- SP-15 - South of Path 15 -- essentially designates the southern california area south of "path 15" transmission lines that link the two areas.
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
ADMINISTRATIVE LAW JUDGE KEVIN DUDNEY, presiding
Order Instituting Investigation on )
the Commission’s Own Motion into the )
Rates, Operations, Practices, ) Investigation
Services and Facilities of Southern ) 12-10-013
California Edison Company and San )
Diego Gas and Electric Company ) Application
Associated with the San Onofre ) 13-03-005
Nuclear Generating Station Units 2 )
and 3. ) Application
And Related Matters. ) 13-03-014
San Francisco, California
August 5, 2013
Pages 1277 - 1431
Volume - 7
Reported by: Michael J. Shintaku, CSR No.8251
Gayle Pichierri, CSR No. 11406
PUBLIC UTILITIES COMMISSION, STATE OF CALIFORNIA
SAN FRANCISCO, CALIFORNIA
I N D E X
Direct Examination By Mr. Weissmann 1283
Cross-Examination By Mr. Shapson 1284
Cross-Examination By Mr. Freedman 1305
7 Cross-Examination By Mr. Geesman 1342
Cross-Examination By Ms. George 1356
8 Cross-Examination (Continued) By Mr. Shapson 1411
9 Examination By ALJ Dudney 1413
Redirect Examination By Mr. Weissmann 1427
Recross-Examination By Mr. Shapson 1428
- Iden. Evid.
- , 8C, 9, 10, and 1305 16 11C
SAN FRANCISCO, CALIFORNIA
AUGUST 5, 2013 - 9:33 A.M.
ADMINISTRATIVE LAW JUDGE DUDNEY:
Commission will come to order.
Good morning. Today is August 5th,
2013. This is the time and place for the
Phase 1A evidentiary hearings in the
Investigation 12-10-013 and consolidated
applications. This investigation focuses on
rates of Southern California Edison and San
Diego Gas and Electric in relationship to the
outage and retirement of the San Onofre
Nuclear Generating Station, we will refer to
I am Administrative Law Judge Kevin
Dudney. ALJ Melanie Darling is not here
today because she is engaged in hearings in
another proceeding. However, she asked me to
assure the parties that she will stay
informed about these hearings via the
transcripts and webcast. Remember this
hearing is being webcast live and the archive
will be posted publicly.
This investigation has been scoped
into several phases, each of which we'll deal
with a specific category of costs and legal
authority for potentially stopping rate
recovery of those costs and provide refunds
The scope of Phase 1A which will
limit our fact finding in this hearing is
about establishing a method for calculating
the costs and replacing power due to the
SONGS outage. I use the term "replacement
power" broadly and encompass both foregone
energy sales and some types of other market
costs. Recognize that one of the issues
disputed in testimony is which types of other
market costs should be included. And for now
I will stay on that issue to develop a more
complete record on the subject.
The scope of Phase 1A does not
extend to discussion of long-term replacement
options for the generation argument about who
should bear the costs of replacement power,
which I anticipate will be decided in
Phase 3, or any 2012 operations or capital
costs of the SONGS facility.
Further, this scope does not include
actions or costs before the beginning of the
outages. It does not include discussion of
which procurement options should have been
pursued. Instead the focus is on quantifying
the costs that were incurred.
On July 22nd, I issued a set of
ground rules for these hearings. I expect
everyone here to abide by those rules so that
we may have an efficient and productive
I'd like to remind everyone of the
few of the key points. We are spending
ratepayer dollars to conduct this hearing.
Ratepayer dollars pay for the facilities,
Commission and utility staff, and intervenor
staff to the extent intervenor compensation
is sought and granted.
We should all take seriously our
responsibility to spend public's money
wisely. Therefore, we all need to stay
focused on the scope and make our questions
and answers to the point.
Questions shall not exclude
excessive introductory remarks or any
attempts to lay foundation using information
that is not in the record. After a question
is asked, the witness should be given time to
To the extent that these rules are
not followed, I will listen to and sustain
objections or may act on my own motion to
keep the record limited to relevant evidence.
As a reminder, briefs on Phase 1A
are currently scheduled for August 29th
followed by reply briefs on September 12th.
Those briefs are your opportunity to make
legal and policy items. These hearings are
only to establish material facts.
Now, we have pre-marked several
exhibits for cross-examination already this
morning. I think we'll go ahead and get the
remainder during the first break.
We will wait to mark them on the
record as exhibits are used. So please
request to mark your exhibits the first time
you use them in your cross-examination or
when introducing the sponsoring witness.
Then we'll take motions to admit exhibits
into evidence at the close of hearing.
Is there any other introductory
business before we start with the first
Okay. Hearing none, Mr. Weissmann.
