. TOLMIE:
This morning in your testimony you made
2
the comment that more planning can give rise to better
3
outcomes in megaprojects.
4
said?
5
DR. GALLOWAY:
6
reliable results, yes.
7
MR. TOLMIE:
Is that more or less what you
Well, more planning does give more
Okay.
So do you think that adequate
8
planning has been applied in this particular case to
9
anticipate the results?
10
DR. GALLOWAY:
We have certainly opined that the
11
approaches and the extensiveness of the pre-execution
12
planning positions OPG favourable for a successful
13
execution of the program.
14
MR. TOLMIE:
Okay.
I don't know if you noticed, but
15
in Ontario the base load generation capacity actually
16
exceeds the average consumption of electricity.
17
aware of that, or can you provide any...
18
19
20
DR. GALLOWAY:
Are you
Not within my scope, sir, so I wouldn't
know the answer to that.
MR. TOLMIE:
Okay.
The numbers are not hard to find.
21
You can look at the daily reports from IESO or many other
22
reports and they will show you the base load generation
23
capacity, which is the nuclear capacity plus hydro,
24
basically, and they show that our demand is in fact quite
25
stable year after year.
26
demand in terawatt-hours by the number of hours, you'll
27
come up with an average value for the power demand, and the
28
generation capacity actually exceeds the power demand.
If you divide the total annual
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Does that imply that we could relieve all or some of
2
the problems by simply adding storage -- electricity
3
storage to the system?
4
DR. GALLOWAY:
Since it wasn't in my scope of review I
5
don't think that it would be appropriate for me to comment,
6
because I haven't reviewed any of the facts surrounding
7
that.
8
9
10
MR. TOLMIE:
Why was this an issue that wasn't covered
in the application itself, do you think?
DR. GALLOWAY:
11
comment on that.
12
MR. TOLMIE:
I don't know.
I wouldn't be able to
The -- if there's storage available in
13
Canada if one intended to apply storage as a means of
14
matching supply and demand.
15
16
17
DR. GALLOWAY:
Again, it wasn't in my scope, so I
would be unable to comment.
MR. TOLMIE:
So it's a planning problem that wasn't
18
included in OPG's application itself.
19
that is potentially significant that was not mentioned in
20
the application, is that correct?
21
MR. KEIZER:
That is an issue
Madam Chair, the witness is here to
22
respond to her report, the Pegasus report which relates to
23
the policies, procedures, and risk aspects and other things
24
related to the Darlington refurbishment plan.
25
She has not been here to tender a report related to
26
storage, or to what is or is not in the application that
27
OPG has filed.
28
MS. LONG:
That's true, Mr. Tolmie.
Do you have any
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questions of Dr. Galloway with respect to the report that
2
she filed?
3
MR. TOLMIE:
My question is about the report.
It
4
should cover all the issues that are significant.
5
report should cover whatever OPG is doing, and OPG should
6
report all the major --
7
MS. LONG:
Her
If you have an issue with what OPG -- the
8
scope that OPG gave to Dr. Galloway, that's an issue for
9
OPG.
10
That's not an issue for Dr. Galloway.
She can only speak to the scope of work that she was
11
asked to complete, and her report that she's filed in
12
evidence.
13
to do so, about the report she filed.
14
So you need to ask her questions, if you choose
I see some in your compendium that look like they're
15
related to the report, and those questions you can ask Dr.
16
Galloway.
17
outside of what she was asked to opine on.
But beyond that, she can't speak to things
18
MR. TOLMIE:
19
comments on the plan.
20
MS. LONG:
She was asked, in my view, to provide
And the plan should cover --
She was asked to give her opinion on the
21
plan that was provided to her, not to coach OPG on what
22
should be in the plan, or opine on what should be in the
23
plan.
24
beginning of her evidence.
25
Her scope of work is clearly outlined in the
So if you have an issue of OPG's scoping of her work,
26
that's something you can deal with with OPG through
27
argument, not through Dr. Galloway.
28
MR. TOLMIE:
We're dealing with a missing element,
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whether it's missing in the OPG plan or in Dr. Galloway's
2
review of that plan, I guess, is something that can be
3
debated.
4
But it's a major missing element.
5
MS. LONG:
What she's here to give expert evidence to
6
this panel on is what she was asked to review.
7
this panel can benefit from hearing from her on.
8
to rephrase your questions.
9
10
11
12
13
14
15
MR. TOLMIE:
That's what
The objective of the Board hearing is to
determine if the rates are appropriate; is that correct?
MS. LONG:
I'm very clear on what our objective is, so
you don't need to coach me on that, Mr. Tolmie.
MR. TOLMIE:
Is it in fact a Board concern that one
should look at things that relate directly to rates?
MS. LONG:
Mr. Tolmie, I'm not going to engage in this
16
argument.
17
there are panels you can ask these questions of.
18
Galloway is here to strictly speak to her report.
19
20
21
22
We've talked about your views on storage, and
going to move to another intervenor that does.
MR. TOLMIE:
question then.
I'll ask this one straightforward
Do you know who wrote the report?
DR. GALLOWAY:
24
MR. TOLMIE:
26
27
28
But Dr.
So if you don't have questions about her report, we're
23
25
You need
My report?
No, the OPG report that you were
considering.
DR. GALLOWAY:
I'm not for sure I understand the
question of the report that you're referring to.
MR. TOLMIE:
The application.
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DR. GALLOWAY:
2
MR. KEIZER:
Well -The application is actually thousands of
3
pages of documents, covering a wide variety of panels and
4
issues.
5
application from any number of contributors from OPG, of
6
which some of those and most of those are probably
7
witnesses in this proceeding.
8
9
So there would be any number -- it's an OPG
MR. TOLMIE:
Just to explain why I'm asking, there are
several different agencies involved in Canada in making
10
decisions and plans and acting those programs, and it's not
11
clear to us as to who is pulling the strings.
12
does the IESO, or OPG, or the Minister of Energy make these
13
plans.
14
You know,
So it would be extremely useful to know how the plan
15
itself is generated -- not in a negative sense.
16
want to know, so that we can contribute appropriately.
17
18
MS. LONG:
I just so
Do you mean the application that OPG has
filed?
19
MR. TOLMIE:
Yes.
20
MR. KEIZER:
The application extends beyond the
21
Darlington refurbishment program, which is what the past
22
few days have been about, and that Dr. Galloway is here to
23
address.
24
application, it's probably better placed with panel 2,
25
which deals with the regulatory constructs of the
26
application, not Dr. Galloway.
So I think if you have questions about the
27
MR. TOLMIE:
28
MS. LONG:
I'll go on to panel 2 then.
Thank you.
Thank you, Mr. Tolmie.
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MR. KEIZER:
Sorry, Madam Chair.
Can I note
2
something?
3
compendium, Exhibit 6.2.
4
series of questions and answers and also cites where -- and
5
I want to be clear that although we've marked it as an
6
exhibit, that those questions and those answers may or may
7
not be, depending upon where he has taken the information
8
from, that they are not OPG's questions and answers.
9
10
We marked as an exhibit Mr. Tolmie's
MS. LONG:
And on his exhibit, he has a
That is well understood.
you for clarifying that.
Thank you.
Mr. Richler?
11
CROSS-EXAMINATION BY MR. RICHLER:
12
MR. RICHLER:
13
Good afternoon, Dr. Galloway.
Thank you, Madam Chair.
My name is Ian Richler
14
and I'm with OEB Staff.
15
already been asked and answered, so I will be brief.
16
Thank
Some of the questions I had have
Yesterday, you provided a helpful summary of the
17
similarities and differences between your report and the
18
report prepared by Staff's expert, Ken Roberts of Schiff
19
Hardin.
20
Just to clarify, would you agree with Schiff Hardin's
21
central thesis that good planning does not ensure similar
22
execution?
23
DR. GALLOWAY:
You certainly have to implement and
24
execute according to the plans, so it may or may not,
25
depending on how that is executed.
26
MR. RICHLER:
Have you seen megaprojects that were
27
exemplary in the project definition phase, but faltered in
28
the execution phase?
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DR. GALLOWAY:
I think generally, again in the reviews
2
that we have done, we may have found elements within the
3
execution plan that were not executed.
4
areas, for instance, that I was talking about on Duke of
5
areas of disallowance.
6
These would be the
But I think as a general statement, it would be unfair
7
to make that general statement.
8
potentially may be areas that would have to be looked at
9
under the circumstances and at the time.
10
MR. RICHLER:
How about the Kemper and Vogtle projects
11
you discussed this morning?
12
planning?
13
I think that there
DR. GALLOWAY:
Did they have world class
The Vogtle project, yes, the same types
14
of findings for their CPCN filing was very similar to the
15
findings here.
16
just a few months ago the commission's order found the
17
program is continuing to execute reasonably and prudently
18
according to those plans.
19
along based on those exemplary pre-execution planning and
20
policies and procedures.
21
And the program, as I also indicated, as of
And so, that one is following
The Kemper, up until the period March 31st, 2013, yes,
22
based on the conditions and the extent of the knowledge at
23
the time of the CPCN, which was much less than even that of
24
Vogtle, significantly less.
25
findings, are deemed reasonable and prudent.
26
think I testified earlier, that prudence review is still
27
ongoing and the testimony will be filed later this year,
28
and the hearing will be later this year.
Those, in the preliminary
But as I
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MR. RICHLER:
I understood you to say yesterday that
2
sometimes you are engaged to assist with project audits.
3
When you were assessing a project that has experienced
4
problems -- in other words, when you are doing what Mr.
5
Buonaguro characterized this morning as an ex post facto
6
prudence review -- what role if any does the risk register
7
play in your assessment?
8
DR. GALLOWAY:
So if you are looking at the project
9
after it has been completed, then you would be looking at
10
how management reviewed the risks and how they dealt with
11
risks.
12
you would look at the risk register, how the risks were
13
identified, how they were put on the risk register, and how
14
they were modelled from cost and time, and you would look
15
at that process and determine whether it was reasonable.
16
For instance, you would look at, similarly here,
As the project moved forward, as it is often common,
17
there will be risks that were not identified originally
18
that may arise, and now you're looking at, you know, when
19
they get on to the risk register, because that's the way
20
risks happen, and that's why you have risk register.
21
Sometimes risks go off when they retire and you have new
22
risks that come on that weren't identified in the
23
beginning, and so you then look at how long the process of
24
looking at management at the time, how they dealt with the
25
new risks that came on, how did it model out, as far as
26
cost and time impact, was it a risk -- I think I gave them
27
those green, yellow, and red indicators of the type of
28
impact that's done on a probabilistic basis based on
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consequence and probability of happening.
2
turn red are the ones that you would then develop a
3
mitigation plan for, and then you would determine whether
4
or not if that risk then occurred on the project then
5
whether they executed according to that mitigation plan.
6
The ones that
So that is the way the risk management process works,
7
and that's what, if you looked at the end of the project,
8
you would take every point in time where the risks were
9
reviewed and how they were retired or how new risks when
10
they came on came on, and then how they were modelled,
11
reviewed, and whether plans were necessary to be prepared,
12
and whether or not if the risk manifested itself whether
13
they executed according to those mitigation plans.
14
MR. RICHLER:
Thank you, that's helpful.
15
Could you perhaps give us one example of a review
16
where -- a risk -- looking backwards that a risk register
17
helped you in your assessment of a project that had
18
experienced difficulties?
19
DR. GALLOWAY:
Yes, I think Duke is a good example,
20
because Duke had some first-of-a-kind risks relative to its
21
technology.
22
in place for that particular IGCC plant, while it had been
23
on a pilot basis, they knew some of the risks, but of
24
course when you scale it up to a larger scale you may not
25
know all of the risks.
26
And obviously, since the technology that was
And so in our review we found a technology risk that
27
had not been identified earlier that arose during the
28
detailed design that was underway at the project.
We
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looked at how it was then added to the risk register when
2
it was identified, because that was important for us to
3
determine when a risk arises how does it quickly get looked
4
at as far as its potential consequence.
5
So in the design the risk was identified.
Then the
6
risk during the process actually did not manifest to the
7
extent they thought it would, but because there was a high
8
consequence a mitigation plan was written for that
9
particular technical risk.
10
So during the beginning of startup -- and remember
11
that I think I mentioned the prudence review was happening
12
during the startup and testing phase -- the risk was not as
13
consequential as it had been modelled for, but because they
14
did have the mitigation plan, startup was able to look at
15
that technical risk and execute according to the mitigation
16
plan so outlined and mitigated the impact that it was
17
deemed to potentially have.
18
impact to be less than it was modelled out to be.
19
MR. RICHLER:
The mitigation allowed that
Could you turn to page 76 of 122 of your
20
report, please.
Again, for the record, this is Exhibit D2-
21
2-11, attachment 3.
22
question:
At the top of page 76 you address the
23
"In your opinion, does the fact that the
24
facilities and infrastructure projects and safety
25
improvement opportunities were not executed per
26
the cost and schedule plan foreshadow similar
27
issues in the execution of the DRP?"
28
And your answer is no.
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Following up on the discussion you had with Mr. Yauch
2
just before lunch, I'm wondering, when you were conducting
3
your review and interviewing OPG folks, did you look into
4
what went wrong with those pre-execution projects?
5
DR. GALLOWAY:
We explored the reasons why schedule
6
and/or costs were over on the projects, and that is what I
7
believe I was explaining earlier relative to some of the
8
contractual issues at the time, that maybe the risk
9
allocation was not as robust as it could have been, and the
10
strategies, and they took those lessons learned to apply
11
them to the contracts in the DRP project.
12
Relative to schedule I think I had mentioned that the
13
policies and procedures and processes and project control
14
tools that were in place in the projects and modifications
15
group from which these projects were executed may not have
16
allowed earlier detection of some of the issues that arose,
17
and so corrections and revisions were made in the policies
18
and procedures and processes for the Darlington
19
refurbishment program that would allow earlier detection of
20
issues and more intense monitoring from the OPG staff to
21
minimize and/or eliminate some of those issues that
22
happened in the pre-execution projects.
23
24
25
So those are the types of reviews that we did on those
overruns on cost and schedule.
MR. RICHLER:
So I just want to make sure I
26
understand.
27
problems that materialized on those pre-execution projects?
28
What in your view was the root cause of the
DR. GALLOWAY:
I think it's what I've just indicated,
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is that the policies, procedures, and project control tools
2
may not have been as robust as they are now to have early
3
detection to be able to mitigate and/or recover the
4
schedule delays and/or to mitigate issues with cost to
5
allow the correction to minimize those costs or find
6
opportunities for those risks on cost to be shared
7
differently than they were on these early projects.
8
MR. RICHLER:
Was it a problem of planning or
9
execution or both?
10
DR. GALLOWAY:
Well, if your policies and procedures
11
and processes are not robust enough to pick up some things,
12
if you execute according to those, you may not pick up on
13
the early detection.
14
is to ensure that the policies and procedures and processes
15
and project controls would be robust enough for early
16
detection and allowing for mitigation and correction.
17
mean, that was the lesson learned.
18
MR. RICHLER:
I think that was the lessons learned,
I
And I think you just mentioned that you
19
considered OPG's contracting approach in respect of these
20
pre-execution projects.
21
specifically with OPG's decision to undertake those pre-
22
execution projects under its existing extended services
23
master service agreements, as opposed to developing a
24
tailor-made contract for those projects?
25
in your view, was it reasonable to rely on those standard
26
pre-existing contracts or, in light of the magnitude of
27
some of those projects, would it have made more sense to
28
develop tailor-made contracts?
Did you have any concerns
In other words,
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DR. GALLOWAY:
Well, our scope did not cover the
2
contracts that were developed for those early execution
3
projects.
4
from the issues that occurred relative to cost and
5
schedule, and how those were mitigated with the processes,
6
the policies, procedures, and the contracting methodology
7
for DRP.
8
9
10
Rather, our scope was, what lessons were learned
MR. RICHLER:
So just to be clear, you have no opinion
on the way the contracts for those pre-execution projects
were structured?
11
DR. GALLOWAY:
12
MR. RICHLER:
13
That was not within our scope.
All right.
Those are all my
questions.
14
MS. LONG:
15
questions for you.
Thank you, Mr. Richler.
16
QUESTIONS BY THE BOARD:
17
MS. FRY:
18
Thank you.
The Panel has some
I have just a couple of questions to follow-
up on your earlier testimony.
19
So at one point you were discussing the Darlington
20
project metrics, and you said in that some aspects, the
21
metrics were more than you would expect to see.
22
23
24
Can you explain which metrics you were talking about
that exceeded expectations?
DR. GALLOWAY:
I think in, for instance, the way that
25
they're looking at earned value, they're more granular than
26
I have seen other utilities look at relative to the detail
27
of the level of progress, the level of the actual budgets
28
and costs that they are looking at in capturing.
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Some utilities roll those numbers up and do it at a
2
more macro level.
3
much more lower level within the system and the program of
4
those metrics which, in our view allows for earlier
5
detection of issues that go to cost and schedule.
6
7
MS. FRY:
Was that the main example, or were there
other metrics that exceeded expectations?
8
9
Darlington seems to be doing it at a
DR. GALLOWAY:
That was one example I remember.
The
others pretty much follow the industry best practices in
10
standards.
11
can't tell you if some of the others were exemplary above
12
what I would expect.
13
think, is much more granular and robust here than I have
14
seen on other programs.
15
Without going back to my specific review, I
MS. FRY:
Okay.
But the earned value clearly, I
You've said a few types that you've
16
noted that lessons learned were incorporated into the
17
Darlington planning, and one example you just gave was
18
early detection.