Thank you, your Honor.
Good morning. As our first witness, we would call Mr. Colin Cushnie.
Mr. Cushnie, please come forward. Mr. Cushnie, please stand and raise your right hand.
COLIN CUSHNIE, called as a witness
by Southern California Edison, having
been sworn, testified as follows:
Please state your name and business address for the record.
My name is Colin Cushnie.
Last name is spelled C-u-s-h-n-i-e. My
business address is 2244, Walnut Grove
Avenue, Rosemead, California, 91770.
MR. WEISSMANN: Thank you, your Honor.
DIRECT EXAMINATION BY MR. WEISSMANN:
Q Good morning, Mr. Cushnie. And
A Good morning.
Q I'd like you to place before yourself a number of exhibits starting with
what's been marked for identification as
SCE-2. Do you have that document?
A Yes, I do.
Q And I'll direct your attention
to -- I'll direct your attention to the
portion of that exhibit beginning on page 18,
Response to Question 16, and running through
page 26, the Response to Question 20.
Do you have those portions in mind?
A I do.
Q Next I'd ask you to look at what's
been marked for identification as SCE-8.
A I have that.
Q And specifically I would ask you to
look at pages 12 through 23.
Do you have that?
A I do.
Q Next I'd ask you to look at Exhibit
SCE what's been marked for identification as
Do you have that?
A Yes, I do.
Q And, finally, what's been markedfor identification as SCE-38.
Do you have that?
A Yes, I do.
Q Now, these exhibits that we have just identified -- were they prepared by you
or under your supervision?
A Yes, they were.
Q And do you adopt them as your
A I do.
Your Honor, the witness as available for cross-examination.
Thank you, Mr. Weissmann. Mr. Shapson.
Thank you, your Honor.
CROSS-EXAMINATION BY MR. SHAPSON:
Q Good morning.
A Good morning.
Q I'm going to ask you to give a road
map here about the forced outage rate and
then about the congestion revenue rates. So
let's start with the forced outage rate. As
I understand your testimony, in various
places throughout what's been marked as your
various exhibits, you believe that the forced
outage rate should be based on a ten-year
average; is that correct?
A That's correct.
Q Okay. Actually, I should ask you
first of all, we're here to talk about power
What is your understanding of why
we care about power replacement costs?
A The Commission in its October 2012
OII has instructed as in San Diego Gas and
Electric to record in their Outage Memorandum
Accounts various categories of costs related
to the operation of San Onofre. Among those
costs were costs that the Commission loosely
referred to as "power replacement costs."
And there were three categories of
costs we were asked to capture in our OMA.
The first category was replacement
generation, which in my testimony I refer to
as replacement energy. The second category
costs were foregone energy sales. Those
would be sales that we could have made had
the power plant been operating since it was
not operating we could not make.
And the third category of costs
were all those costs, market-related costs
that the utility incurred to maintain
reliable electric service for its customers.
And I referred to that as either other or
miscellaneous costs in my testimony. And it
includes capacity-related costs.
Q Are you aware of the Commission
ever disallowing power replacement costs this
A I'm generally aware of some very
nominal disallowances for -- in the case of
Southern California Edison, for power plant
outages that the Commission found Edison was
unreasonable in its operation and therefore
assessed a disallowance based on some form of
power replacement cost calculation.
Q Are you aware of any differences
between the calculations that we use in those
cases and the calculation that you presented
in your memorandum account?
A Again, I'm just generally aware
that the disallowances that the Commission
did adopt were based primarily on energy-
related assessments. In other words, they
looked at the lost energy production and
multiplied it by and assumed energy price to
come up with a disallowance whereas in this
case, in Phase 1A, we're not talking about
disallowances. We're talking about
categorizing and estimating costs pursuant to
the instructions in the OII.
And there we're capturing broader
categories of costs than we did for previous
disallowances. So in addition to energy,
we're looking at foregone energy sales.
We're looking at capacity-related costs. And
we're looking at other market-related costs
that are associated with the outages of San
Q Okay. Thank you for that
The ten-year average -- what do you
base the need for a ten-year average on?
A The nuclear power plant has been in
operation for an extended period of time.
And like any large piece of equipment, you'll
have periods of time with power plant. It
has a very high availability factor. It runs
very well. And you will have other periods
of time where incidents occur to prevent the
power plant from operating for a period of
So we felt that ten years was a
reasonable period of time that would capture
both the periods of time where the power
plant was run very well and other periods of
time where the power plant had extended
Q Did you make the decision to use a
A It was my decision to adopt a
ten-year average. My support team had
actually recommended that we look at the
entirety of the power plant operations. And
I felt that was too long. I felt that ten
years was long enough.
Q When they made that recommendation
to look at the entirety of the plant, did
they present you with forced outage rate for
that period of time?