19
the lesson learned was, and how it was incorporated into
20
the Darlington planning?
21
Are there other specific examples of what
DR. GALLOWAY:
I think the entire depth of, for
22
instance, design completion.
23
lessons learned from megaprograms in general that you
24
typically, whether it's the ability of having the luxury or
25
just the decision not to go that far, that you seldom see
26
completion of design to what we have at Darlington, what we
27
saw.
28
I think that was a big
So that was a huge lessons learned.
I think there were some lessons learned from some of
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the refurbishment projects.
I don't have the detail off of
2
my head, but we went through the various tables of lessons
3
learned that they captured from the prior refurbishment
4
projects and went through them specifically with them at
5
the time to see how they incorporated those specifics,
6
whether they were technical lessons learned, or whether
7
they were contractual, or later we looked through that to
8
see how they then incorporated that either into their
9
probabilistic modelling, their risk reviews to give it a
10
higher or lower list -- I mean a higher or lower
11
probability of that risk manifesting and its calculation.
12
I think we, also in those lessons learned, did look at
13
what they were learning on the other nuclear projects, for
14
instance Vogtle, SCANA, Bellafonte; Watts Bar is also
15
mentioned relative to lessons learned on both allocation of
16
risk -- I think I mentioned before the contract and how
17
much risk you actually turn over to your EPC contractor
18
versus the decision to take some of those risks and manage
19
them yourself because you think you're in a better position
20
to do that.
21
I think again the pre-execution planning for the other
22
nuclear plants was much less than here, and I think that
23
was a lessons learned that they took.
24
So there was, I think, numerous examples of those
25
risks, and what we did is we wanted to go through each of
26
those lessons learn and see how they applied it.
27
went into various categories; it wasn't just a cost.
28
lessons learned went into how they looked at those risks,
And it
Those
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how they might change the project control tools to have
2
earlier detections, as I just indicated, relative to the
3
earned value system.
4
They may have looked at how they want to handle some
5
of those technical issues so they wouldn't have the same
6
problem in Darlington they may have had in other
7
refurbishment projects.
8
9
So that's the level we went through on those lessons
learned.
10
MS. FRY:
11
MS. LONG:
Thank you.
Dr. Galloway, I just have two questions for
12
you.
If you can turn to page 52 of your report, around
13
line 16, your answer here:
14
"Based on my review and the interviews conducted,
15
it is my understanding that OPG benchmarked
16
against the available cost data from other
17
refurbishment projects at Point Lepreau,
18
Pickering, and Bruce units 1 and 2, incorporating
19
lessons learned from these projects into the DRP
20
estimate."
21
And then you go on to say because it was the first of
22
a kind nature of the program that you understand that much
23
of the benchmarking was based on their own operating
24
experience.
25
And I guess I wasn't clear on the first part of your
26
answer where you say "based on my review".
27
exactly that you reviewed with respect to benchmarking?
28
DR. GALLOWAY:
What is it
Again, how it's mostly in the lessons
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2
3
learned that I just discussed.
MS. LONG:
So you didn't actually look at any
benchmarking cost data from any of these other projects?
4
DR. GALLOWAY:
5
MS. LONG:
No.
Thank you.
My final question: you spoke a
6
bit this morning -- I was very interested when you spoke
7
about the energy strong program, and how your role is
8
basically as an independent monitor.
9
10
DR. GALLOWAY:
MS. LONG:
Yes.
I wonder if you can expand upon how it is
11
you came to be in that role.
12
commission asked you to take on, or was that something that
13
the utility proposed, that you become involved?
14
that you became involved in that mandate?
15
DR. GALLOWAY:
Was that something that the
How was it
So the original energy strong program
16
that was proposed by the utility was probably 2 to 3 types
17
the size that it is now.
18
at the time of trying to do too much at once, and so the
19
commission, through a settlement of what actually the scope
20
of work that would be for the energy strong program, the
21
commission determined that it wanted an independent monitor
22
that the utility would pay for, of course, hopefully
23
potentially recovering that through its rates at some point
24
in the future.
25
The commission expressed concern
But the commission is the one that determined that
26
they wanted the independent monitor, and that independent
27
monitor would report to both the commission rate counsel
28
and also to the utility.
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MS. LONG:
Okay.
And then as I understand it, you do
2
quarterly reports and an annual report.
3
extent that you've noticed anything in those reports that
4
needs improvement, how is it that -- well, I guess those
5
reports are made public.
6
to make the corrections based on what your recommendations
7
are, and has that been the common practice that those
8
things have been undertaken?
9
DR. GALLOWAY:
Yes.
And I guess to the
And is it up to the utility then
The procedure that was
10
established, the protocol that was established is that we
11
will -- it's continuous monitoring.
12
attending the weekly meetings, we are reviewing all
13
reports.
14
So for instance, we're
Any decision that is going to be made by the utility
15
is discussed with the monitor before the decision is
16
finally implemented.
17
of the commission in order to allow the utility to look at
18
its options and potentially make different tweaks of that
19
method at the decision, you might say, or the outcome.
20
We have found that the utility has been very
This is something that -- a request
21
cooperative.
22
Recommendations, but where the recommendations have not
23
been taken, the utility provides its response to the
24
commission on why it has not taken that recommendation.
25
The utility, on the other hand, has taken a lot of the
26
recommendations.
27
28
The utility has not taken all of the
And as I believe I stated either today or yesterday -I can't remember now which one -- I think that all the
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parties believe that the process has been beneficial in
2
that the program, which is probably about 80 percent done
3
at this time, is tracking below budget and under schedule.
4
So everyone seems to be very pleased with the process.
5
MS. LONG:
Thank you.
Mr. Keizer, any redirect?
6
MR. KEIZER:
7
MS. LONG:
8
RE-EXAMINATION BY MR. KEIZER:
9
MR. KEIZER:
If I can just have one moment?
Sure.
I have a couple questions in redirect and
10
one relates to, I believe, your discussion this morning
11
with Mr. Poch where there were some discussions about
12
unanticipated risk, and I guess it's a clarification with
13
respect to it, is that if a risk occurs that -- on a
14
project that's not anticipated, does that necessarily
15
equate to imprudence?
16
DR. GALLOWAY:
No, that's exactly what I was referring
17
to, I believe, under the other question, that all projects
18
will have risks that get retired and will have risks that
19
arise during a project, and that is just the way projects
20
happen, so, no, there would be no indication of imprudence
21
just because a risk arose.
22
MR. KEIZER:
The other question, actually, follow on
23
from Madam Chair's questions, and that is, on the Energy
24
Strong work that you do, the report that you prepare -- and
25
I just wanted to clarify -- is that a public report or a
26
private report?
27
the Board or is it something that's published and put on
28
the website?
Is it private as between the utility and
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DR. GALLOWAY:
My understanding is that it is between
2
the commission and the utility and rate council.
3
believe that it is a document that is made public on the
4
website of either of those -- any of those parties.
5
6
7
MR. KEIZER:
I do not
And would it eventually be used in a
public endeavour, or not at all?
DR. GALLOWAY:
I believe the understanding is that if
8
a prudence hearing is held at the end of the project that
9
potentially the reports may be made available.
I don't
10
think the commission and the rate council and the utility
11
have come to an agreement on that yet.
12
there is a disagreement.
13
decided as to -- yet as to how those reports potentially
14
might be used at some point in the future.
And I don't mean
I just don't -- the three haven't
15
MR. KEIZER:
16
Those are my questions, Madam Chair.
17
MS. LONG:
18
Thank you very much for your testimony, Dr. Galloway.
19
If I can just have one moment.
Thank you, Mr. Keizer.
You are excused.
20
DR. GALLOWAY:
21
MS. LONG:
22
23
24
Mr. Keizer, I understand your next panel is
ready to go?
MR. KEIZER:
Yes, and I -- Mr. Smith, Crawford Smith,
is going to take that panel through its paces.
25
MS. LONG:
26
MR. KEIZER:
27
MS. LONG:
28
Thank you.
Okay.
You'll be back on Thursday then?
I'll be back on Thursday.
I think we'll take five minutes here just
to change the deck chairs and get the next panel up.
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MR. KEIZER:
Thank you.
2
--- Recess taken at 1:54 p.m.
3
--- On resuming at 2:00 p.m.
4
MS. LONG:
5
MR. SMITH:
Mr. Smith?
Madam Chair, good afternoon.
We have
6
OPG's panel 2A(i), which is the application overview,
7
nuclear rate setting framework, and business planning
8
panel.
9
10
I'll introduce them briefly.
We have Mr. John Mauti furthest from me, Mr. Chris
Fralick, and Randy Pugh, and I'd ask they be affirmed.
11
ONTARIO POWER GENERATION - PANEL 2A(I)
12
John Mauti,
13
Chris Fralick,
14
Randy Pugh, Affirmed
15
EXAMINATION-IN-CHIEF BY MR. SMITH:
16
MR. SMITH:
Very briefly, members of the Board, let me
17
start with you, Mr. Fralick.
18
vice-president of regulatory affairs of OPG.
19
MR. FRALICK:
20
MR. SMITH:
21
last year?
MR. FRALICK:
23
MR. SMITH:
increasing responsibility since approximately 2000?
MR. FRALICK:
26
MR. SMITH:
28
I did.
And you have been with OPG in positions of
25
27
I am.
And that is a position you assumed early
22
24
I understand you are the
That's correct.
Including responsibility as regional plant
manager for northwest operations?
MR. FRALICK:
Yes.
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MR. SMITH:
I understand that you have an MBA in
2
business from Wilfred Laurier University, and an
3
engineering degree from the University of Waterloo.
4
MR. FRALICK:
5
MR. SMITH:
6
Yes.
Mr. Mauti, I understand you are the vice-
president, chief controller, and accounting officer of OPG.
7
MR. MAUTI:
I am.
8
MR. SMITH:
In that position, you provide overall
9
corporate controllership services.
10
MR. MAUTI:
Yes, I do.
11
MR. SMITH:
You have been with OPG or its predecessor
12
since approximately 1991?
13
MR. MAUTI:
That's true.
14
MR. SMITH:
And you have had business planning or
15
controllership responsibilities since roughly 2012?
16
MR. MAUTI:
That's true, yes.
17
MR. SMITH:
And you have a business degree from
18
Wilfred Laurier university?
19
MR. MAUTI:
Yes.
20
MR. SMITH:
And you are a CPA?
21
MR. MAUTI:
Yes.
22
MR. SMITH:
Finally, Mr. Pugh.
I understand you're
23
the Director of regulatory affairs, regulatory accounting
24
and finance?
25
MR. PUGH:
26
MR. SMITH:
27
MR. PUGH:
28
MR. SMITH:
I am.
You have been with OPG since 2004?
Correct.
Prior to that, you were employed by this
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Board and before that, by Union Gas Limited?
2
MR. PUGH:
I was.
3
MR. SMITH:
4
MR. PUGH:
5
MR. SMITH:
I understand, sir, you are also a CPA.
I am.
Mr. Fralick, maybe I can turn to you.
On
6
behalf of the panel, do you adopt the evidence assigned to
7
panel 2A(i) as detailed in Exhibit A1, tab 9, schedule 1?
8
MR. FRALICK:
9
MR. SMITH:
10
11
12
I do.
Thank you.
I have no further examination-
in-chief, and tender them for cross-examination.
MS. LONG:
Mr. Stephenson, are you ready to commence
your cross-examination?
13
CROSS-EXAMINATION BY MR. STEPHENSON:
14
MR. STEPHENSON:
I am.
Good afternoon, panel, and
15
good afternoon, witnesses.
16
the past.
17
for the Power Workers' Union.
I think I've met all of you in
My name is Richard Stephenson, and I am counsel
Good afternoon.
18
I want to talk about the nuclear stretch factor.
As I
19
understand it, the purpose of this mechanism is to attempt
20
to improve OPG's performance relative to one of its key
21
performance metrics, which is the total cost per megawatt-
22
hour metric.
Am I right about that?
23
MR. FRALICK:
Yes.
24
MR. STEPHENSON:
And OPG is increasingly looking for
25
that metric as being an important performance indicator, I
26
gather, and it's embedded in fact in your business plan,
27
correct?
28
MR. FRALICK:
It is, yes.
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MR. STEPHENSON:
I think this is self-evident, but
2
you'll agree with me that obviously that metric turns on
3
two numbers.
4
other hand, it is your actual output, your production,
5
correct?
On the one hand, it's your costs, and on the
6
MR. FRALICK:
It is, yes.
7
MR. STEPHENSON:
Can I just ask you if the object of
8
the exercise is to improve your performance relative to
9
that metric, why do you have a proposal that deals with
10
11
only one of the two elements of that metric?
Your proposal deals entirely with costs, correct, and
12
not about production?
13
MR. FRALICK:
The stretch factor is applied to 75
14
percent of the total OM&A cost in our proposal.
15
production is based on our forecast, the way we've done it
16
as per our historical methodology.
17
18
19
The
As you're aware our rate, is 100 percent variable so
we are incented to increase our output as much as possible.
MR. STEPHENSON:
Sure.
But this is a cost-cutting
20
metric, correct?
21
cost-cutting; that is you've got to find savings on your
22
costs, correct?
23
MR. FRALICK:
Sorry, your stretch factor is all about
That's the way it works?
It's an efficiency measure as we
24
understand it, so it is applied to the cost.
25
way in which to make up for that stretch factor would be to
26
increase our production relative to plan.
27
28
MR. STEPHENSON:
However, one
That would be true, but it's
certainly not going to be measured by your stretch factor,
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it's not going to be captured in that mechanism, correct?
2
MR. FRALICK:
Correct.
3
MR. STEPHENSON:
I mean, aren't I right that one of
4
the ways that you can improve your performance against the
5
total cost per megawatt hour metric is by increasing your
6
costs by increasing your costs in a cost effective manner
7
such that you're increasing your production that such an
8
revenue -- the incremental revenues exceed the incremental
9
costs?
10
MR. FRALICK:
Yes, we do have a category of projects
11
in fact that we would pursue on the basis of value
12
enhancing, and we do those types of analyses and pursue
13
projects that fall into that category.
14
MR. STEPHENSON:
That's true not only in terms of
15
capital projects, but also -- I mean, outage management has
16
been an ongoing priority for the company, correct?
17
MR. FRALICK:
Yes.
18
MR. STEPHENSON:
And the simple reality is the best
19
way for the company to increase production is to manage
20
your outages efficiently, make them as short as possible,
21
correct?
22
MR. FRALICK:
Well, that would certainly be one
23
predominant way, but also managing our reliability so we
24
minimize forced loss rate would also achieve the same.
25
MR. STEPHENSON:
Sure, I got it.
But just in terms of
26
minimizing your outage length, one of the ways of doing
27
that is by deploying more resources during the outage.
28
You're actually putting incremental costs in, correct?
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MR. FRALICK:
Yes.
In terms of making decisions about
2
the length of an outage or how to manage and resource an
3
outage, the duration and the impact on our revenues
4
associated with the cost and what we expect to be able to
5
get as a result of that investment, is always part of the
6
decision-making.
7
So on a real-time basis, if we think that we can
8
return a unit quicker and the incremental revenue that
9
would result is more than the cost that we would incur to
10
11
achieve, then we would pursue that.
MR. STEPHENSON:
And that would be a means whereby you
12
are in fact increasing your costs, but doing better on the
13
metric, right?
14
MR. FRALICK:
15
MR. STEPHENSON:
16
That's right.
But your stretch factor just doesn't
deal with that the all, right?
17
MR. FRALICK:
That's right.
18
MR. STEPHENSON:
Let me just talk now about your
19
challenge in in fact taking costs out of the company during
20
the rate period.
21
Your evidence indicates that you are constrained in a
22
variety of ways, in terms of your ability to take costs out
23
and that's in part why you're only applying it to a portion
24
of your costs, correct?
25
MR. FRALICK:
Yes.
26
MR. STEPHENSON:
And you've excluded certain areas
27
that have to do with safety, as I understand it, so that
28
you've got -- it's 75 percent of your OM&A is the basket
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that you're capturing in this for the stretch factor
2
purposes, correct?
3
MR. FRALICK:
Yeah, our stretch factor in our proposal
4
applies to our base OM&A plus the corporate allocations.
5
Now, within base OM&A there are certain cost drivers where
6
we do not expect to be able to achieve efficiencies, so as
7
you alluded to, safety, regulatory requirements, things
8
that are very prescriptive in nature that you won't be able
9
to improve from an efficiency perspective.
So that
10
necessarily drives us to look at our total cost bucket in
11
order to come up with the cost savings that we will need to
12
identify in order to offset that stretch factor.
13
MR. STEPHENSON:
So you've got a savings number for
14
your stretch factor, but as I understand it, I mean, have
15
you got a calculation anywhere in your evidence where you
16
can have attempted to isolate as a practical matter the
17
amount of cost from which you are able to make some
18
savings, you know, you say even within this there's, you
19
know, safety issues that we can't meaningfully extract any
20
costs anyway.
21
So once you extract the things that you don't have a
22
meaningful ability to extract costs, what's left?
23
the -- what's the bucket from which you're taking costs out
24
of?
25
MR. FRALICK:
What is
I don't have that number off the top of
26
my head.
It would be something less than the 75 percent of
27
our OM&A that we have applied it to.
28
bit of a proxy for where we think we can obtain
We treat that as a
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efficiencies, but we know that it's not -- I do not have
2
that figure directly.