A No, they didn't.
Q Did you learn the forced outage
rate for any periods other than the ten-year
A In developing the testimony, we
were aware that a shorter duration period
would result in a lower forced outage rate.
But that was just became obvious in looking
at the data. It wasn't -- our selection of
the ten years was not intended to achieve
Q Did you look at a 15-year average?
A Not specifically.
Q Do you know what the 15-year
average would be?
A I do not.
Q Do you know what a 20-year average
A I do not.
Q Do you know what the 20-year
industry average is?
A No, I do not.
Q In your testimony, you quote the
ten-year industry average, correct?
A That's correct.
Q So just so I'm clear, so you picked
the ten-year average without knowing what the
number would be? ]
A That's correct.
Q Now, I understand that there were
two outages between -- in '05 -- I'm sorry.
There was one outage for about three weeks in
'05, and another outage for about a month and
a half in '06.
Are you aware of those outages?
A I am aware that there were two
outages that a DRA witness recommended be
excluded from a ten-year forced outage rate
calculation because they were of a longer
duration than the other outages.
Q Okay. You don't believe that those
should be excluded as outliers because of
A Because they happened and they
represent the actual availability of the
power plant over the ten-year period.
Removing those two outages would
result in an artificially low availability
rate compared to what the plants were
actually able to operate at over that
Q Okay. And so as I understand it,
you believe the ten-year average is more
useful than the five-year average because it
has a larger sample size.
A That's correct.
Q Okay. Thank you. I want to ask
you a few questions about Congestion Revenue
First of all, let's -- well, let's
start really simple. What's congestion?
A Congestion occurs on the
transmission paths when there is more energy
trying to be transmitted across the path to a
Q What's revenue?
A Revenue is associated with
Congestion Revenue Rights. Congestion
Revenue Rights are a financial instrument
that Cal ISO makes available to market
participants either through allocation or
auction. And the older of that Congestion
Revenue Right is entitled to either the
revenues that are associated with that CRR
instrument or they're obligated to pay the
costs that are associated with that CRR
instrument. You receive revenues when there
is a congestion cost on the line, and you
have to pay when there is a CRR benefit, if
you will, or a congestion benefit, if you
will, on the line.
Q Okay. You sort of jumped ahead. I
was actually going to ask you about
Congestion Revenue Rights. I was just asking
you about revenue right then.
So I take it that your prior answer
is essentially your definition of Congestion
A Yes. Congestion Revenue Right is a
financial instrument that obligates the
holder to either pay or receive the costs of
the congestion on a particular path,
depending on the direction of the congestion.
Q And, well, can we make an agreement
that CRRs or Congestion Revenue Rights are
3 the same thing --
A Yes, they are.
Q -- for purposes of these --
A CRRs are an acronym for Congestion
Q Thank you. So the CRRs are --
well, how are they acquired?
A Most of Edison's CRRs are acquired
through an allocation process. The
California Independent System Operator
allocates CRRs on a year ahead basis and a
month ahead basis. And low-serving entities
are entitled to put in nominations for CRRs
at various generation nodes.
Edison can also will acquire CRRs
through auction. The Cal Iso auctions off
remaining CRRs after the allocation process
to all market participants. And Edison does
seek to acquire CRRs through the auction
process and sometimes sells CRRs through the
Q The monthly CRRs are acquired or
allocated each month. The ones that are
acquired each month are about 25 percent of
the total CRRs; is that correct?
A I don't recall the specific number
off the top of my head, but it is a fraction
somewhere in the 25 to 30 percent range.
Q Okay. Thank you. That would be a
fair estimate, then.
Q I think you used the phrase
"congestion node." Is that the same as the
A I don't recall using the term
Q I apologize. Let me start again,
Did you use the phrase "congestion
A I do not recall.
Q Okay. And the CRRs that Edison
acquired on an annual basis for 2012 were
acquired before the outage occurred at SONGS;
A That's correct.
Q And CRRs that would be acquired for
2013 would be acquired on an annual basis
A It occurs over several rounds of
allocation and auction. Typically, the
process starts in September of the year
preceding the CRR annual year and concludes I
want to say at the end of October, early
November. I don't have the dates in front of
Q Do you know if Edison acquired any
CRRs for 2013?
A I do not.
MR. WEISSMANN: Objection, your Honor. Scope.
Let's focus --
I'm sorry. May I respond?
ALJ DUDNEY: Sure.
It's my understanding
that we are here to evaluate the methodology
of calculating power placement costs for the
entirety of the case, not just for 2012.
For now, let's focus on
the method for 2012. And if we -- depending
on how things go later on in the case, if we
need to open the question of whether the
method for 2013 would be different, we will
do that later. But for now, let's just focus
on 2012 to be consistent with all of the
previous rulings and scope.