3
MR. STEPHENSON:
So if we think about it, that it's
4
not 75 percent, it's a number lower than 75 percent, then
5
the actual amount in practical terms of your stretch factor
6
is a number higher than the notional stretch factor that
7
you've got -- or, sorry, the nominal stretch factor that
8
you have got in your application, correct?
9
MR. FRALICK:
Yes, if I'm following you, then the --
10
if the 75 percent includes things that we will not be able
11
to achieve efficiencies upon, then the degree to which that
12
amount decreases, then what's left of a fixed amount of
13
stretch factor that we have calculated now divided by a
14
smaller number becomes a bigger percentage, yes.
15
16
MR. STEPHENSON:
We just don't know exactly what that
number is?
17
MR. FRALICK:
No.
18
MR. STEPHENSON:
Okay.
Another way of thinking about
19
constraints on your ability to take costs out is -- are the
20
legal and committed limitations that you've got on at least
21
certain buckets of your costs, and one of those limitations
22
is with respect to your compensation envelope, correct?
23
There are some constraints on your ability to extract costs
24
out of that envelope, correct?
25
MR. FRALICK:
Yes, the compensation costs are --
26
they're the outcome of collective agreement negotiating
27
process, to a large extent.
28
measures by way of overtime and things like that, but as
We do have some control of
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I'm sure panel 4 will go into much greater detail, once
2
that collective agreement is negotiated and set, then the
3
rates for that term of the collective agreement are indeed
4
set, and therefore our ability to extract labour costs from
5
-- certainly on a rate basis are -- we don't have that as a
6
lever.
7
MR. STEPHENSON:
Okay.
Can I just get you to turn up
8
-- it's Exhibit A1, tab 3, schedule 2.
9
for this part.
10
11
12
It's the evidence
And in particular page 38.
I just want to
correct one thing.
In the middle of the page there is a reference to the
PWU collective agreement.
Line 17:
13
"These agreements run from April 1, 2015 to March
14
31, 2017."
15
Do you see that?
16
MR. FRALICK:
17
MR. STEPHENSON:
18
MR. FRALICK:
19
MR. STEPHENSON:
20
2018?
On line 17?
Yes.
Yes.
That's wrong, right?
It's actually
That's just a typo?
21
MR. FRALICK:
That's correct.
22
MR. STEPHENSON:
Okay.
And I think this is true for
23
both of your labour agreements, at least the two big ones
24
with the Society and the PWU, and I may have to deal with
25
this with another panel, but let's see how far I can get
26
with you.
27
28
Both of those agreements prohibit the company from
doing any involuntary layoffs or terminations during their
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period, correct?
2
MR. FRALICK:
As I understand it, yes.
3
MR. STEPHENSON:
So as I understand it, in terms of
4
the company's ability to decrease the costs associated with
5
those collective agreements, it's really limited to three
6
things.
Item number 1 is attrition, correct?
7
MR. FRALICK:
8
MR. STEPHENSON:
9
That would be a means.
People leave the company, you have
some ability to not replace them, correct?
10
MR. FRALICK:
Yes.
11
MR. STEPHENSON:
But however, if we look in your
12
material -- and I can check this with somebody else if you
13
don't know it -- you're not actually forecasting decrease
14
in complement until after 2020.
15
MR. FRALICK:
Not in any material way.
I have to turn up the evidence, but I
16
believe it's relatively flat through most of the five-year
17
term, yes.
18
MR. STEPHENSON:
The second way that you can take
19
costs out is by controlling the amount of overtime, and
20
you've indicated that, correct?
21
MR. FRALICK:
Yes.
22
MR. STEPHENSON:
But this dovetails back to the issue
23
of outage management to a large degree, doesn't it?
24
where the lion's share of your overtime in fact is
25
dedicated, correct?
26
27
28
MR. FRALICK:
That's
We incur a lot of overtime, particularly
in the maintenance ranks, during outages, yes.
MR. STEPHENSON:
And from the company's perspective,
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you actually in a -- colloquially, you make money on that
2
overtime.
3
even at higher rates, if you can shorten that outage
4
duration, you're back online and making revenue?
5
If you can deploy those additional resources
MR. FRALICK:
Yeah, I guess if you're saying that it
6
would be a myopic view to look strictly at overtime, say,
7
and minimize that at all costs, to use the phrase, would be
8
a narrow way to look at how to run the business.
9
not do that.
10
11
MR. STEPHENSON:
Right.
You would
I mean, you may save a
dollar, but it may cost you a dollar and a half, right?
12
MR. FRALICK:
Yes.
13
MR. STEPHENSON:
Okay.
And the third way you can take
14
some costs out of these collective agreements is that you
15
have got some temporary employees governed by these
16
collective agreements and you can, you know, increase or
17
decrease the number of those, correct?
18
MR. FRALICK:
Well, linked to your first metric, being
19
attrition, as people leave, particularly in light of what
20
we were looking at at Pickering and end of commercial
21
operations in the next decade, we have got the term
22
employee provision now, so we would look to shift more
23
employees to that from a full regular FTE, yes.
24
MR. STEPHENSON:
Right.
But that's more of a
25
theoretical than a real issue in terms of your ability to
26
say, because you're not actually forecasting any material
27
change in complement, right?
28
MR. FRALICK:
Correct.
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MR. STEPHENSON:
And that's governed by your perceived
2
need, right, that you would take -- you would be -- if you
3
could get more complement down you would, but you perceive
4
you need these bodies to do your operations, right?
5
MR. FRALICK:
We have a challenging mandate to meet at
6
our stations over the next decade, and we have a work
7
program that has to be executed to ensure that we maintain
8
the reliability and execute the tough mandate that we have,
9
and that's the complement that -- and the full plan that we
10
11
require in order to be successful in that endeavour, yes.
MR. STEPHENSON:
So -- and obviously on management
12
comp you have less legal constraints around your ability to
13
reduce that, but again, as I understand your staffing plan
14
from elsewhere in your materials, you're more or less
15
looking at a fairly flat complement in that area as well,
16
at least until 2020, again because you perceive that that's
17
what you need to run the operation.
18
MR. FRALICK:
That's right.
19
MR. STEPHENSON:
So if you -- if you're -- and the
20
compensation bucket is a very substantial proportion of
21
your OM&A spend, correct?
22
23
24
MR. FRALICK:
Yes, it's -- I'd be guessing, but
somewhere two-thirds or more.
MR. STEPHENSON:
And if that bucket is -- you'd agree
25
with me it's pretty highly constrained in terms of your
26
ability to extract dollars, fair?
27
MR. FRALICK:
Yes.
28
MR. STEPHENSON:
And bearing in mind those
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constraints, if we're looking only at the remaining aspect
2
of your OM&A budget, again if you're going to extract all
3
the vast majority of the savings for your stretch factor
4
out of that remaining portion, again the actual amount of
5
the stretch is that much bigger, correct?
6
MR. FRALICK:
To achieve the stretch factor that we've
7
proposed will be a challenge.
8
side some $50 million cumulative over the full five years,
9
and that's not going to be easy for us to find.
10
MR. STEPHENSON:
It totals, on the nuclear
I didn't see in the evidence actually
11
any plan, proposal, any identification actually where the
12
money is coming from.
13
MR. FRALICK:
Is there something I missed?
No, you didn't miss it.
The stretch
14
factor by design is an up-front give that is incremental to
15
our challenging business plans.
16
a number of initiatives that we will need to execute in
17
order to achieve, and the stretch factor is above and
18
beyond that, and we have not identified what those
19
initiatives will be in detail at this point in time.
20
need to do that.
21
MR. STEPHENSON:
Our business plan includes
We
The number that you've indicated is
22
this .3 percent, which is essentially compounded, as I
23
understand it, over the term.
24
MR. FRALICK:
Yes.
25
MR. STEPHENSON:
But just as we've gone through and
26
talked about the constraints on areas where you can't
27
meaningfully get money out -- I mean, if we talked about
28
the stretch factor as a practical matter in terms of
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controllable costs being at, say, one percent or higher,
2
does that sound like a reasonable number?
3
4
5
6
MR. FRALICK:
greater than .3.
MR. STEPHENSON:
Those are my questions.
MS. LONG:
8
MR. MILLAR:
Thank you, Mr. Stephenson.
Good afternoon, Panel.
Mr. Millar?
When would you be
looking at taking an afternoon break?
10
MS. LONG:
11
MR. MILLAR:
12
CROSS-EXAMINATION BY MR. MILLAR:
13
Good afternoon, panel.
14
am counsel for Board Staff.
15
pleasure of meeting before.
16
Thank you
very much.
7
9
I'd be guessing, but certainly it's
Around 3 o'clock.
Thank you.
My name is Michael Millar; I
I believe we've all had the
First, I have some questions about your custom
17
incentive regulation proposal for your nuclear operations,
18
and -–
19
20
21
22
MR. SMITH:
Sorry, Mr. Millar.
compendium; was it your intention to mark that?
MR. MILLAR:
Yes, why don't we do that?
K6.3, Staff compendium.
MR. FRALICK:
24
EXHIBIT NO. K6.3:
25
COMPENDIUM FOR OPG PANEL 2A(I)
26
MR. MILLAR:
28
That will be
Panel, you have copies of this?
23
27
You provided a
Yes.
BOARD STAFF CROSS-EXAMINATION
You proposed a five-year custom incentive
for your nuclear facilities?
MR. FRALICK:
Yes, we have.
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MR. MILLAR:
And one of the features is the stretch
2
factor which you were just discussing with Mr. Stephenson,
3
and I'm going to start with a few questions about that.
4
Maybe we could begin by turning to page 2 of the
5
compendium.
6
Stephenson as talking about, but I thought I would take you
7
to the Board's words on this.
8
stretch factor is.
9
10
And this gets a little bit to with a Mr.
It sort of describes what a
If you look at the third full paragraph about the
middle the page, it states:
11
"The stretch factor component of the X factor is
12
intended to reflect the incremental productivity
13
gains that firms are expected to achieve under
14
incentive regulation, and is a common feature of
15
IR plans.
16
vary by company, and depend on the efficiency of
17
a given company at the outset of the IR plan.
18
Stretch factors are generally lower for firms
19
that are relatively more efficient."
20
Now first of all, it's talking about an X factor
21
there.
22
custom IR.
23
These expected productivity gains can
So obviously, this is discussing IRM as opposed to
But for our purposes here today, is that an accurate
24
description of a stretch factor, from your perspective?
25
that what you were thinking when you proposed a stretch
26
factor, that that's the purpose of a stretch factor?
27
28
MR. FRALICK:
Yes.
Is
We essentially took the definition
of the stretch factor to be akin to the one that we applied
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to our hydroelectric assets, which is more of a pure fourth
2
generation IRM, and we treated it the exact same.
3
construct perspective, a stretch factor is the same, yes.
4
MR. MILLAR:
From a
This is not unique to OPG; it's a
5
standard tool the Board has been using under incentive
6
regulation for many years?
7
MR. FRALICK:
8
MR. MILLAR:
9
10
As I understand it, yes.
The document I took you to is for
distributors, for example, and I know you modeled your plan
on that.
But this is not new to OPG, is my point.
11
MR. FRALICK:
12
absolutely new for OPG.
13
previous proceeding.
14
applied a stretch factor.
15
MR. MILLAR:
The use of a stretch factor is
We have not applied that in any
This is the first time we have
Certainly it's new to OPG, but the
16
concept of a stretch factor has been around at the Board
17
for a while under incentive regulation plans for
18
distributors?
19
MR. FRALICK:
20
MR. MILLAR:
Understood, yes.
Just to take you to a couple things Mr.
21
Stephenson mentioned, it's been used by distributors for
22
many years.
23
agreements with those employees; is that fair?
LDCs have employees and they have collective
24
MR. FRALICK:
25
MR. MILLAR:
26
I would assume so, yes.
You can take that subject to check, that
Hydro One has collective agreements.
27
MR. FRALICK:
28
MR. MILLAR:
I know Hydro One does, yes.
And many, at least of the larger ones,
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would have collective agreements with their employees?
2
MR. FRALICK:
3
MR. MILLAR:
Yes.
And there are probably doubtless other
4
areas.
5
be areas where a distributor simply can't find
6
efficiencies; is that probably true?
7
They wouldn't be regulated by CNSC, but there would
MR. FRALICK:
Probably true.
However, OPG is unique
8
in the fact that we have a 100 percent variable rate design
9
and no part of our costs are fixed, and that is a
10
11
significant difference to other regulated entities.
MR. MILLAR:
But a stretch factor applies against the
12
entire -- okay, I take your point.
13
savings that you might be able to find from your
14
compensation costs.
15
Let's move on to
There was a suggestion that you have very little
16
wiggle room when it comes to making savings on compensation
17
costs, although you did concede there are some things like
18
over time, and I'd also suggest the number of FTEs that are
19
outside the collective agreement that you do have some
20
control over?
21
MR. FRALICK:
Yes, we have control over the numbers
22
and overtime to a certain extent.
23
running the operation, you're not strictly looking at how
24
many people you have or how much your overtime is.
25
looking at are you able to get the work done within the
26
overall envelope.
27
28
However, when you're
You're
So you're switching in between your resource types and
resource work execution methods, as appropriate in the
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2
3
given circumstance.
MR. MILLAR:
Mr. Fralick, you'd be familiar with OPG's
business transformation initiative from several years ago.
4
MR. FRALICK:
5
MR. MILLAR:
I am, yes.
I am doing this from memory, but it ran
6
something like from 2011 to 2015?
7
in that range?
8
9
10
Does that sound right,
Mr. Mauti, you may know better?
MR. MAUTI:
Yes, it did.
That was the approximate
range, yes.
MR. MILLAR:
And through that initiative, you were
11
able to shed over 2000 positions, 2000 FTEs.
12
correct?
13
MR. MAUTI:
14
MR. MILLAR:
15
I believe the number we quoted was 2700.
MR. FRALICK:
17
MR. MILLAR:
19
Okay, so closer to 3000.
And by doing
that, you were able to realize significant OM&A savings?
16
18
Is that
Yes.
And you also realized significant
efficiency through business transformation, is that fair?
MR. MAUTI:
Part of the approach for coming up with
20
the centre led sort of structure was to try to gain those
21
efficiencies, and operate the business as effectively as
22
possible, yes.
23
MR. MILLAR:
And your collective agreements did not
24
prevent you from realizing those savings, or realizing
25
those efficiencies?
26
MR. MAUTI:
Not directly.
We were able to leverage
27
the demographics of the company that would allow for those
28
departures to happen, without there being a formal process
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2
to downsize in the company.
MR. MILLAR:
Can I ask you to turn to page 3 of the
3
compendium, please?
4
you proposed a stretch factor of 0.3 percent, and this
5
would apply to a portion of your OM&A expenses as we've
6
already discussed.
7
8
9
10
As you discussed with Mr. Stephenson,
You also mentioned that's approximately 75 percent of
your total OM&A?
MR. FRALICK:
MR. MILLAR:
That's correct.
The savings that would result from your
11
proposal over the five years of the custom IR term is
12
$50 million; is that correct?
13
14
15
MR. FRALICK:
The cumulative total over the five years
is 50 million, yes.
MR. MILLAR:
Let's start with the derivation of how
16
you came up with the 0.3 percent.
17
framework for electricity distributors, there's five
18
different buckets you can fall in, is that right?
19
MR. FRALICK:
20
MR. MILLAR:
Under the current
Yes.
And you can see that in the footnote at
21
the bottom of page 3 of the compendium.
22
percent, .15, .3, .45 and .6.
23
buckets?
24
MR. FRALICK:
25
MR. MILLAR:
There's zero
So those are the five
Yes.
And maybe we can turn to page 7 of the
26
compendium.
Electricity distributors are slotted into one
27
of these groups based on the relative efficiency of their
28
operations, is that correct?
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MR. FRALICK:
2
MR. MILLAR:
As we understand it, yes.
Okay.
And I guess the way they do that
3
is a report is prepared, and this -- the most recent one is
4
by Pacific Economics Group, and they do some research on
5
their relative efficiency, and then all of the LDCs are
6
slotted in one of those five buckets; is that right?
7
you understand it?
8
MR. FRALICK:
9
MR. MILLAR:
As
As we understand it, yes.
Okay.
In fact, if you turn to page 7 of
10
the compendium you can see the most recent stretch factor
11
assignments for the LDCs.
12
MR. PUGH:
13
MR. MILLAR:
That's correct.
Now, OPG, of course, is not part of this,
14
because you're not an LDC, and you weren't part of this
15
study, but your proposal is to place yourself in the middle
16
group, the 0.3 percent?
17
MR. FRALICK:
Yes, OPG utilized the existing
18
ScottMadden methodology for benchmarking that's been in
19
place for many years, and we assessed where we ranked on
20
our TGC basis relative to, you know, the benchmark, and
21
through our calculation determined that we would be at .3,
22
yes.
23
MR. MILLAR:
Yes, in fact you'll see that if you turn
24
to page 8 of the compendium.
I've taken an excerpt from
25
your application.
26
the measure you used for efficiency was TGC, and I think
27
Staff tends to agree with that measure, but maybe you could
28
let us know why that is the measure you selected.
And first, just to backtrack a little,
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MR. FRALICK:
I think ultimately it is a fair
2
reflection of OPG's cost performance.
3
readily benchmarkable, and its denominator is megawatt
4
hours, which is our product, and so we feel that that is
5
appropriate for use in the determination of a stretch
6
factor.
7
MR. MILLAR:
Okay.
It's one that's
And then if we look at chart 9, we
8
see what you did.