Do you have a question, Mr. Shapson?
Well, it wasn't my understanding of what we were doing here
today. I appreciate, your Honor, that we're
sort of, in a colloquial sense, dealing with
damages before liability, but we're working
on, as I understood it, the methodology --
not necessarily the number, but the
methodology for figuring out what those
damages would be should eventually the
Commission find liability.
Right. I agree with that.
But for this hearing let's focus on 2012, and
we'll come up with the formula for
determining that number for 2012. And if at
a later date we think it's necessary to
expand that time horizon beyond 2012, we will
Thank you, your Honor.
May I have a minute,
then, your Honor?
Sure. Let's take a moment, then, off the record.
(Off the record.)
On the record. Go ahead.
If it please the Court, I
would like to reserve a little time at the
end because I may need to tweak some of my
cross, given the Court's guidance.
And just to make sure I
understand, that's at the end of Mr.
At the end of Mr.
Cushnie's testimony, yes. Thank you, your
ALJ DUDNEY: All right.
Q Mr. Cushnie, where are
Congestion Revenue Rights -- I'm sorry,
Mr. Cushnie, are Congestion Revenue
Rights recorded in the Energy Resource
A Yes, they are.
Q Where are they recorded in the ERRA
or Energy Resource Recovery Account?
A Are you asking what specific sub
account are they recorded in?
Q I'm sorry. Thank you for the
Where are they reported to the
Commission? I'll give you some options, if
that will help.
Are they -- potentially reported to
the Commission in the QCR, Quarterly
Compliance Report. Potentially they are
reported to the Commission in the annual
reasonableness review application. They may
be reported to the Commission somewhere else.
I'm asking if you know what vehicle
is used to report them to the Commission.
A Okay. So with that understanding,
there are actually two vehicles under which
our CRR transactions are reported to the
Commission. The first is through the
Quarterly Compliance Report, also referred to
as the QCR. That is, as the name applies, a
quarterly submittal to the Commission for the
Commission to review all of the transactions
that we did in the previous quarter to verify
that they were compliant with our AB 57
bundle procurement plan.
The costs of the CRRs are recorded
into the ERRA account, and those costs are
submitted to the Commission for costs
recovery as part of our ERRA proceedings.
Q Okay. And while we're at it, do
you know the sub account?
A I do not.
Q Do you have an understanding of the
effect that the SONGS outage had on Edison's
A I have a general understanding.
Q What is that understanding, please?
A The SONGS outage created a lot of
additional congestion in the LA Basin. That
additional congestion resulted in higher CRR
revenues to the extent that Edison was
holding CRRs on the congested paths.
Q Do you know what a power flow
A Generally familiar with power flow
Q Could you tell the Court what that
A It's an analysis performed using
fundamental models to assess the flow of
power -- electricity, if you will -- across
the grid, and it is used to assess where
constraints may occur on the grid. Those
constraints lead to congestion.
Q And I may have missed something,
but I believe that San Diego's witness
testifies about the value of doing a power
flow analysis, but you do not. Is that
correct? Or did I miss some part of your
A There is a portion of my testimony
where I indicate that a power flow analysis
could be performed or -- let me back up.
That analysis could be performed to
assess the impact of SONGS being out and what
that impact would be on congestion and the
cost of congestion; and that it would be
highly speculative because there would have
to be a lot of assumptions put into and we
don't recommend doing it.
Q Okay. Would it add to your
understanding of the effect of the SONGS
outage on Edison's CRR portfolio?
A Edison performs numerous power flow
studies in part to understand the impact of
San Onofre not being available to operate and
what that does to the power flow in the LA
Basin and its impact on market prices.
We do those analyses with many
different assumptions. You want to think
about we do a lot of iterations of those
analyses, a lot of sensitivities of those
analyses. There is not a definitive set of
analyses that we could point to that we think
would make sense in a hearing room because
the assumptions would be very much subject to
Q Thank you. Would the power flow
analysis add to Edison's understanding of the
impact of the SONGS outage on the CRR
A The power flow analyses that we've
done have added to our understanding the
impact that the SONGS outages had on our CRR
portfolio, but we haven't calculated what the
specific impacts would be. We're just
generally aware of what those impacts are. ]
Q What is your understanding,
A That the CRRs that we hold in the
LA Basin realized more revenue as a result of
the SONGS outages.
Q Do you know how much more revenue?
A I don't have that number. And,
again, it would be a large range because it
would be very assumption dependent.
Q When you say it's speculative
assumption dependent, are you aware of any
particular margin of error that that analysis
A I'm not aware of specific margin of
error. These analyses are very complicated.