You split Darlington and Pickering, and
9
you assigned each of them their own value based on their
10
relative efficiency, and for Darlington the TGC was top
11
quartile, so you gave that a zero.
12
bottom quartile.
13
through the production forecast, weighed it, and you ended
14
up at more or less 0.3.
15
You gave that .6.
MR. FRALICK:
For Pickering it was
You sort of ran that
That's how you arrived at 0.3?
Correct.
We production-weighted the
16
individual stations' stretch factor determination based on
17
their TGC performance.
18
MR. MILLAR:
And what you did was you chose to
19
consider Pickering TGC and Darlington TGC separately, as
20
opposed to considering an overall number for OPG.
21
ask you to turn to page 9 of the compendium.
22
business plan.
23
approach you take in the business plan.
24
think it's the second sentence overall:
If I can
This is your
We can see here near the -- this is not the
If you look -- I
25
"In 2016 OPG adopted TGC as an enterprise-wide
26
measure of operational cost-effectiveness in
27
addition to TGC metrics for each of the nuclear
28
and hydro operations."
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So why is it appropriate to use an all-in number for
2
your business planning purposes but for setting a stretch
3
factor you wanted to divide it between Pickering and
4
Darlington?
5
MR. MAUTI:
In the business plan that you referenced
6
on page 9 we summarized an enterprise and by technology
7
level the two total generating cost measures.
8
further in the back of the business plan, and A221,
9
attachment 1, page 30, provides the operational targets,
They are
10
including TGC at a Pickering and Darlington individual
11
level.
12
So the way we described it in the front part of the
13
business plan was just to get an overall flavour from a
14
technology point of view.
15
plan package tends to have a consolidated kind of use of
16
things.
17
So the front of the business
We have a lot more detail in the back as well.
So they are calculated -- they're benchmarked at a
18
station level.
19
this on the technology basis.
20
We just reported them at the front part of
MR. MILLAR:
Okay.
The numbers that you used to set
21
the 0.3 that we just looked at on page 8, I guess it was,
22
those were based on the 2015 nuclear benchmarking report;
23
is that correct?
24
MR. FRALICK:
25
MR. MILLAR:
That's correct.
And although it's called the 2015
26
benchmarking report it's actually for 2014 numbers; is that
27
right?
28
MR. FRALICK:
That's correct.
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2
MR. MILLAR:
And at the time you prepared the
application that was the most recent data that you had?
3
MR. FRALICK:
4
MR. MILLAR:
That's correct.
And just to take a step back, this
5
nuclear benchmarking report, I do have some benchmarking
6
questions here.
7
getting into more detail on benchmarking, but I think since
8
it relates to stretch factor we will have to go over this
9
just a little bit here.
Obviously it's panel 3 with which we'll be
10
What this benchmarking report does is it compares your
11
performance against other North American nuclear operators?
12
MR. FRALICK:
13
MR. MILLAR:
It does.
And the comparators in this report and
14
the entire methodology was established with the assistance
15
of the consulting firm ScottMadden?
16
MR. FRALICK:
17
MR. MILLAR:
18
It was, yes.
And you've been reporting on this basis
for quite a number of years now.
19
MR. FRALICK:
20
MR. MILLAR:
Yes, that's right.
Okay.
And back with the 2015
21
benchmarking report, as we've discussed, Darlington was top
22
quartile and Pickering was bottom quartile.
23
then we have the 2016 benchmarking report, and if I could
24
ask you to flip all the way ahead to page 29 of the
25
compendium.
26
However, since
We see the results of that here.
If you look under the "value for money" metric just
27
over halfway down the page, you'll see the three-year total
28
generating cost, and it's colour-coded, so if you loacross
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to Pickering we see red, which means fourth-quartile, which
2
is where it was in the previous report, but Darlington now
3
is second quartile; is that right?
4
MR. FRALICK:
That's right.
So this, as you'll see,
5
is a rolling three-year average for the Darlington metrics.
6
So 2015 would have come in and 2012 would have dropped off.
7
And 2015 was a very unique year for Darlington, in that it
8
executed a one-in-ten-year vacuum building outage, so
9
you've taken the entire plant down, so the corresponding
10
production is down considerably, the costs are up.
11
was a significant driver for the cost performance coming in
12
for Darlington in 2015.
13
So that
In addition to that you'll see further on down in this
14
report on page 80 the capital performance and -- while
15
still well within the first quartile, the capital program
16
for Darlington has increased in recent time as it's gearing
17
up for the Darlington refurbishment.
18
And the third contributing factor which again
19
reinforced the need for refurbishment is, the FLR rate at
20
Darlington has exceeded our target, and that has also
21
contributed to the variance.
22
23
24
25
26
MR. MILLAR:
And those may all be the reasons for
that, but you've dropped to second quartile under TCG.
MR. FRALICK:
Yes, the point being that the 2015 is
not a representative year for those matters.
MR. MILLAR:
Okay.
But we don't -- when we look at
27
these figures it's based against your comparators.
In any
28
given year one of your comparators may have higher FLR than
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they anticipated or there may be a major project coming.
2
3
When we look at TGC the result is what the result is;
is that fair?
4
5
MR. FRALICK:
Yes, but the entire benchmark doesn't
take a VBO at the same time in the same year.
6
MR. MILLAR:
It doesn't, but other years you might
7
have benefited when somebody else had an outage like that.
8
Is that possible?
9
MR. FRALICK:
10
MR. MILLAR:
Marginally.
Let's flip back to page 10 of the
11
compendium.
This shows your most current results for OPG
12
as a whole.
And am I right that of the 13 nuclear
13
operators that are measured you are 12th out of 13th when
14
it comes to TGC?
15
16
17
MR. FRALICK:
You're the second-worst?
That appears to be what this table says,
yes.
MR. MILLAR:
And that's a drop-off of what you had
18
when you originally filed.
19
ahead to page 12, this was the original pre-filed material.
20
You were a bit better than -- you were 10th out of 13th
21
overall, but as I say, you're now 12th out of 13th.
22
23
24
MR. FRALICK:
Right.
You can see that -- if you flip
And the reasons for that I
outlined.
MR. MILLAR:
Okay.
And then indeed if we look at your
25
business plan that's back on page 9, I note first on page
26
10 that your TGC for 2015 was $54.58.
27
after, you'll see on page 9 of the compendium right at the
28
top $63.20, so you're predicting a very significant
For 2016, a year
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2
increase from 2015 to 2016 as well; is that fair?
MR. FRALICK:
Yes, and while panel 3 can go into this
3
in greater detail, certainly a significant driver would be
4
the commencement of the Darlington refurbishment program,
5
as well as other outage activities.
6
MR. MILLAR:
So is that a normal -- we'll get into
7
normalized with panel 3, I think, but is that a normalized
8
number, is that a non-normalized number?
9
10
MR. MAUTI:
As you see it on page 9, this would be a
non-normalized number.
This is the raw number itself.
11
MR. MILLAR:
12
For 2016, Darlington shut-off -- Unit 2 went out at
13
14
15
16
Okay.
That's the raw number.
Thank you.
the end of November?
MR. FRALICK:
No, it went out in the middle of
October.
MR. MILLAR:
Middle of October, okay.
You'll see that
17
over the test period, the costs are up in the 75 to -- 74
18
to 77 range.
19
normalized, so I take it the DRP is one causes of the high
20
costs at that time.
21
MR. MAUTI:
22
predominant by far.
23
Again, those are the raw numbers not
MR. MILLAR:
Correct.
That's probably the most
Given the numbers up to 2015, if you wish
24
to exclude 2016, is it still your view that this is mid
25
range performance on TGC?
26
MR. FRALICK:
Well, we would look at the period before
27
2015, given the unique outage in 2015.
If you want to look
28
at a period that's reflective of what OPG's underlying
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performance is, and in that period OPG was indeed top
2
quartile for Darlington.
3
noted, has been unchanged.
4
MR. MILLAR:
And Pickering has, as you've
But most recent actual data we have from
5
2015, at least on a company-wide basis, shows you as 12th
6
out of 13th in TGC performance.
7
suggest a stretch factor of 0.6.
To some, that would
8
Do you have anything to add to what you just said?
9
MR. FRALICK:
I wouldn't say that that is a direct
10
conclusion.
11
methodology that we have utilized, that would not come out
12
at 0.6.
13
14
I think if you run through the calculation
MR. MILLAR:
You didn't rerun on the numbers, though,
did you based on the most updated results -- or did you?
15
MR. PUGH:
We did do is we ran the results using these
16
2015 benchmark numbers that appear on page 29 of your
17
compendium.
18
at the median at .3, and it shows Pickering is in the
19
fourth quartile at .6.
20
21
22
So it shows that Darlington is in fact right
And when we ran the numbers for those, we came up with
.43.
MR. MILLAR:
Okay.
So that would be closer to .45
23
than .3, obviously.
And is OPG actually amending its
24
application to reflect that, or are you still seeking 0.3?
25
MR. FRALICK:
26
MR. MILLAR:
27
I have some questions about the memorandum of
28
We're seeking 0.3.
Let me move to my next area.
agreement, and I actually thought these would be questions
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for panel 3 because they're really about benchmarking.
2
I saw on your consolidation sheet that they're questions
3
for you.
4
So I'll try them with you.
But if there posed to
5
panel 3, by all means punt me to them.
6
lose my chance.
7
MR. FRALICK:
8
MR. MILLAR:
9
But
I don't want to
Are these questions for you, Mr. Fralick?
Likely John, Mr. Mauti.
Mr. Mauti, you're familiar with the
memorandum of agreement that OPG has with its shareholder?
10
MR. MAUTI:
11
MR. MILLAR:
Yes, I am.
And there have been changes to that
12
memorandum of agreement since last we enjoyed a discussion
13
here in this room, since the last case?
14
MR. MAUTI:
15
in August 2015.
16
MR. MILLAR:
Sorry, the memorandum of agreement changed
So after the last main OPG proceeding.
17
I'm sorry, I did see you at the technical conference, so I
18
apologize for that.
19
One of the changes relates to benchmarking, and if you
20
look at page 16 of the compendium, we have the old
21
memorandum of agreement.
22
it discusses continuous improvements, and that you're to
23
benchmark and target the top quartile against other North
24
American operated utilities.
25
You'll see that in paragraph 3,
And if we look at the revised version of the
26
memorandum of understanding, you'll see that on page 15 of
27
the compendium -- I didn't reproduce the whole thing, but I
28
think I have the replacements here -- that language no
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longer appears, is that fair?
2
3
MR. MAUTI:
The language on benchmarking has changed
and it is now in a subsection 6.1.3.
4
MR. MILLAR:
That's right.
Should questions I have
5
about this, are they for you now or should these be for
6
panel 3, questions about your approach to benchmarking?
7
8
MR. MAUTI:
depending on the technical --
9
10
You can try the questions for me,
MR. MILLAR:
I'll try them, and you can tell me if
we've gone too far.
11
The MOA no longer specifies you should target top
12
quartile in your benchmarking efforts.
13
why that change was enacted?
14
MR. MAUTI:
First, do you know
I guess as part of updating the memorandum
15
of agreement that had, I believe, been in existence in
16
since 2005.
17
There were several changes and Board Staff IR number 1
18
described what those main changes were.
19
benchmarking, I believe it was a recognition it was a
20
recognition to do appropriate benchmarking, as it should
21
always be, you should try to find an appropriateness of how
22
you're doing the benchmarking and what you were comparing
23
to.
24
When it came to
So I think in our case, recognizing that in 2015 our
25
nuclear fleet was getting to a point where the plants were
26
going through very different changes, whether that's
27
refurbishment for a second life for Darlington or
28
approaching commercial end of commercial operations or
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potential extension for Pickering, it was more appropriate
2
to have a memorandum of agreement that required
3
benchmarking that was appropriate for the operations as we
4
have them at the time.
5
They have changed substantially since 2005, and I
6
would assume that's what led to the change in the wording
7
to make it an appropriate benchmark as opposed to something
8
more specific.
9
MR. MILLAR:
And the new language, which we see at
10
page 15, it doesn't say anything about targets at all; is
11
that right?
12
MR. MAUTI:
13
what's appropriate.
14
cycle of that plant and how you're comparing what some of
15
those factors would be, that you do benchmarking to be able
16
to come up with actionable things you can take from that,
17
not just necessarily to compare to what's at the top or the
18
bottom of that comparator group.
19
20
21
No, it just says you should benchmark to
MR. MILLAR:
And again, understanding the life
It doesn't mention continuous improvement
Either, at least not specifically; is that fair?
MR. MAUTI:
Perhaps not specifically within that, but
22
in the expectations for operations in terms of improvement,
23
I believe that language is in the MOA, just not specific to
24
the benchmarking.
25
26
MR. MILLAR:
OPG still proposes to set targets for TGC
and in fact, we see that in the application, right?
27
MR. MAUTI:
28
MR. MILLAR:
That is correct, yes.
And you are targeting -- it's not just an
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absolute number.
2
quartiles as well?
3
MR. MAUTI:
You have targets with respect to
We try to understand obviously where we
4
believe the industry is going from a quartile basis and set
5
our targets, again in taking into account the evolution of
6
the plant, and specifically with Darlington as it's going
7
through refurbishment for the next decade, where you'll
8
have one and sometimes two units out for refurbishment,
9
that has a dramatic impact on the TGC value.
10
11
So we need to
take that into account.
It would be inappropriate to suggest we are targeting
12
top quartile to Darlington while it's going through that
13
phase of refurbishment.
14
MR. MILLAR:
With respect to continuous improvement, I
15
assume you'd agree with me that despite the fact that those
16
words don't appear in the MOA anymore, OPG still does
17
strive for continuous improvement?
18
MR. MAUTI:
Yes.
I believe you had a compendium
19
excerpt from the previous hearing as well, and Ms. Swami
20
also did reference the fact that we're always trying to
21
improve and make changes to our operations targeting,
22
whether it's a how we do our outages or the reliability of
23
our plants, safety and what-not.
24
Those are things we continuously look at and continue
25
to compare ourselves.
26
MR. MILLAR:
Let's turn to that.
That's page 20 of
27
the compendium, I believe.
At the bottom of the page, this
28
is a response from Ms. Swami to a question I asked.
She
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states:
2
"And would I like to see us move up the relative
3
ranking?
4
trying to make our performance better, and that's
5
why we targeted improvement programs," et cetera.
Of course.
OPG is always interested in
6
I assume that still holds true today?
7
MR. MAUTI:
8
MR. MILLAR:
9
Yes, it does.
Thank you.
I have a couple of more
questions about the stretch factor, but not about the
10
number, the 0.3 or what have you, but the portions of your
11
spend you propose to apply it to.
12
Could we turn to page 22 of the compendium?
We went
13
over this a little bit already, but to refresh everybody's
14
memory, you don't propose to apply the stretch factor to
15
your entire O&M budget.
16
O&M and allocated service O&M, is that right?
17
MR. FRALICK:
18
MR. MILLAR:
It will be applied to nuclear base
And allocated corporate support costs.
Sorry, yes, I misstated that yes.
When
19
we turn to page 23, we see those numbers and without
20
straining anyone's vision too much, you can see that
21
project OM&A is line 2 and allocation of corporate cost is
22
line 7, is that right?
23
MR. FRALICK:
24
MR. MAUTI:
25
MR. MILLAR:
Yes.
That's correct.
And 11 is the total OM&A.
So I just want
26
to make sure I understand how you did the calculation.
27
added lines 2 and -- I'm sorry, it's base OM&A.
28
misspoke.
You
I
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MR. FRALICK:
2
MR. MILLAR:
Yes.
It's base OM&A.
My mistake.
So line 1 and line 7, you
3
added those together, and then you took that as a
4
proportion of the total OM&A, which is line 11.
5
you came up with the 75 percent?
6
MR. FRALICK:
7
MR. MILLAR:
That's how
Yes.
Okay.
When we did the calculations it
8
actually -- it varied between 70 and 75 percent depending
9
on the year.
Would you take that subject to check?
10
MR. FRALICK:
11
MR. MILLAR:
Subject to check.
Okay.
All right.
And you propose to
12
exclude all other O&M from the application of the stretch
13
factor because in -- I'm reading from page 24 here.
14
don't know that you need to pull it up, but you state:
15
"OPG does not expect to find material
16
efficiencies in the remaining 25 percent."
17
MR. FRALICK:
Yes, so the projects, for example, and
18
outages, they are discrete activities, so they're not
19
activities that we do on a repetitive basis.
20
unique endeavour, and we develop a scope, and that is
21
tailored to that specific need at that time.
22
I
Each one is a
So from the perspective of efficiency of getting
23
better at doing the same thing, these cost categories do
24
not lend themselves to that type of gains.
25
MR. MILLAR:
Well, let's look at that a little bit
26
more carefully.
If we go back to page 23, which is up on
27
the screen, first, the two largest things you look to
28
exclude -- or two of the larger things that are excluded
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are project OM&A and outage OM&A, which you were just
2
discussing?
That's lines 2 and 3?
3
MR. FRALICK:
4
MR. MILLAR:
5
Yes.
And together those are about 500 million
dollars a year?
It varies a little bit?
6
MR. FRALICK:
7
MR. MILLAR:
Sure, yes.
Give or take?
In fact, the bulk of that
8
is outage OM&A.
In 2017, for example, it's 394, and it's
9
mostly around that range until you get to 2021, give or
10
take 400 million?
11
MR. FRALICK:
12
MR. MILLAR:
13
That's right.
And the Darlington units
are on a -- on outage cycle that's every three years?
14
MR. FRALICK:
15
MR. MILLAR:
16
Yes, between 394 and 415, yes.