Some of the variables that you would have to
account for would be the bid behavior of the
market participants, which Edison does not
have access to. So we have to make
assumptions as to how entities are bidding
their assets. We have to look at how imports
are being delivered to the California grid.
We have to look at how full network model is
changing from time to time.
So when we run our models, we're
using the latest full network model that's
available to us, but it doesn't necessarily
capture all the constraints that Cal ISO has
in their high-end market operation. So
there's a tremendous amount of moving parts
in an analysis like this to make it very
difficult to ascertain with any sort of
competence what a specific impact is of
something like San Onofre being out. We can
do a lot of analysis that says generally the
CRRs that Edison holds are worth more as a
result of the SONGS outage. But it's very
difficult to quantify how much more.
Q Have you heard the phrase
production costs model?
Q And do you understand that to be
different than power flow analysis?
A Production cost model is different
than -- people sometimes use the word
production cost model interchangeably. But I
think of production cost model as basically a
supply and demand of assessment where a power
flow model is looking at actual power flows
across the grid and identifying constraints.
But it also produces -- can also produce the
cost of congestion and market prices, if you
run it that way.
Q Has Edison performed any production
cost model analysis to help it understand the
effect of the SONGS outage on its CRR
Q Would doing so help it understand
or better understand the effect of the outage
at SONGS on its CRR portfolio?
A Not on its CRR portfolio.
Q Are you aware of CAISO publication
I believe it's call "Local Capacity Technical
A I believe that's the local area
studies that CAISO performs.
Q And SONGS is in the LA Basin area
in that analysis; is that correct?
A I think it's defined as being in
the LA Basin, but it's physically located
between the Edison and San Diego systems.
Q And do you know what a Local
Reliability Area is in the parlance of ISO
and analysis that I just brought up?
A The CAISO has defined two local
area zones for Southern California Edison.
One is the LA Basin, and the second is the
Big Creek Ventura area. And then in San
Diego service territory, the local area is
the San Diego Low Pocket.
Q And do you know why CAISO performs
these Local Reliability Area studies?
A To ensure that the grid is
sufficiently robust in the local areas
because there is a dependence on imported
generation to carry the load. They want to
make sure there's enough local area
generation to avoid system disturbances in
the event of large contingencies on the grid.
Q And is that because the LA Basin as
we've just using it the way we just talked
about is considered locally constrained -- a
locally constrained area?
A That's correct.
Thank you very much, your Honor. I just would like to reserve some
time as we discussed before.
Thank you, your Honor.
Can we go off the record to
distribute some exhibits?
Off the record.
(Off the record)
Back on the record.
While were off the record, we
pre-marked few exhibits. Mr. Freedman will
now walk us through those.
Thank you, your Honor.
During the break, we marked a series
of exhibits. I will walk through what each
of these exhibits is. We have preliminarily
marked as TURN-7 several pages from a
California ISO 2012 Annual Report on Market
Issues and Performance.
We have preliminarily marked as
Exhibit TURN-8C a Data Response by Edison to
TURN Data Request Set 9, Question 1. This is
a confidential data response that contains
Edison-specific confidential material.
We have preliminarily marked as
Exhibit TURN-9 a series of data responses by
Southern California Edison to TURN Data
Request Set 2, Questions 13A, 13B, and Data
Request Set 2, Question 19A.
We have marked as Exhibit TURN-10 a
series of Edison data responses to TURN
Set 3, Question 6A, 6C, 3, and TURN Data
Request Set 2, Question 17D.
And then, finally, we have marked as
TURN Exhibit 11C Edison Data Response to TURN
Set 3, Question 5, including tables that have
Edison-specific confidential materials.
Thank you, Mr. Freedman.
TURN Exhibits 7, 8C, 9, 10, and 11C
are marked for identification.
(Exhibits Nos. 7, 8C, 9, 10, and 11C
were marked for identification.)
Mr. Freedman, do you need
MR. FREEDMAN: I think I am ready, your
Okay. Go ahead.
CROSS-EXAMINATION BY MR. FREEDMAN:
Q Good morning, Mr. Cushnie.
A Good morning, Mr. Freedman.
Q I'd like to start with what has
been marked as Exhibit SCE-02, which is the
January 9th testimony, specifically on page
A I have that.
Q On page 21, starting on line 14
going through line 16, you refer to the price
deflation elasticity impact SONGS would have
had on market prices had SONGS been available
Is that another way of saying that
the SONGS outages caused market energy prices
to rise above levels they would have
otherwise been set at?
A Yes, except that I would say rather
than having market prices set at, it's what
market prices would have cleared at. They're
not administratively set.
Q And, in fact, are you aware that
Southern California Edison did provide a
specific estimate of the impact of the SONGS
outages on SP-15 market prices in response to
a TURN data request that was included in
Mr. Woodruff's testimony?
A Is it one of the exhibits that we
marked here this morning?
Q It is not. It is part of
Mr. Woodruff's March 29th testimony to which
you were provided rebuttal?
A Was that the July 10 testimony of
Q It is the March 29th testimony of
A Can you point me to a page
Q It would have been Attachment 2.
Let's go off the record
for a moment while everybody gets their
(Off the record)
Back on the record.
Mr. Freedman, please remind us what
exhibit we're looking at and then go ahead.
MR. FREEDMAN: We're looking the
exhibit that was pre-marked as Exhibit
TURN-2C, Mr. Woodruff's prepared direct
testimony on March 29th. And Attachment 2
has a table that is based on an Edison data
response to TURN.
Q Mr. Cushnie, have you been able to
take a look at that?
A Yes, I have.
And am I correct in understanding
that this represents Edison's estimate of the
impact of the SONGS outages on replacement
A This looks like results of a price
elasticity study that we performed to inform
our price elasticity assumptions in our
foregone energy sales calculations.
Q And you didn't provide any rebuttal
testimony, did you, on the calculations that
are contained in this attachment?
A No, I did not.
Q All right. Well, keeping that in
mind, I would like you to turn to what has
been marked as TURN-7.
This exhibit contains an excerpt
from the California ISO's Division of Market
Monitoring report on the ISO market for 2012.
Have you had a chance to take a
look at this excerpt that was provided?
A I reviewed it briefly prior to the
Q Okay. Well, I would like you to
turn to what has been -- what is marked as
page 58 of the report. It's not 58 of the
attachments, since we have mercifully
excerpted the relevant pages.
There is a section titled "Total
Wholesale Market Costs," and in particular
there is a reference at the very end of the
first paragraph to an increase of over
28 percent in gas normalized prices during
2012. Do you see that sentence?
A Yes, I do.
Q Does the report in the next
paragraph identify one of the factors
contributing to this increase in gas
normalized costs or prices as the outage of
the San Onofre nuclear plant?
A Yes, it does.
Q And do you generally agree with the
ISO's conclusions in this respect?
A I would agree that the standard San
Onofre outage is one of the contributing
factors to the higher gas normalized prices
that they report, but there were other
factors that led to higher prices as well.
Q And does this generally mean that
Edison's purchases of energy in the ISO
markets during 2012 occurred at higher prices
that were in part due to the SONGS outages?
A Yes. The market prices that we
paid in 2012 for energy delivered in 2012
were impacted by the SONGS outages and were
presumably higher because of the SONGS
Q And would these higher prices have
also been paid by San Diego Gas & Electric
for its replacement power?
A The higher prices would have been
paid by any market participant seeking to buy
energy in that market.
Q Would this include market
participants in Northern California?
A It's hard for me to say for sure at
every hour that a Northern California
customer would have paid more as a result of
the San Onofre outages, but I will
acknowledge that there were undoubtedly
certain hours where the market clearing price
in Northern California was adversely impacted
by the SONGS outages. And by "adverse" I
mean it was higher than would have otherwise
been had SONGS operated.
Q I would like you to move backwards
in the exhibit to the prior page which is
marked page 15. And on page 15 under the
subheading which is marked Other Reliability
Costs, there is a discussion of the costs
associated with the ISO's Capacity
Are you familiar with the Capacity
A Yes, I am.
Q And in the final paragraph under
Other Reliability Costs there is a statement
that in response to the SONGS outages, the
ISO used its Capacity Procurement Mechanism
to procure a total capacity of 966 megawatts
at a total cost of about $26 million in 2012.
Do you have any reason to believe
that this number is not an accurate
representation of the CPM costs incurred by
the ISO related to SONGS in 2012?
A I don't have any reason to dispute
the magnitude of the costs. I will indicate
that in the previous paragraph Cal ISO report
indicates that most of the CPM costs were
attributed to the SONGS outages. And in the
sentence you referred to, it's not clear to
me that there -- that the total of
9966 megawatts is the entirety of their CPM
purchases or just the purchases related to
what the Cal ISO was attributing to the SONGS
outages. But with that caveat, I don't have
any reason to dispute the magnitude of the
Q Well, let's go to a little bit
later in the exhibit, page 217 that's the
final page. And there is a table titled
"Table 9.9.2 Capacity Procurement Mechanism
Costs in 2012." And this table shows numbers
that add up to the number that was previously
discussed: 25.9 million, which I believe is
the same as 26 million that was stated
Where are these units located that
are in the table?
A The Huntington Beach units are
located in Southern California Edison service
territory, and the Encino Unit 4 is located
in the San Diego local area.
Q And if you read the asterisk below
the table, the asterisk states that all the
units are dispatched due to the outages of
the San Onofre generating stations Units 2
Does this clarify the source of the
A Yes, it does.