That's right, yes.
And Pickering is faster than that.
two years.
17
MR. FRALICK:
18
MR. MILLAR:
Correct.
So these are -- the work may vary, but
19
outages are not unique, are they?
20
a set schedule?
21
It's
MR. FRALICK:
They're things you do on
To a certain extent they are, but
22
they're also -- the scope of any given outage is defined by
23
the corrective backlog that you want to undertake at that
24
point in time, so if something is broken, you need an
25
outage to fix it.
26
outage to a large extent, so while there would be some
27
component inspection type work that would be common, there
28
would certainly be a large portion that would be unique to
That would inform the scope of your
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a given outage.
2
3
The extent to which that breakdown is detailed, that
would be a question best asked to panel 3, though.
4
MR. MILLAR:
Okay.
Understood.
And -- but it's your
5
view no lessons learned on outage OM&A?
6
efficient over time?
7
MR. FRALICK:
You don't get more
No, that's not my point at all.
My
8
point is that each of these outages is unique endeavour,
9
and we set a budget that is challenging to execute the
10
scope of work that we need to for a given outage.
We would
11
execute lessons learned on outages like we do on projects,
12
and we continue -- we seek to improve our performance.
13
Indeed, outage performance is one of the initiatives listed
14
in our business plan.
15
MR. MILLAR:
So I guess I'm not quite following why
16
you don't think there are significant efficiencies to be
17
found there when there could be under base OM&A.
18
assume you have an aggressive forecast for base OM&A as
19
well, but you think a stretch factor is reasonable to apply
20
there.
21
is.
22
But I
I guess I'm not quite seeing what the difference
MR. FRALICK:
Yeah, it's the repetition of the work.
23
It's the likeness of the work.
24
much more work that is like for like, where you're
25
repeating a similar task over and over again, where it
26
would be more reasonable to seek efficiency gains.
27
28
Within base OM&A there is
In an outage it's not like that.
Each outage is
constructed uniquely, given the circumstances and scope at
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2
that time.
MR. MILLAR:
In your review of the Board's -- the
3
renewed regulatory framework and all its related documents,
4
did you find any references there that suggested that a
5
stretch factor would only apply to a portion of O&M?
6
MR. FRALICK:
No, we did not find a reference to that
7
extent.
We did note that the note of steady state is
8
something that is referenced in the RRFE, so when we looked
9
at our cost categories we looked for costs that we would
10
feel would be -- well, that are more objectively in a
11
steady state, and that is base OM&A and the corporate
12
support costs.
13
14
MR. MILLAR:
Your stretch factor also excludes your
capital spend; is that right?
15
MR. FRALICK:
16
MR. MILLAR:
It does.
And the same question I just asked with
17
respect to the RRFE or its related documents, did you find
18
a source there that suggested that capital should be
19
excluded from productivity measures such as a stretch
20
factor?
21
MR. FRALICK:
We did not find such a reference.
22
However, similar to the project OM&A bucket the capital
23
project bucket is similarly constructed of very discrete
24
projects, so unlike distributors, where you would see a lot
25
more repetition, each of this -- each project is unique, by
26
and large.
27
28
OPG employs what we call a project portfolio -portfolio management approach, sorry.
So we determine an
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annual budget for our capital program that is informed by
2
benchmarks.
3
capital program as efficiently as possible in order to
4
enable us to execute additional projects.
5
However, we are incented to execute our
We always have more projects than we have budget.
So
6
we are inherently incented to become as efficient as
7
possible on capital in order to make more investment in the
8
station which will improve reliability and performance, and
9
given the fact that our rate design is 100 percent
10
variable, we are always incented to try to maximize
11
production.
12
is that.
13
So our incentive within the capital portfolio
MR. MILLAR:
Now, you -- I know this isn't the hydro
14
panel, but under hydroelectric you're doing IRM, which also
15
has a stretch factor; is that right?
16
MR. FRALICK:
17
MR. MILLAR:
18
19
correct?
Yes, it does.
And that applies to everything.
Am I
It applies to O&M and capital?
MR. FRALICK:
Yes, we -- as we'll talk to in panel
20
2A(i), we have endeavoured to mirror the hydro IRM
21
structure as closely to the fourth-generation IRM construct
22
as possible.
23
24
25
MR. MILLAR:
So why should the stretch factor apply to
capital under IRM but not under custom IR?
MR. FRALICK:
Well, under IRM we understand it's an
26
all-in.
And while everything I said about the capital
27
program is also appropriate for hydroelectric, when it
28
comes to custom incentive regulation, we looked at that
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from the perspective of, you know, what was in a steady
2
state on the nuclear side of the house, and the capital
3
program, as I said, is much more discrete, and we feel that
4
it is -- an incentive on the capital program would not --
5
an efficiency -- stretch factor on the capital program
6
would not result materially in a change in our behaviour
7
towards how we executed that capital program.
8
9
MR. MILLAR:
Do I take that to mean that -- well,
you're -- I think you're proposing there be less incentives
10
for productivity under custom IR than under IRM, in that
11
you're not applying the stretch factor to everything?
12
Would that be a fair way to characterize it?
13
taken your answer as to why you think that's appropriate,
14
but that's the ultimate outcome of your proposal; is that
15
fair?
16
MR. FRALICK:
And I have
No, I think there are unique risk
17
challenges on the nuclear side that are also relevant here
18
compared to hydroelectric, so for example, where
19
hydroelectric has variance accounts to address certain
20
unknown risks, and rightfully so, nuclear, on the other
21
hand, is strictly 100 percent variable.
22
So it's risk exposure, risk profile, is materially
23
different than what it is on the hydroelectric side,
24
notwithstanding the technology differences and the risk
25
associated with nuclear risks as opposed to hydroelectric,
26
and that's gone into in great detail in our Concentric
27
cost-of-capital report, attachment 12C2
28
MR. MILLAR:
Okay.
C1-1-1.
But you're not without protection
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on the nuclear side.
2
the nuclear side.
3
MR. FRALICK:
4
MR. MILLAR:
6
we will discuss.
Well, there is the midterm review, which
7
MR. FRALICK:
8
MR. MILLAR:
9
MR. FRALICK:
11
We do, but none with regards to
production.
5
10
You have many deferral accounts on
Your proposal -There's none currently in effect.
Okay.
We are seeking that the midterm review,
yes.
MR. MILLAR:
Madam Chair, I just have one or two quick
12
more questions on this area and then it would be
13
appropriate for a break if that's --
14
MS. LONG:
15
MR. MILLAR:
16
Yes.
Okay.
Are you familiar with the Toronto
Hydro custom incentive regulation decision?
17
MR. FRALICK:
18
MR. MILLAR:
At a high level.
Okay.
I reproduced a page of it from --
19
page 25 of the compendium, and I don't have much of a
20
question here other than to point out at least in that case
21
the Board was resistant to the idea of excluding capital
22
from the stretch factor in a custom IR.
23
You've already given many reasons why you think OPG
24
shouldn't have a stretch factor applied to capital.
25
there anything you want add in light of the Toronto Hydro
26
decision?
27
28
Is
I just thought I'd put it to you, in fairness.
MR. FRALICK:
I think exploring the portfolio
management approach, as I discussed with panel 3, would be
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helpful to further understand how that portfolio is managed
2
to the view of stretch factor not being meaningful
3
incentive, if it were to be applied on that.
4
the point that distributors, their capital program is
5
discretely different from nuclear.
6
faces very significant safety and regulatory requirements,
7
training requirements that is are indeed incremental to
8
what the distributors would face.
9
I reiterate
The nuclear industry
And thirdly, our rate design, again going back to the
10
fact that it's a 100 percent variable rate design.
11
a distinct difference for OPG relative to the distributors.
12
MR. MILLAR:
That is
Finally on this point, let's imagine the
13
Board was inclined to consider a stretch factor on capital.
14
Its a not always obvious how that would work.
15
there's two ways that leap to mind for me.
16
I guess
One would be you could use the stretch as an offset to
17
the revenue requirement impact of new capital spend over
18
the test period.
19
straight offset to the capex number itself.
20
Or alternatively, you could use it as a
Do you have any thought -- I know this isn't in your
21
proposal, but if the Board wanted to go that way, do you
22
have any thoughts on what the best way to implement that
23
would be?
24
MR. FRALICK:
25
MR. MILLAR:
26
27
28
We have not turned our mind to that.
Madam Chair, would this be an appropriate
time for a break?
MS. LONG:
It would be, yes.
We'll break for 15
minutes.
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--- Recess taken at 3:02 p.m.
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--- On resuming at 3:20 p.m.
3
MS. LONG:
4
MR. MILLAR:
5
I have some questions now about your proposed nuclear
Mr. Millar, are you ready to continue?
Yes, I am.
Thank you, Madam Chair.
6
annual reporting.
7
established a number of reports and measures that OPG would
8
be required to file on an annual basis in the 2010-0008
9
proceeding?
10
MR. PUGH:
11
MR. MILLAR:
12
And you will recall that the Board
That's correct.
And essentially you propose to continue
filing this material throughout the test period.
13
MR. FRALICK:
14
MR. MILLAR:
Yes.
Can I ask you to turn to page 27 of the
15
compendium.
16
propose to report on?
17
MR. FRALICK:
18
And I think you've listed here the things you
That's correct, yes.
That's out of
A132, yes.
19
MR. MILLAR:
Yes, that's right.
20
Could I ask you to flip the page to page 28.
Is this
21
the format you would be filing in, in other words, showing
22
quartiles, or would it just be the raw numbers?
23
MR. FRALICK:
24
MR. MILLAR:
25
I'm not sure.
If I told you Staff's preference would be
for quartiles would you have an opinion on that?
26
[Laughter]
27
MR. PUGH:
28
MR. MILLAR:
We would be happy to help.
Okay.
Thank you.
And in terms of -- we
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see here things are broken out by Pickering and Darlington.
2
Is it your proposal to continue reporting on that basis?
3
MR. FRALICK:
4
MR. MILLAR:
Yes.
Would you be willing to file -- we'll get
5
into this in benchmarking, but the three key metrics are
6
generally thought to be total generating cost, the WANO
7
nuclear performance index, and the UCF, the unit capability
8
factor.
9
10
11
12
Would you be willing to report those on a company-wide
basis, an OPG-wide basis?
MR. FRALICK:
Well, on a company-wide basis -- you
mean you're referring to nuclear only --
13
MR. MILLAR:
14
MR. FRALICK:
15
MR. MILLAR:
16
MR. FRALICK:
Yes --- I'm assuming.
That's right, nuclear.
I'm not sure how we break that down.
17
would have to talk to panel 3 about the specifics of how
18
they calculate their metrics.
19
20
21
22
23
MR. MILLAR:
Okay.
We
If that's practical is there an
objection to filing that?
MR. FRALICK:
We don't -- if it's practical we don't
have an objection.
MR. MILLAR:
Okay.
Thank you.
If we can turn to
24
pages -- or page 31 of the compendium.
You'll see at the
25
top of the page you propose to file what are called
26
normalized numbers.
27
normalized, but I think for reporting purposes you propose
28
to file normalized numbers, or do I have that right?
You calculate normalized and non-
Maybe
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you haven't said how you plan to report?
2
question is, are you filing normalized or non-normalized
3
for Darlington?
4
MR. FRALICK:
I guess my
Yeah, just looking down at line 8 there.
5
We are proposing to compare Darlington's TGC on a
6
normalized basis.
7
MR. MILLAR:
Okay.
And I apologize to the Board
8
Panel.
We haven't gotten into exactly what normalized
9
means, but just for the purposes of our discussion here
10
today it's a mechanism you've developed to sort of correct
11
for the fact that Darlington will be under refurbishment
12
for essentially the entire test period, and you've adjusted
13
the denominator to reflect that.
14
MR. FRALICK:
Yeah, that's right.
So the extent to
15
which Unit 2 is out of service now, it would be
16
contributing -- expected to contribute a certain amount of
17
megawatt hours in a given year.
18
It's not, so we would add that back into the denominator.
It's on refurbishment.
19
Now, it's not a perfect correction to adjust on a
20
benchmarking basis, but it's something that we're proposing
21
that's easy to do.
22
MR. MILLAR:
Understood.
And we'll get into the
23
details of that more with panel 3, I believe, but for
24
reporting you propose to file normalized numbers?
25
MR. FRALICK:
26
MR. MILLAR:
27
28
Yes.
Do you have an objection to filing
normalized and non-normalized?
MR. FRALICK:
No.
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MR. MILLAR:
Okay.
Thank you.
If we look at page 33
2
of the compendium, you propose to file your targets for the
3
coming year?
Do you see that at the very top?
4
MR. FRALICK:
5
MR. MILLAR:
Yes.
Is there any opposition to providing as
6
well the variance between your last target and actuals?
7
other words, in 2018 -- when 2019 comes you'll have actual
8
figures for 2018, but you'll also have what your target had
9
been for 2018.
I'm wondering if there is any opposition to
10
filing the delta between what you predicted and what your
11
actuals were?
12
MR. FRALICK:
I don't believe so.
Subject to any
13
issues that panel 3 would have.
14
But again, without any principal reason to object we
15
wouldn't have one.
16
MR. MILLAR:
They have got the numbers.
And is the reporting going to be done on
17
a year-by-year or an annual basis or on a rolling average
18
basis?
19
MR. FRALICK:
The reporting would be done on an annual
20
basis.
21
based on rolling average data.
22
benchmark works within the ScottMadden methodology.
23
However, the metrics, where indicated, would be
MR. MILLAR:
And that's how the
With respect to the timing of this, maybe
24
you can help me with this.
25
the test period.
26
your 2017 numbers?
27
MR. PUGH:
28
In
Let's look at the first year of
For 2017, when would you expect to file
Your annual report for 2017?
If the purpose is going to be to include
benchmark quartile data, that may take some time.
We'll
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probably have the actuals early in the year.
2
on the benchmark that's coming from ECG or from WANO, that
3
might take several months into the next year to have that
4
comparator.
5
6
7
MR. MILLAR:
But depending
Yeah, that's what I understood.
the raw data earlier than the quartile data?
MR. MAUTI:
That's definitely true.
And I'm not
8
exactly sure when the WANO data for some of your
9
operational measures would be available.
10
We get
MR. MILLAR:
And I guess we'll see how this shakes
11
out, but assuming that there is a significant delay between
12
those two numbers being available, is there any opposition
13
to filing the raw data first and then updating it with the
14
quartiles when that comes in?
15
16
17
MR. MAUTI:
Again, principally, no, it's just, it's a
matter of when those data points are available.
MR. FRALICK:
For example, we filed the 2016
18
ScottMadden benchmarking report as an attachment to an IR,
19
so that was in the October time frame, so it's quite some
20
time through the year before that ScottMadden methodology
21
would be complete.
22
MR. MILLAR:
Yeah, that's why I was asking, because I
23
understand the raw data is available much earlier than
24
that, and I think Staff wants the quartiles, but we don't
25
necessarily want to wait eight months or whatever the time
26
period may be.
27
Thank you.
28
But I think we understand each other.
So I'll move on to my next area, which is the midterm
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review.
2
of the compendium.
3
And in that light perhaps we could turn to page 36
Yes, thank you.
And just to frame this issue to remind us what we're
4
talking about, your proposal is that a review be conducted
5
at the midterm of your test period, and the purpose of that
6
review will be limited to updating your nuclear production
7
forecast plus the clearance of your year-end 2018 balances
8
for certain DVAs; is that right?
9
MR. FRALICK:
Yes, just to be clear, the midterm
10
review in terms of updating the production forecast is
11
separate and distinct from the clearance of the deferral
12
and variance accounts.
13
MR. MILLAR:
14
MR. FRALICK:
Okay.
So in other words, if the midterm review
15
is not ultimately accepted, we would still intend to file,
16
to clear our deferral and variance accounts --
17
MR. MILLAR:
18
MR. FRALICK:
19
MR. MILLAR:
20
MR. FRALICK:
22
MR. MILLAR:
But if your proposal is accepted as
Yes.
And the review would take place sometime
in the first half of 2019?
24
MR. FRALICK:
25
MR. MILLAR:
26
-- at this time.
filed, this would all be one proceeding?
21
23
That's helpful.
That's what we're proposing, yes.
So it would apply to the first two-and-a-
half years of the test period.
27
MR. FRALICK:
28
MR. MILLAR:
That's right, yes.
Okay.
So it's DVAs in the production
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forecast.
2
historically you've had some difficulty in meeting your
3
production forecast?
4
If we turn to page 40, it's fair to say that
MR. FRALICK:
As outlined in chart 2 and further
5
explained below, yes, we have had challenges meeting our
6
production targets.
7
MR. MILLAR:
And in fact since -- from 2008, 2015, I
8
don't think you ever hit your -- first of all, neither the
9
Board-approved production forecast or indeed your own
10
applied-for production forecast, although it's been pretty
11
close in some years.
12
MR. FRALICK:
13
MR. MILLAR:
That is correct.
And if we flip back to page 37 of the
14
compendium, you list a number of factors here starting at
15
the bottom of page 37, that make forecasting your
16
production over a five-year term difficult; you present
17
some challenges.
18
So I would like to go through those with you.
19
first is the risk of public policy changes; do you see
20
that?
21
MR. FRALICK:
22
MR. MILLAR:
23
24
The
I see that.
Is there anything new there?
I read
through it.
MR. FRALICK:
No.
It's just inherent risk something
25
in the realm of public policy could occur that we have not
26
currently anticipated, and that would have an impact on
27
production.