Q Does this remove some of the
concerns you had about whether the entire
amount, the 25.9 million, was attributable to
the SONGS outages?
A The reason I still have a question,
Mr. Freedman, is if you look at two
paragraphs above the table, it says.
However, while reliability
must-run payments remain low,
capacity payments related to the
Capacity Procurement Mechanism
increased. The increase in the
Capacity Procurement Mechanism
payments in 2012 are directly
related to the outage of SONGS
Units 2 and 3 which were offline
for almost all of 2012.
So when you talk about an increase,
I'm not sure if it's an increase relative to
zero or an increase relative to other CPM
costs that were also incurred in 2011.
So I do concur that Table 9.9.2 has
a summation equal to 966 megawatts, or 25.9
million, but the Cal ISO has an asterisk
there that indicates all of the units are
dispatched due to the outages of the SONGS
Units 2 and 3. I'm just not sure if this is
the entirety of all of the CPM charges.
Q So there could be additional CPM
charges that are related to the SONGS
A No. There are just additional CPM
Q Okay. I would like you to, with
that in mind, turn to will has been marked as
TURN -- Exhibit TURN-8 C. Again, this is an
Edison data response to TURN set 9, Question
A I have it.
Q And I know you are not the person
who is listed as having prepared this data
response, but are you prepared to answer a
couple of brief questions about it?
A I'll do my best.
Q Is it correct to say, if I were to
look at the confidential table which is the
second page of the data response, that these
lines on the table -- and I think I can read
the title of the table without there being a
problem, which is the title is "Capacity
Related Charges CPM Data." Is it fair to say
that these line items show Edison's estimates
of CPM costs incurred between February and
October of 2012?
A That's correct.
Q And do you know why the data ends
A Based on my understanding, Edison
did not incur any CPM charges in November and
December of 2012.
Q And although there is no sum total
provided by Edison, I would note that I did
handwrite in a calculated total. And I would
ask whether you would accept, subject to
check, that the column titled "Sum Amount,"
if you add up all those numbers, that it adds
up to a number that is handwritten at the
A I would agree to that.
Q Okay. And so if you were to -- is
it your understanding that the CPM costs that
are identified in this response are the same
CPM costs that we were discussing in the ISO
report, meaning the same types of costs?
A They would be.
Q And so if the ISO did incur the
25.9 million we were discussing previously,
this number here would reflect Edison's share
of that amount?
A That's correct.
Q And to the extent that there were
other CPM costs, meaning the difference
between this number and the 25.9 million
number, those would have been paid by other
market participants in the ISO system?
A The 25.9 million number that we
addressed earlier is what the Cal ISO is
indicating is the totality of the CPM charges
associated with the SONGS outages.
And the 13.6 million that you've
calculated here is Edison's share of those
charges. The CPM charges for the San Onofre
outages were allocated to all scheduling
coordinators in the Edison and San Diego
Can we go off the
record for just one second, your Honor?
Off the record.
(Off the record.)
On the record.
Go ahead, Mr. Freedman.
Q So I guess we can
just clarify, then, that the Sum Total amount
that was referenced that is handwritten in
the exhibit here, Edison does not consider
the total amount to be confidential; is that
A Not at this time. Not at this
Q And that total amount, then, is
13.6 million for 2012.
Q And so the delta, just to close the
loop on this, between the ISO's estimate of
costs and Edison's estimate of its costs, in
other words, 25.9 minus 13.6, that delta is
charged to other market participants or
allocated to other users of the ISO system?
A Specifically allocated under
scheduling coordinators in the San Diego and
Edison service territory.
Q So it would not be allocated to NP
15, for example, scheduling coordinators?
Q Keeping this in mind, I would like
to ask you to turn to -- I would like you to
turn to your Energy Resource Recovery Account
review of operations. It's testimony, I
believe this is SCE-3, dated July 8th.
It's actually 38.
Q Oh, I'm sorry.
Exhibit 38. And page 9 of that exhibit.
A I have that.
Q This is not a confidential table;
A It is a public table.
Q Okay. Great. So when you show in
this table, Table 17-3, Total Capacity Costs
of $33.1 million, is the number we were just
discussing, the 13.6 million, is that a
subset of this number or is it additive to
A It is a subset.
Q And what are the remainder of the
capacity related costs in this table? If you
could characterize what they're related to.
A There's two other components that
we included in our capacity related costs
calculations. The second category is what we
refer to as net standard capacity product
charges, and the third is bilateral contracts
which were entered into to substitute for the
RA capacity Unit 3 that was no longer
available due to the forced outage.