28
MR. MILLAR:
The reason you're seeking an ability to
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update the production forecast in this case -- not to put
2
words in your mouth, but I assume the five years is the
3
problem here.
4
that would be less of a risk?
5
If this was one or two year test period,
MR. FRALICK:
Yes, thanks for that.
We have
6
historically set our nuclear production forecast in rates
7
on, at most, two-year basis and this would see us setting
8
rates on 30 months at the outset, and then re-setting that
9
again for the second 30 months.
10
11
12
So it would still be an extension of what we have
historically set our production forecast on, but yes.
MR. MILLAR:
Okay.
Similarly, if we flip to page 38,
13
items IV and V, regulatory requirements and approvals and
14
ageing facilities, this is all steady state, right?
15
is nothing particularly new in this application that we
16
wouldn't have seen in previous applications.
17
have always been around?
18
MR. FRALICK:
There
Those risks
We have faced regulatory uncertainty.
19
Given the state of Pickering's endeavours and Pickering
20
standard operations, and then leading into Pickering end of
21
commercial operations, we know there is a particular
22
regulatory requirement that we're going to have to meet, so
23
there could be some risks associated with that that we
24
today don't foresee.
25
MR. MILLAR:
Sure.
But that would have been true of
26
your last application as well.
27
difference here is the length of the forecast.
28
MR. FRALICK:
I guess the chief
The length of the forecast, yes.
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MR. PUGH:
And I think for the ageing facilities as
2
you get closer to the end of your life.
3
consultation here with respect to incentive regulation,
4
they talked about the ageing curve being an S-curve, and as
5
you get towards the end of your life, you have a lot more
6
variability in your production.
7
MR. MILLAR:
When we had a
Sure, but you've identified different
8
risk categories for both Pickering and Darlington, so I
9
assume those would be captured under those headings.
10
MR. PUGH:
Certainly the ageing facilities would be
11
more particular to Pickering, as it nears the end of its
12
life.
13
MR. MILLAR:
Let's talk about Pickering.
You see that
14
at the bottom of page 37 and the top of page 38, one of the
15
risks you highlight is Pickering extended operations and
16
you state -- this is again at the very bottom of page 37:
17
"Canadian Nuclear Safety Commission approval is
18
still required and as discussed elsewhere in the
19
application, OPG has not yet completed work
20
necessary to confirm that the Pickering units
21
would be fit to operate beyond 2020."
22
23
So that's a risk you identify with your production
forecast?
24
MR. FRALICK:
25
MR. MILLAR:
It is, yes.
Let's flip to page 41 of the compendium.
26
This is a press release issued by OPG on January 11th of
27
2016.
28
it states a quote from Mr. Lyash:
And if you look down to the second last paragraph,
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"Our technical work shows that Pickering can be
2
safely operated to 2024, and that doing so would
3
save Ontario electricity customers up to
4
600 million dollars, avoid 8 million tons of
5
greenhouse gas emissions, and protect 4500 jobs
6
across Durham Region."
7
Mr. Lyash appears to be fairly confident here that the
8
plant will operate 2024.
9
and/or contrast that with what I've just read you about
10
Pickering.
11
12
I'm wondering if you can compare
MR. FRALICK:
If you read the very last sentence
at the bottom:
13
"Any plan to extend Pickering's life would
14
require approval of the CNSC."
15
So that's the only thing we are referring to.
16
MR. MILLAR:
17
18
well.
It was caveated in that press release as
That's fair enough.
If we go back to your list of risk factors, this time
19
page 38 of the compendium, the last one is the execution of
20
the Darlington refurbishment program.
21
highlighted risks around whatever delays there may be would
22
have a significant impact on your production forecast.
23
that fair?
24
MR. FRALICK:
25
MR. MILLAR:
It could, yes.
Right.
And again you've
Is
It could go either way.
If we go to page 42 of the
26
compendium, I don't know if this is the same press release,
27
but it was issued the same day.
28
OPG, and in the very first paragraph:
It's a press release from
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"OPG is well positioned to deliver the DRP on
2
time and on budget.
3
world's top performing nuclear stations.
4
put in years of detailed planning,
5
of the art training facility, assembled an
6
excellent team and partnered with top companies
7
from across Ontario."
8
9
Darlington is one of the
We've
built a state
This press release -- I know it's a not regulatory
document, but it doesn't highlight any -- you seem fairly
10
confident here that everything is going to go well with the
11
DRP.
12
MR. FRALICK:
We've just heard five and a half days of
13
testimony with regard to the Darlington refurbishment
14
program and the complexities associated with that, the
15
risks associated with it the P90 considerations.
16
I won't rehash all of that, but there is a significant
17
amount of risk associated with the execution of this
18
project.
19
nothing short of misleading.
20
And to portray that this is a done deal would be
MR. MILLAR:
Okay.
I agree with you; we've heard
21
plenty about the risks of Darlington over the past couple
22
of days, so I won't ask any more on that.
23
However, if there is a delay in restarting Unit 2,
24
this would have a very significant impact on your
25
production forecast in 2020 and 2021?
26
MR. FRALICK:
Potentially.
You'd have to run
27
different scenarios because as Unit 2 delays, then the Unit
28
3 start would delay, and Unit 1 at the back end may push
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off into the next term.
And there's these warranty outages
2
on Unit 2 that play into the mix here.
3
So the actual production impact varies and is very
4
dependent upon just how much and what direction the DRP
5
changes by.
6
MR. MILLAR:
That's a fair comment.
Certainly there
7
are scenarios where it could have a very significant on
8
your production forecast?
9
10
11
MR. FRALICK:
MR. MILLAR:
MR. FRALICK:
13
MR. MILLAR:
15
How would it work in the other direction
that would increase production forecast?
12
14
In either direction.
If it was done early.
Wouldn't you be shutting down Unit 3
early?
MR. FRALICK:
You would, but then you'd be -- there
16
would other outages that play into the mix.
As I said, I
17
don't want to get into the scenarios here in a
18
hypothetical, but we could look at a given scenario, and
19
have looked at some of these where if it's early by this
20
much or late by that much.
21
There's many moving parts is the bottom line.
22
MR. MILLAR:
That's fair enough.
The midterm review;
23
you are proposing to -- outside of a DVA analysis, you're
24
proposing to adjust your production forecast only, and you
25
are not proposing to have any look at revenue requirement;
26
is that right?
27
MR. FRALICK:
28
MR. MILLAR:
That is correct.
Yes.
And if I look at page 38 of the
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compendium, the page we were already on, do I understand if
2
you look starting around line 23, that its a your view that
3
-- well, I'll just read it:
4
"Subject to the OEB concluding that rates are no
5
longer just and reasonable pursuant to the Act,
6
the regulation does not entitle the OEB to
7
revisit those approved revenue requirement
8
amounts during the five years."
9
10
11
And then you go on to say there is no such limitation
for production.
So do I understand you to be suggesting that the
12
regulation prevents the Board from reviewing the revenue
13
requirement after it's been set in this proceeding?
14
MR. FRALICK:
Yes, that's our interpretation of the
15
regulation.
16
requirements for five years.
17
It requires that the Board establish revenue
MR. MILLAR:
Now, in your adjustment of the production
18
forecast, imagine we do as you've proposed.
As a midterm
19
review, you adjust the production forecast.
You're also
20
proposing to make consequential adjustments to your fuel
21
costs?
22
MR. FRALICK:
We are indeed, and we're doing that
23
fundamentally because the fuel is an absolutely direct
24
marginal cost, and any fluctuation in production forecast
25
would have a direct impact on fuel cost and, quite frankly,
26
it would be wrong for us to not update for fuel cost.
27
28
MR. MILLAR:
I understand the rationale behind it.
But is fuel cost an O&M expense?
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2
MR. FRALICK:
I believe that's where it's captured,
yes.
3
MR. MILLAR:
It's part of revenue requirement?
4
MR. FRALICK:
5
MR. MILLAR:
It is part of revenue requirement, yes.
In your view, is there a carve-out in the
6
reg that allows for adjustments to revenue requirement if
7
they're related to fuel costs?
8
9
MR. FRALICK:
It was a principal position we've taken
with regards to the fact that fuel is a direct marginal
10
cost, and we felt it would be wrong for us to exclude that
11
from an update on production.
12
MR. MILLAR:
Okay.
It would be disingenuous.
Let's imagine that there is some
13
type of problem with Unit 2, it's delayed for some reason
14
-- and I take your point that that doesn't necessarily
15
result in a lower production forecast.
16
scenario where that does happen.
17
But let's imagine a
So you find two years in that your production forecast
18
is too high.
19
have the production forecast lowered.
20
obviously the ultimate impact of that would be to raise
21
payment amounts, is that fair?
22
So you come to the Board and you apply to
MR. PUGH:
If that happened,
The actual impact of that would be recorded
23
in a variance account that we proposed -- I think you have
24
it in the compendium.
25
midterm review variance account.
26
MR. MILLAR:
But it would be recorded in the
That's right.
So it goes into a variance
27
account, but ultimately that would serve to increase
28
payment amounts.
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MR. PUGH:
2
MR. MILLAR:
Once it's cleared.
Yeah.
You're right that it wouldn't
3
happen at the review, but at some point that -- those
4
monies would be recovered from ratepayers.
5
MR. PUGH:
If the Board approved a lower forecast to
6
reflect that, then that would be the implication of it,
7
yes.
8
9
MR. MILLAR:
Okay.
But in your view the Board is not
able at the same time to update the revenue requirement to
10
reflect the fact that Unit 2 is not in rate base, that
11
there may be different O&M costs associated with that.
12
That would be outside of the scope of the review in OPG's
13
proposal.
14
MR. PUGH:
15
MR. MILLAR:
That's correct.
Similarly, let's imagine a scenario where
16
you don't get CNSC approval for Pickering beyond 2020.
17
would -- in that scenario you would come in to seek to
18
adjust your production forecast downwards?
19
MR. FRALICK:
You
I think in the event of something as
20
dramatic as that to OPG's plans we would be coming into the
21
Board in any event.
22
MR. MILLAR:
Is that because it would trigger the 300
23
basis points off-ramp, or is there some other reason you'd
24
be --
25
MR. FRALICK:
Well, similar to what we've said in GEC,
26
I think 464, whereas in the event that an off-ramp is
27
triggered we would come back to the Board, that's not part
28
of an application cycle or part of the midterm review
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2
proposal.
But that is -- it would be a very significant event
3
that would fundamentally change the outlook on the company,
4
and we would come back to the Board and seek direction in
5
that event.
6
MR. MILLAR:
Okay.
I was going to save my off-ramp
7
questions, but you've brought it up.
So I had understood
8
you to say that the reg prevents the Board from adjusting
9
revenue requirement, and I'm trying to square how that
10
would mesh with the idea of off-ramp.
An off-ramp would
11
require a review of the revenue requirement.
12
And I understood you to say the rate prevented that,
13
so I just, I want to understand why it's okay if there is
14
an off-ramp.
15
MR. FRALICK:
Are you referring -- like, in my
16
previous description of off-ramp, it was as the -- in the
17
context of DRP, in that language.
18
are you referring to off-ramps within the context of the
19
RRFE?
20
MR. MILLAR:
When you say off-ramp
Well, OPG's proposal in this case for
21
nuclear is, there is an off-ramp if your earnings are plus
22
or minus 300 basis points --
23
MR. FRALICK:
24
MR. MILLAR:
Okay.
-- off the forecast.
That's the off-ramp
25
I'm talking about.
And I guess I wanted to see how this
26
squared with your assertion that the regulation does not
27
allow the Board to revisit the five years of revenue
28
requirement once it has set that for this proceeding?
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MR. FRALICK:
In terms of the applicability of the
2
off-ramp, OPG is not seeking unique treatment with regards
3
to how an off-ramp would work as a mechanism under any
4
incentive regulation.
5
MR. MILLAR:
I understand that.
And if this is a
6
matter for argument, that's fine.
7
position to be that you can't change revenue requirement
8
after it's been set in this proceeding because of the
9
regulation.
10
11
But I understood OPG's
There is no similar regulation for anybody
else.
So I just wanted to understand how there could be off-
12
ramps if the regulation permitted adjustments to revenue
13
requirement.
14
MR. SMITH:
I think this may be a matter of argument.
15
I mean, it will obviously depend on the overall caveat as
16
to whether or not the Board determines under section 78.1
17
the resulting rates are just and reasonable, Mr. Millar.
18
MR. MILLAR:
19
answer might be.
20
OPG's room (sic) that there is an absolute prohibition on
21
any adjustments to revenue requirement after it sets rates
22
through this proceeding.
23
actually say that.
24
Well, and that's what I expected the
So I take it that it's OP -- it's not
Certainly I don't read the reg to
But as you fairly pointed out in your application --
25
you do say subject to the OEB concluding that rates are no
26
longer just and reasonable, so maybe we're talking
27
ourselves into a circle here, but I don't read that to say
28
that once the OEB sets just and reasonable revenue
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requirements for five years it is forbidden from ever
2
looking at that again.
3
MR. SMITH:
Does OPG agree with that?
I think the fairest articulation of the
4
position is the one that's at page 38 of your compendium,
5
set out at line 23.
6
7
MR. MILLAR:
All right.
to argument.
8
All right.
9
production forecast.
10
Well, we can leave the rest
compendium.
Just let me get back to forecasting, your
Could we go to page 39 of the
So at about line 9 you state:
11
"In general it is more difficult to forecast
12
events further into the future.
13
increases further when the subject matter of the
14
forecast is inherently certain."
15
16
This difficulty
And I think that's what you were speaking to earlier,
Mr. Fralick; is that right?
17
MR. FRALICK:
18
MR. MILLAR:
Yes.
So no doubt there are risks in predicting
19
the production forecast out five years.
20
you, though, is, you seem to be very comfortable in
21
forecasting your revenue requirement out for five years.
22
Why is that easier to predict than your production
23
forecast?
24
MR. FRALICK:
My question to
Not to be facetious, but I don't think
25
we've said anywhere that we're comfortable with forecasting
26
our revenue requirement out five years.
27
is put an application before the Board which is -- has
28
endeavoured to match the Board's intentions and directions
What we have done
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with regards to OPG's regulatory construct and framework
2
for the next five years, so it's a custom incentive
3
regulation for nuclear and an IRM for hydroelectric, and
4
we've only sought to apply changes where it's appropriate,
5
and in the case of the midterm review, that is a very
6
significant area of risk for the business.
7
highlighted on chart 2 and F -- E211 that it has been a
8
historical challenge for us.
9
production forecast window from 24 to 30 months in this
You've rightly
We are increasing our
10
proposal.
11
unparalleled state of the nuclear life cycle that we're in
12
within OPG, both at Darlington and at Pickering, we feel
13
that it's not an unreasonable request to come in and seek
14
to update the nuclear production forecast, given the fact
15
again that we have a 100 percent variable rate design.
16
We are accepting some risk.
MR. MILLAR:
Given the
And I apologize if I put words in your
17
mouth.
I didn't mean to do that.
18
suggest that OPG had said it was easy to forecast revenue
19
requirement out five years, but when we went through the
20
list of risk factors that you'd identified for production
21
forecast, the five factors, is it fair that those apply
22
equally to the forecasting of revenue requirement?
23
MR. FRALICK:
24
MR. MILLAR:
And I didn't mean to
Sorry, what page was that again?
That is on page 37 and 38 of the
25
compendium.
26
these would all apply to revenue requirement as well?
27
28
I mean, generally speaking, it seems to me
MR. FRALICK:
I mean, they would have different
impacts, but I think they would all be considerations that
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would have to be taken into account in terms of the
2
revenue-requirement impact.
3
MR. MILLAR:
They could.
You've proposed -- we discussed -- you're
4
proposing a deferral account, the nuclear production
5
variance account.
6
tracked, assuming the Board found there were any
7
differences?
8
MR. PUGH:
9
MR. MILLAR:
That's where these differences would be
Midterm account, yes.
Yes, sorry, the -- yeah, the midterm
10
nuclear production -- I might have described it wrong, but
11
it's going into a variance account?
12
MR. PUGH:
13
MR. MILLAR:
It is.
Does that variance account actually have
14
to be made now -- there wouldn't be any entries until after
15
the midterm review; is that fair?
16
MR. PUGH:
That's fair.
17
MR. MILLAR:
18
MR. FRALICK:
19
MR. MILLAR:
Okay.
That's correct, yes.
And finally, I don't know if you'll be
20
able to answer this question or not, but I'll put it to you
21
so I don't lose it.
22
regulation on rate smoothing, and it now appears to
23
incorporate DVA balances and the Board's consideration of
24
how to smooth.
25
MR. PUGH:
26
MR. MILLAR:
There have been some updates to the
Are you familiar with that?
Yes.
And you'll be proposing, if your proposal
27
is accepted, you'll be looking to clear DVA balances as
28
part of the midterm review.
And I just want to know if
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you've given any thought to whether the regulation will
2
impact that any way, would it include a proposal for
3
smoothing of those amounts, or if the regulation -- if
4
you've had any thought about that?
5
MR. FRALICK:
Yeah, in our interpretation of the
6
regulation we understand that the consideration of deferral
7
and variance accounts for hydroelectric and nuclear would
8
be utilized in the determination of the smoothing of the
9
nuclear payment amount in a major application, so -- and
10
where we are now for the next five years.
11
When we come in the midterm to seek clearance of the
12
deferral and variance accounts, as I understand the Board
13
has mechanisms to consider with regards to the overall
14
impact that any of those riders could have on customers, be
15
that spreading the disposition over a longer period of time
16
or whatnot.
17
18
19
So I don't believe that the regulation is at all in
conflict with that.
MR. MILLAR:
And I wasn't suggesting it was in
20
conflict.
21
regulation result in changes in the way that you present
22
the DVA balances for clearance, and if this is a better
23
question for the rate smoothing panel, or if you don't know
24
yet, that's fine.
25
thought to that.
26
27
28
I guess my question was more, will the new
MR. PUGH:
I just wondered if you had given any
First of all, I do think it's a better
question for the rate smoothing panel.
MR. MILLAR:
Okay.
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2
MS. LONG:
Mr. Fralick, are you on the rate smoothing
panel?
3
MR. FRALICK:
4
MS. LONG:
5
MR. FRALICK:
6
With additions?
Yes, Lindsay Arsenault is also on that
panel with us.
7
MR. SMITH:
8
MS. LONG:
9
We all are.
There is an addition, yes.
And the mechanics of how this is all going
to work are going to be --
10
MR. SMITH:
11
MS. LONG:
Filed tomorrow.
-- explained to us.
I'm waiting with bated
12
breath.
13
and you'll take us through this?
14
lot of questions about the actual mechanics of this are
15
going to work in the context of what we've talking about
16
now.
17
18
19
But I understand it's going to be filed tomorrow,
MR. SMITH:
You understand we have a
I understand there will be many questions
about this.
MR. FRALICK:
In an effort to be responsive in our
20
impact statement, we have -- we will be including a number
21
of interrogatories that we will be updating because a
22
number of scenarios were requested.
23
24
25
So we hope that that will be illustrative of the
impact of what the new rate smoothing proposal will do.
MR. SMITH:
To be clear on that, there were IRs asked
26
on the last methodology.
We've updated all of those.
They
27
are attachments -- they will be attachments to the evidence
28
that's being filed tomorrow.
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MS. LONG:
I don't want to derail Mr. Millar's cross-
2
examination here, but have you, Mr. Smith, had any contact
3
from any other intervenors who are looking to delve deeper
4
into what's filed as of Wednesday?
5
I guess we can deal with it on Thursday, based on
6
what's filed, whether or not you anticipate that there will
7
be more interrogatories asked, or these updated
8
interrogatories may be sufficient.
9
10
I guess we'll hear from people on Thursday or Friday,
once they've had a chance to review the material.
11
MR. SMITH:
12
MR. MILLAR:
We have not had any contact, no.
Thank you, Madam Chair.
I'm actually
13
finished with my cross-examination, so thank you very much,
14
panel.
15
16
17
MS. LONG:
Mr. Tolmie?
Do you have some questions for
this panel?
MR. TOLMIE:
I had submitted a compendium.
But in the
18
interests of getting on with the job and shortening the
19
time, I would like to simply respond to your invitation to
20
bring up the storage issue for this particular panel, if
21
that's okay.
22
MS. LONG:
You can pose a question.
I don't know what
23
the question is, and I don't know if this is the proper
24
panel to answer it.
25
we'll see what it is.
But you can ask your question and
26
CROSS-EXAMINATION BY MR. TOLMIE:
27
MR. TOLMIE:
28
What we discussed earlier today is the
concept that the base load generation currently exceeds the
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actual demand for power on average in Ontario, and that's
2
giving rise to problems right now.
3
If you look at the price record over the past several
4
years, there have been many occasions in which the price
5
has gone negative.
6
exceeding the demand, right?
7
MR. FRALICK:
8
MR. TOLMIE:
That indicates that the supply is
Yes.
Okay.
But every day of the year for many
9
years now, the night time price for electricity has gone to
10
a very low value, typically close to zero, is that correct?
11
MR. FRALICK:
I wouldn't be able to speak with
12
authority with regards to the trend in the HOEP.
13
that it varies quite a bit.
14
What it is on a given day, or its trend, I don't know if I
15
could speak with any specificity.
16
panel could.
17
not experts in.
18
19
I know it's not a high number.
I don't know if any OPG
That's an IESO type of an area that we are
MR. TOLMIE:
You're aware, though, that it goes
through a big trough every night?
20
MR. FRALICK:
21
MR. TOLMIE:
22
I know
Certainly.
Okay.
And OPG gets paid per megawatt
hour of energy actually delivered, is that correct?
23
MR. FRALICK:
24
MR. TOLMIE:
That's correct.
Okay.
Now, if you look at the numbers
25
that come from IESO, the surplus generation over average
26
demand is something like 43 hundred megawatts.
27
quite a bit.
28
That's
But if you look at what's happening with the policies
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in Ontario, they're trying to reduce the consumption of
2
fossil fuels in particular, and those fossil fuels are
3
being used to heat homes.
4
-- most of the cooling of that comes from the electricity.
5
So if the government and industry succeed in reducing
And part of the heat and cooling
6
the demand for electricity for heating purposes, the
7
potential is to the order of 5700 megawatts, which brings
8
up the possibility that you may be facing a deficit of
9
demand over supply of around 10,000 megawatts in the not
10
too distant future.
11
demand for a lot of the power that you're committing to
12
produce; is that possible?
13
MR. FRALICK:
14
MR. TOLMIE:
15
MR. FRALICK:
16
17
18
MR. TOLMIE:
20
MR. TOLMIE:
23
24
Is it significant if it's possible?
Is it significant if it's possible?
Would that have an impact on your revenue
then?
MR. FRALICK:
22
I don't know.
10,000 megawatts is significant.
19
21
In other words, there would be no
I don't know.
Would it have an impact on the
appropriate rate setting for this Board to determine?
MR. FRALICK:
That level of change in provincial
demand has not been reflected in our application.
MR. SMITH:
Madam Chair, I simply ask for guidance.
25
don't know what to do with Mr. Tolmie's question, other
26
than these seem like broad system planning questions.
27
don't have a witness panel to address them.
28
-- nor do I think, frankly, OPG is the right party to
I
We
If there are
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2
address them.
To the extent we want Mr. Tolmie to ask the questions,
3
there is an IESO witness.
I don't want that person to be
4
put on the spot.
5
we can say when we have certain evidence responsibilities
6
that are outlined in the schedule that we talked about at
7
the outset of this.
But on the other hand, I don't know what
8
If Mr. Tolmie wants to ask any question about any of
9
the evidence that OPG has prepared, we're certainly happy
10
11
12
13
to take those questions.
MR. TOLMIE:
If it has an impact on the rate, should
it not be something that would be considered by the Board?
MS. LONG:
Mr. Tolmie, I think to the extent you have
14
a question about what this panel is giving evidence on, so
15
if you related your question to production forecast, that
16
is something they can ask answer a question on.
17
18
19
You can ask questions about what they considered in
putting their application before the Board.
That is fair.
But to talk about system wide planning, that's not
20
something that this panel is charged with answering
21
questions on.
22
MR. TOLMIE:
The IESO person that's going to talk
23
about the Pickering system, as I understand, which is
24
really a different --
25
MS. LONG:
The IESO witness, we were very clear in
26
our procedural order that they are going to speak to the
27
analysis they've done, and I'm going to constrain parties
28
to speak about -- to ask questions about what was filed and
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not have other scenarios that the witness is going to do
2
system planning on the spot.
That is not the intention of
3
the IESO witness being here.
He is going to speak to that
4
report.
5
MR. TOLMIE:
That was my assumption, so it really
6
doesn't provide an opportunity to raise an issue that I
7
think is fundamental to setting the rate.
8
9
MS. LONG:
Well, this rate hearing may not be the
forum for you to raise the issues you want to discuss.
I
10
want to get back to this witness panel, and whether or not
11
you have any questions to ask them of the evidence they've
12
given and they're responsible for.
13
MR. TOLMIE:
Well, as you suggested, one of the
14
questions is with regard to future projections for demand
15
for your services.
16
MS. LONG:
17
18
So do you have a question related to that,
a specific question that this panel can answer?
MR. TOLMIE:
Does the plan to reduce that demand, by
19
eliminating the requirement for both fossil fuels and
20
electricity for thermal applications, have an impact on
21
your estimates?
22
MR. FRALICK:
Our application has not factored in any
23
significant system demand reductions, or the impact
24
thereof, in the next five years.
25
26
MR. TOLMIE:
That's what I was driving at, that the
production may not be precise.
27
MS. LONG:
Thank you, Mr. Tolmie.
28
MR. RUBENSTEIN:
Mr. Rubenstein?
Thank you very much.
Panel, I have a
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compendium of documents, if we can mark that.
2
if the hearing panel has a copy.
3
MR. MILLAR:
4
EXHIBIT NO. K6.4:
5
FOR OPG PANEL 2A(I)
6
MR. RUBENSTEIN:
7
8
9
I don't know
K6.3.
CROSS-EXAMINATION COMPENDIUM OF SEC
Mr. Millar has asked a lot of my
questions, so -MR. SMITH:
Sorry, Mr. Rubenstein's compendium -- are
we at 6.3 or 6.4?
10
MR. MILLAR:
My mistake.
6.4.
11
CROSS-EXAMINATION BY MR. RUBENSTEIN:
12
MR. RUBENSTEIN:
Staff has asked a number of my
13
questions, so I just have some odds and ends I would like
14
to ask you about.
15
here and how you set the structure of this application,
16
specifically the structure of the nuclear side of the
17
business and the payment amounts, and as I understand from
18
the Board's direction you were required to set the
19
hydroelectric assets on an IR framework and the OPG assets
20
on a custom IR framework.
21
well?
22
23
MR. FRALICK:
I just want to go back to the beginning
Is that your understanding as
I'm not sure, when you say OPG assets --
we were required to set --
24
MR. RUBENSTEIN:
25
MR. FRALICK:
Regulate --
-- hydroelectric assets on an IRM
26
mechanism and the nuclear assets, as is stated in the
27
February 17th, 2015 letter:
28
"A longer-term approach to payment amount setting
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for the nuclear assets that focuses on the
2
parameters of -- for a multi-year cost-of-service
3
application while incorporating elements of IR."
4
5
MR. RUBENSTEIN:
I'm on page 3.
letter that we're talking about here.
I think I have this
We see this:
6
"The Board expects OPG to develop IR framework
7
for its hydroelectric assets, any custom IR
8
framework for its nuclear assets, based on the
9
principles outlined in the RRFE."
10
MR. FRALICK:
I see that, yes.
11
MR. RUBENSTEIN:
All right.
So you're set -- and your
12
proposal is for the nuclear assets to set them on a custom
13
IR basis?
14
MR. FRALICK:
Yes.
15
MR. RUBENSTEIN:
All right.
And then I just want to
16
understand what that means in your -- from your
17
perspective.
18
and how you've set them on a custom IR basis, is to set
19
them on a five -- to determine your budget for the five
20
years on a five-year cost-of-service basis, and then to put
21
in place the stretch factor on 75 percent of your OM&A.
22
I correct?
23
And my understanding, your proposal to do so
MR. FRALICK:
As it pertains to strictly the cost
24
items and the framework requirements of a custom IR, yes,
25
the cost was on a five-year basis with a stretch factor
26
that will apply to 75 percent of the OM&A.
27
28
Am
MR. RUBENSTEIN:
And Mr. Millar talked to you about
how you determine the stretch factor and why it's only
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applied to OM&A, and I just wanted to understand that a
2
little bit better.
3
As I understand for the OM&A perspective you've
4
determined that you should -- it's only appropriate to
5
apply to, I believe it was base OM&A, and -- I forget the
6
term you used.
7
MR. FRALICK:
8
MR. RUBENSTEIN:
9
Corporate support cost.
Corporate support cost, and not for
project OM&A and outage OM&A, correct?
10
MR. FRALICK:
Correct.
11
MR. RUBENSTEIN:
And as I understood your discussion,
12
it was because project and outage OM&A, there is no
13
productivities, further productivities, to be had.
14
MR. FRALICK:
I wouldn't characterize it that way.
I
15
would say that, while we strive to get better at projects
16
and outages over time, because of the fact that they're
17
discrete undertakings, we reflect the best estimate for the
18
cost for that given scope of work within our business plan.
19
MR. RUBENSTEIN:
And so it's your expectation, though,
20
you forecasted in amount, like, for 2017 and 2018 and 2010
21
and so on, so if we look at 2018, you're not going to be,
22
from today until you start doing that work, find any more
23
productivity.
24
MR. FRALICK:
Well, we will continue to look for areas
25
to improve.
With regards to where we are going to be able
26
to find incremental efficiency gains above and beyond what
27
we've outlined in our business plan, we have not yet
28
identified what those are going to be, but out of
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necessity, given the fact that the -- where we have applied
2
the stretch factor we will have limitations with regards to
3
identifying costs to that magnitude, we're going to have to
4
look wherever we can in order to come up with the extra
5
savings in order to account for the full quantum of that
6
stretch factor.
7
MR. RUBENSTEIN:
But I just want to talk, because your
8
proposal, as I understood it, is for project and outage
9
OM&A as compared to other OM&A that is covered.
It's not
10
appropriate, and I just want to focus on that.
11
took it, as I understood it, it's because there is
12
something inherently different with that type of work that
13
you won't be able to find more efficiency benefits than may
14
be embedded in that budget.
15
MR. FRALICK:
And as I
Is that correct?
I mean, without restating my testimony
16
with Mr. Millar, yes, we look to apply the stretch factor
17
to the areas of the nuclear cost that were in a steady
18
state that would be subject to efficiency gains.
19
MR. RUBENSTEIN:
So when I look at the chart that Mr.
20
Millar took you to on page 23 of his compendium, I see that
21
for 2018, so this was the first year stretch factor is
22
applied to any amount, if you take a look at the project
23
and outage OM&A, I did about $503 million.
24
that?
Do you see
Line 2 and 3?
25
MR. PUGH:
Yes.
26
MR. RUBENSTEIN:
And so if we applied a stretch factor
27
of your proposed stretch factor of 0.3, I get about one-
28
and-a-half million dollars.
Does that sound reasonable to
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you?
2
MR. FRALICK:
It's in the ballpark, yeah.
3
MR. RUBENSTEIN:
So your evidence -- and as I
4
understand is for the $503 million that you plan to spend,
5
you don't think you could find $1.5 million of savings?
6
MR. FRALICK:
What we're suggesting is for the reasons
7
we outlined earlier with our -- some of the compensation
8
restraints, regulatory and safety requirements, and other
9
things that are inherent within the base OM&A where we are
10
applying the stretch factor, we will necessarily be
11
required to look elsewhere in order to come up with that
12
savings.
13
So I'm not saying that we cannot find or won't be
14
looking to get better within those cost categories, but as
15
a category, they are much more discrete, and they do not
16
lend themselves to efficiency gains the way the base OM&A
17
cost category does.
18
MR. RUBENSTEIN:
Okay.
So I think I understand.
The
19
rationale then is more, you don't even think you can get
20
the 0.3 on everything else, the 75 percent?
21
MR. FRALICK:
22
MR. RUBENSTEIN:
23
24
this amount?
Yes.
So then it would be unfair to add in
Is that my understanding?
MR. FRALICK:
The 0.3 stretch factor applied as we
25
have accumulates over the five years and eventually totals
26
$50 million will be a significant challenge for us, yes.
27
28
MR. RUBENSTEIN:
And as I understood the evidence,
capital is also inappropriate to do the stretch factor,
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correct?
MR. FRALICK:
Yes, for the reasons that I outlined
3
earlier with Mr. Millar.
4
MR. RUBENSTEIN:
And I want to understand, the way
5
that you determined the stretch factor was using the total
6
-- was the total generating cost per megawatt hour.
7
how you determined which cohort you would be in, to
8
determine the 0.3?
9
MR. FRALICK:
That's
Yes, so it's in A132, the methodology,
10
but we took a look at Pickering and Darlington
11
independently, look at their TGC rating, what stretch
12
factor would you apply to Darlington based on its TGC
13
performance, what stretch factor would you apply to
14
Pickering based on its TGC performance, and then we
15
production-weighted those two numbers to come up with an
16
ultimate stretch factor that was reflective of all of
17
nuclear, and in the case of our pre-filed that equals
18
0.3 percent.
19
MR. RUBENSTEIN:
And my understanding about the total
20
generating cost per megawatt hour is that's an all-in.
21
That includes capital cost and OM&A cost, correct?
22
MR. FRALICK:
It is, yes.
23
MR. RUBENSTEIN:
So if we're only applying it to OM&A,
24
why is it not more appropriate to use some form of OM&A
25
costs per megawatt hour, an apples-to-apples comparison?
26
MR. PUGH:
I think it's because the metrics that we
27
have that are benchmarked for the ScottMadden methodology
28
provides a reasonable basis for comparison, and those are
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the numbers that are available, are the total generation
2
costs, and because we felt that was a reasonable
3
representation of the company, as we said earlier, that
4
we've actually adopted as a metric for our company, we
5
thought that was a reasonable basis for which to do a
6
comparison.
7
MR. RUBENSTEIN:
Can I ask you to turn to page 21.
8
This is from the benchmarking report -- the updated
9
benchmarking report, the 2016.
Sorry, 21 of the -- and my
10
understanding is you do benchmark on non-fuel operating
11
costs per megawatt hour.
12
Why isn't this the more appropriate benchmark to use?
13
MR. FRALICK:
Fundamentally it is not an appropriate
14
metric to benchmark CANDU plants on, so the fundamental
15
design benefit of CANDU is the fact that you can get away
16
with using cheaper fuel.
17
So the cost trade-off for that is that you have some
18
higher OM&A costs.
19
done and laid out over many years, is on a TGC basis.
20
So the appropriate metric, as we have
MR. RUBENSTEIN:
Sorry, I don't understand.
My
21
understanding is your fuel costs are not included in the --
22
while they're part of the revenue requirement and I guess
23
in some sense they're OM&A costs, you don't -- in the
24
categories in Mr. Millar's table on page 23 you -- it's
25
sort of outside what you consider total OM&A, correct?
26
27
28
MR. FRALICK:
In the benchmarking, it is not included
in the non-fuel operating cost category.
MR. RUBENSTEIN:
I still don't understand why, if
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we're now comparing your OM&A costs, why we shouldn't use
2
the more appropriate me metric, which is non-fuel operating
3
cost per megawatt hour.
4
MR. FRALICK:
I'll try to explain myself better.
The
5
benchmarks that we compare ourselves to, which are at the
6
front of this report, are many utilities from across North
7
America, many of which -- most of which are not CANDU.
8
9
10
11
So one of the fundamental design differences of CANDU
compared to a pressurized water reactor or boiling water
reactor is that we can utilize unenriched uranium fuel.
The trade-off in the design is you have higher OM&A
12
costs to enable that technology.
13
trade-off that costs you more on the technology side, but
14
gets you that benefit on the fuel side.
15
So you have a design
So to only extract the one piece of it and then
16
compare is not an apples to apples comparison.
17
why a TGC is an appropriate comparator for CANDU in amongst
18
a peer group that includes others in addition to CANDU.
19
MR. RUBENSTEIN:
So that is
Can I ask you to turn to page 25?
20
You also have a metric fuel cost per megawatt hour.
21
don't we just add up, I would have thought based on your
22
response, the non-fuel operating cost per megawatt hour and
23
The fuel cost per megawatt hour.
24
benefits you’re talking about, about the CANDU reactor and
25
how it has cheaper fuel costs, and you have the issues you
26
believe you have with using non-fuel operating costs, and
27
have all-in OM&A cost per megawatt hour.
28
MR. MAUTI:
So why
And then you have the
I guess one reason the company overall has
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adopted a total generating cost in terms of a comparator is
2
within the nuclear industry, the total generating cost
3
takes into account all basically cash expenditures that are
4
required to operate the plant for any given year.
5
In previous proceedings, we looked at our
6
capitalization policies and thresholds about what's
7
considered capital versus O&M.
8
actually sees through all that and actually takes a look at
9
the total cost to operate.
Total generating cost
We believe it's the most
10
appropriate way of an apples-to-apples comparative basis to
11
look amongst all within the industry.
12
So I think for that reason that's why, in terms of
13
standings us up against others, that's probably the most
14
appropriate one too use.
15
MR. RUBENSTEIN:
16
17
18
19
But it includes capital cost which
you are not then applying the stretch factor to.
MR. FRALICK:
Correct.
From a comparison perspective,
the total cost metric is the most appropriate to benchmark.
MR. RUBENSTEIN:
My understanding of the Board's IRM
20
framework and what your -- essentially your proposal with
21
respect to the hydroelectricity is sort of an I minus X
22
mechanism, correct?
23
24
25
MR. FRALICK:
Under hydroelectric, yes, we've applied
an I minus X, yes.
MR. RUBENSTEIN:
And my understanding is the X
26
mechanism that the Board uses and what you're forecast to
27
use for hydroelectric is made up of two parts, a stretch
28
factor as well as industry productivity factor, correct?
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MR. FRALICK:
Correct.
2
MR. RUBENSTEIN:
So you were asked at Energy Probe 34
3
-- sorry Energy Probe 2, on page 34, about why you have not
4
proposed a productivity factor for nuclear.
5
your response, essentially the high level -- there’s a lot
6
of work being done on Pickering and Darlington, and thus
7
the historical periods will not be reflective of the
8
future.
9
And as I read
Is that fair?
MR. FRALICK:
That's one of the reasons why.
I think
10
the subject of a total factor productivity for nuclear has
11
been one of significant discussion over the years, as OPG
12
has evolved its regulatory framework.
13
to the Board's EB 2012-0340 report, there is quite a bit of
14
discussion in there about the suitability and applicability
15
of the total productivity study for nuclear.
16
submitted some comments with regards to that report that go
17
to that extent.
18
So if you look back
In fact, SEC
So that report also itself, on page 7, I believe,
19
outlines the fact that a total factor productivity is not
20
appropriate for nuclear.
21
MR. RUBENSTEIN:
If I can ask you to turn to page 36?
22
I want to understand this question from a business planning
23
perspective of how OPG plans its operations.
24
We asked you in SEC number 1 a number of questions,
25
and we were asking you how -- in essence, about any
26
forecast or estimates you've done with respect to a number
27
of different things, but they include price levels when
28
generating becomes unproductive, or your own price levels
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2
which potentially customers to exit the system.
And your response was essentially, well, we don't have
3
any of those; we don't have any of those studies.
4
a fair characterization?
5
MR. FRALICK:
Is that
I think OPG prides itself on being a
6
low-cost electricity generator in Ontario.
7
strive to maintain that position through this application.
8
The smoothing mechanism that we will be discussing in
9
And in fact, we
panel 6 is another consideration that will be deployed to
10
minimize the impact of OPG's rates.
11
very challenging time, as you're well aware, with the
12
Darlington refurbishment, so it is a fundamental tenet of
13
OPG’s competitive advantage to retain its position as a low
14
cost provider.
15
MR. RUBENSTEIN:
I understand.
We're going through a
I want to understand
16
from a planning perspective, how do you implement that
17
process where you want to be a low cost provider, you want
18
to ensure you are competitive.
19
20
21
From a planning process, how do you go about making
sure that occurs?
MR. MAUTI:
Can you just give me some insight?
In terms of the cost to operate the
22
facilities we have and the applications we're putting
23
forward to the Board to determine our price position, the
24
IESO has information available and we have groups within
25
Ontario Power Generation that to try to assess where that
26
marketplace is going in comparison to that, and we sort of
27
look at what our weighted average price of our generation
28
is versus the price for other generators in the province.
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And historically, we've been some 35 to 40 percent on
2
average overall cheaper than all the other generation
3
within the province.
4
We look at our forecast, and what's happening through
5
our smoothing proposals and through our IRM proposals with
6
hydroelectric, and we still believe that on a forecast
7
basis, we will still continue to be significantly below,
8
somewhere in the 30 to 40 percent, based on our forecast,
9
below other generators.
10
So we do feel that we do have that price mitigation
11
aspect of what we are doing, notwithstanding the fact we're
12
trying to refurbish the nuclear station, which has its own
13
specific pressures on prices as generation comes up and
14
investments are made, and as Pickering approaches its end
15
of life.
16
There are a lot of things obviously happening within
17
the nuclear fleet in the next ten years, and we're trying
18
to navigate through that while being cognizant what our
19
position is in relation to our customers.
20
MR. RUBENSTEIN:
Is that an output of -- sort of the
21
end of the line conclusion based on the planning, so
22
essentially you've forecasted your rates and what you
23
believe you need to operate the plants and so on, and then
24
you've come to the determination that we're still lower
25
than -- we're going to be okay because we're 30 percent
26
lower than other sources, or whatever the number is?
27
that something at the top end in the planning process,
28
where you say we must ensure that we are competitive.
Or is
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Which one is it?
MR. MAUTI:
Historically, you know where you are
3
within -- it's easy to get the historical information now.
4
IESO publishes enough information and data for you to be
5
able to, at least globally, look at that.
6
forward in terms of our path that we’re taking with our
7
smoothing proposal and IRM, there’s more unknown trying to
8
forecast into the future how the rest of the marketplace
9
and the rest of the generation will play out in the
10
11
And going
province.
We feel comfortable -- not as much as when you are
12
looking backwards historically, but we do feel, based on
13
information available, at the end we would still have the
14
competitive advantage position.
15
MR. RUBENSTEIN:
Let me ask you about the off ramp
16
proposal.
17
the word standard, but it’s generally the usual 300 basis
18
point.
19
20
21
My understanding is it's -- I don’t want to use
MR. FRALICK:
We've not sought any deviation from the
definition of an off ramp in the RRFE.
MR. RUBENSTEIN:
I want to understand what you mean by
22
the -- what's going to happen when you tell the Board.
23
it your view that if you’re plus or minus 300 bases points
24
at the end of the year, you will file something with the
25
Board, or is it simply they will alert you if there is an
26
issue based on your annual triple R filings, or whatever
27
the equivalent is for OPG?
28
MR. PUGH:
Is
We would file on June 30th, which was our
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filing requirements in 2010-008, we would file our
2
regulatory ROE and the results would be there, and with
3
that we would advise the Board whether we thought that this
4
was because of a temporary activity, whether it was
5
ongoing, so we would provide them some advice, and then the
6
Board would determine whether they wanted to bring us in
7
for an application, because the RRFE said they may have an
8
application, and therefore we would provide them input in
9
order to do that --
10
MR. RUBENSTEIN:
11
MR. PUGH:
12
MR. RUBENSTEIN:
All right.
-- beyond just the 300 basis point number.
Maybe this is for the smoothing
13
panel, and I -- how is this going to work with the rates
14
being smooth?
What are we comparing 300 basis points to?
15
MR. PUGH:
What are you comparing it to?
16
MR. RUBENSTEIN:
Well, you're deferring -- as the plan
17
goes on you're smoothing, so you're not actually bringing
18
in the revenue that you would need in that year, an amount
19
goes into an account.
20
if there's a -- maybe there is no interaction between the
21
smoothing proposal and the 300 basis points.
22
MR. MAUTI:
Just trying to understand how the --
In the calculation of the regulatory ROE
23
it's based on our net income, and our net income is largely
24
driven on revenue requirement.
25
the amount through rates, think of more of a financing sort
26
of aspect of it.
27
income that would be sort of reporting in each individual
28
year.
The process of smoothing
It doesn't specifically change the net
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MR. PUGH:
That example is drawn out in your
compendium at Board Staff 271.
MR. RUBENSTEIN:
that, and this is on...
MR. PUGH:
The short is -- it's not -- the RSV has
no --
7
MR. RUBENSTEIN:
8
MR. PUGH:
9
10
Yeah, I was going to bring you to
Page --
-- income impact.
It has a cash-flow
impact.
MR. RUBENSTEIN:
So you will have a -- you will get --
11
the Board will approve a revenue requirement for a given
12
year that you're seeking as approved -- say it's exactly as
13
approved.
14
in that given year from the smooth payment amounts will
15
differ.
But the revenue that you will actually collect
16
MR. PUGH:
Correct.
17
MR. RUBENSTEIN:
And I'm just trying to understand if
18
you can help us understand the -- how this -- the
19
calculation.
20
-- how this works with this interrogatory that you had
21
provided.
22
or is it better for the smoothing panel, because this may
23
all change.
24
I know -- and I didn't fully understand the
So I was wondering if you can go through it now,
MR. FRALICK:
Well, hopefully this will sum it up, and
25
if not, Randy can fill in with the details, but if the
26
entries that OPG makes into the rate smoothing deferral
27
account affect our cash flow but they do not affect our net
28
income, so the balances that get recorded into the RSDA are
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2
recognized as income in the year that they're recorded.
MR. RUBENSTEIN:
3
to page 40.
4
would be.
5
$221.7 million?
All right.
If I can ask you to turn
You were asked essentially what the threshold
And as I see for, say, 2020, it's about
Am I -- that's my --
6
MR. PUGH:
You've got the right number.
7
MR. RUBENSTEIN:
So just based on sort of a simple
8
calculation, if Darlington Unit 2 is delayed by a year for
9
some -- and doesn't go in-service in 2020 as forecasted,
10
aren't you going to be fully offside the 221.7 million?
11
It's my understanding it's coming in to sort --
12
$4.8 billion are coming -- forecasted and will be built
13
into the revenue requirement to come in in February.
14
MR. PUGH:
Unless we had a very good hydro year, yes.
15
MR. RUBENSTEIN:
So my question is, will accounts that
16
have some sort of variance account protection on it, such
17
as the Darlington refurbishment, because of the nuclear
18
capacity refurbishment variance account, in that case would
19
you seek for the -- would you ask the Board to do anything
20
if you're 300 basis points off?
21
22
23
MR. PUGH:
We didn't understand your question.
You'll
have to try it again.
MR. RUBENSTEIN:
That's totally fine.
Considering
24
that for an example like Darlington you can be
25
significantly offside the 200 basis points but there is a
26
variance account that captures the in-service timing
27
difference, my understanding, that is the refurbishment --
28
nuclear refurbishment capacity variance account.
For other
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amounts where there is an in-place variance account
2
treatment, is that an area where you would say to the
3
Board, we don't think you need to -- we may be 300 basis
4
points off, but you don't need to worry about it?
5
MR. FRALICK:
I think I'm trying to think how to
6
answer this.
The -- where we have costs that are subject
7
to a deferral and variance account, those are still
8
recognized as revenue, so the extent to which something
9
were to occur that caused the cost to, instead of being
10
part of a revenue requirement, to flow into a deferral and
11
variance account, that would not impact our ROE.
12
would only be costs that would not flow to a deferral and
13
variance account that could potentially impact ROE to the
14
point of triggering an off-ramp in this example.
15
16
17
MR. RUBENSTEIN:
So it
I'll have to think about that, but
I'll move on.
I just want to ask just about -- quickly about the
18
midterm review.
Mr. Millar has discussed a number of
19
aspects of that.
20
originally filed the production forecast for the second
21
half there would be an update as well as the consequential
22
fuel cost, correct?
So as I understood originally as
23
MR. FRALICK:
Correct.
24
MR. RUBENSTEIN:
The deferral and variance accounts
25
will also be updated?
26
the deferral and variance accounts?
27
MR. FRALICK:
28
MR. RUBENSTEIN:
I mean, there will be a clearance of
Yes.
And as well, from the N2 update, we
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will be reviewing the D -- proposed to review the D2O
2
project as well?
3
MR. FRALICK:
That's our proposal, yes.
4
MR. RUBENSTEIN:
And you went with Mr. Millar, and Mr.
5
Millar took you through to a number of risks that you
6
thought was specific to the nuclear production element, and
7
I was wondering, had you considered how much -- what
8
component of those risks could be dealt with through the
9
Board's Z factor policy, which my understanding you still
10
11
want to leave open in your proposal?
MR. FRALICK:
Custom IR proposal?
I don't believe we looked at it through
12
that lens, but we have looked at the Z factor.
13
understand that it -- we would be seeking it for -- within
14
this application, and if we were to encounter an exogenous
15
event that would be appropriately subject to a Z factor,
16
then we would pursue recourse through that mechanism.
17
MR. RUBENSTEIN:
We
But my question was you -- Mr. Millar
18
took you through to a number of risks that were -- for why
19
you believe you needed to update the production forecast.
20
Do you recall that?
21
MR. FRALICK:
Yes.
22
MR. RUBENSTEIN:
My question to you is, did you
23
consider how those risks may be alleviated by the ability
24
to potentially come before the Board for a Z factor,
25
meaning there would be no need for a midterm review for
26
production?
27
28
MR. FRALICK:
We would assess any given event that
were to materialize through that lens at that time.
So I
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wouldn't say that we went through and imagined any infinite
2
number of possible scenarios, but, yes, we would view an
3
event through the lens of a Z factor before seeking another
4
treatment.
5
MR. PUGH:
I think, Mr. Rubenstein, one of the things
6
we did consider, as Mr. Fralick has said, we started off
7
with the RRFE, said, what can't we live with.
8
production forecast was an element of that, and then what
9
we said was, can we make it as close to custom IR as
10
The
possible.
11
So by coming up with another forecast we're again
12
subject to forecast risk for the other term, and we thought
13
that was consistent with taking on the risk of RRFE and
14
custom IR.
15
MR. RUBENSTEIN:
Can I get you to turn to page 6.
16
You're aware of the Board's handbook on utility rate
17
applications?
18
19
20
MR. FRALICK:
Yes, it was issued during our
interrogatory period last year.
MR. RUBENSTEIN:
I recognize that.
Sorry, page 7.
If I can ask you
21
to turn to page 26.
26 of the handbook.
22
And under "updates" the Board is talking about custom IR,
23
and the Board says:
24
“Updates:
25
custom IR application, the OEB expects that there
26
be no further rate applications for annual
27
updates within the five-year term unless there
28
are exceptional circumstances, with the exception
After the rates are set as part of a
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of the clearance of established deferral and
2
variance accounts.
3
expect -- address annual rate application for
4
updates of cost of capital, working capital
5
allowance, or sales volume.
6
establishment of new deferral and variance
7
accounts should be minimized as part of the
8
custom IR application."
9
For example, the OEB does not
In addition the
Do you find that the need to adjust your sales volume,
10
essentially your production forecast is an exceptional
11
circumstance?
12
MR. PUGH:
I think in the circumstances which we're
13
forecasting now, I think it's very different than anything
14
we've been through, so yes.
15
16
17
MR. RUBENSTEIN:
Thanks very much.
Those are my
questions.
MS. LONG:
Thank you, Mr. Rubenstein.
That concludes
18
cross-examination for today.
We are back on Thursday with
19
the panel 1D, Schiff Hardin.
And, Mr. Smith, I would ask
20
that you have this panel ready, just in case we do have
21
some time on Thursday.
22
MR. SMITH:
23
MS. LONG:
24
Yes, they are queued up to be available.
Good.
If there is nothing further, we are
adjourned until 9:30 Thursday morning.
25
MR. SMITH:
Thank you.
26
--- Whereupon the hearing adjourned at 4:33 p.m.
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