Q Okay. I would like to turn to
another topic, if we can move to your
Mr. Freedman, would this
be a good time to take a break? It's about
Let's take a ten-minute
break. And while we are off the record, for
the parties that still have more exhibits to
mark, we can work on that.
And we will come back at 10:55.
Off the record.
On the record.
Q We're in Exhibit SCE-37 and at
Table I-2 on page 8. And this table shows
replacement energy costs and replacement
energy by month; is that right?
A Yes, it does.
Q And Edison made a revision to these
calculations in the July 24th testimony
relative to Exhibit SCE-38; isn't that right?
A Yes, we did.
Q And were those revisions in
response to DRA's testimony regarding outage
rates and nuclear fuel costs?
A Yes, they were.
Q Were there any other reasons why
the numbers in Table I-2 were changed?
A There should not have been any
Q Okay. And would the same hold
true, then, for Table I-3 on the following
page which shows reporting of foregone excess
A That's correct.
Q Okay. Staying in Exhibit 37, I
would like you to turn to -- starting on page
1-5 there is a discussion of price
benchmarks, and you describe in this
testimony why you believe the DLAP, Default
Load Aggregation Point, prices should not be
the basis for computing replacement power
costs; is that right?
A Yeah. The way I've tried to
describe it in the past is that the SP-15
index price is more appropriate than the SCE
DLAP price. But we have said previously that
SCE DLAP price could be used for replacement
energy; it's just not the preferable price
benchmark for a variety of reasons.
Q Could you please explain how the
DLAP price is calculated as a general matter?
A The DLAP stands for Distributed
Load Aggregation Point, and it is the load
weighted average price that a buyer of load
will pay in the Cal ISO IFM market.
Q And is the DLAP price different for
A The DLAP price is different for
each utility service territory. So there is
an SCE DLAP, PG&E DLAP and an SDG&E DLAP; and
anyone buying their load in one of those
service territories will pay the applicable
Q You also reference on page 16 the
EZ Gen trading hub price, lines 21 through
22. Can you explain the difference between
the EZ Gen trade hub price and the DLAP
A The EZ Gen price is the generation
weighted average price that generators
receive in that existing zone. In this case
it's the SP-15 zone, so that would include
the Edison and San Diego service territories.
Q So when you refer to the SP-15
price, you're also referring to the EZ Gen
A When I refer to SP-15 for the day
ahead index, I am referring to the SP-15
zone. The index is being reported on the
bilaterally transacted prices that occur
between buyers and sellers prior to the Cal
ISO's IFM market operations which is what
gives rise to the EZ Gen price.
So EZ Gen is a Cal ISO IFM price.
SP-15 index is a bilaterally negotiated
price between buyers and sellers that precede
by a few hours the operation of Cal ISO's
Q And what entities report the day
ahead SP-15 indexes?
A Multiple market participants. But
it is voluntary. Not all entities that
transact in those markets report.
Q And what entities actually report
their market data?
A I can't tell you specifically which
market participants report to the trade
publications, but they have a fairly robust
process in place where they canvass market
Q How many vendors are there that
produce this data?
A We currently utilize Platts. I
believe there are one or two other vendors
that do it. I couldn't tell you off the top
of my head. And we also use Clearinghouse
prices, ICE, which is the
, has an index price
that we use for some of our reporting
purposes as well. We are not using it for
these calculations though, but the prices
track fairly well with the Platts day
Q Are the prices reported by the
different vendors identical or similar?
A They're typically very similar.
Q I would like you to take a look at
what's been marked as TURN Exhibit 9. And,
again, this exhibit starts with data
responses by Edison to TURN's Set 2, Question
13 A, and proceeds from there.
You're familiar with these data
responses, Mr. Cushnie?
A Yes, I am.
Q On the first page of the response
you write, in response to Question 13 A, in
the third line that SCE does not object to
the use of its DLAP prices to estimate the
cost of replacement energy; is that right?
A I say that as a follow on to my
statement which is SP-15 index prices are
more appropriate because they reflect the
daily bilateral market activity that the
precedes the daily Cal ISO IFM.
And I would also note that I was
very specific in saying to estimate the cost
of replacement energy. I did not say to
estimate the cost of foregone energy sales,
which is why we, in part, chose the SP-15
data index because it's a single-price source
that could be used for pricing both the short
position, which are the replacement energy,
as well as the long position, which is the
foregone energy sales.
If we're going to use DLAP to price
replacement costs energy, then we're going to
need to come up with some sort of
generation-based price index to calculate
foregone energy sales.
Q Could Edison use the SP-15 index to
determine the pricing for foregone energy
sales, and the DLAP for replacement energy
A Mathematically we could, but I
would disagree with that as an appropriate
premise. The SP-15 index reflects, again, a
price that buyers and sellers negotiated in
bilateral transactions. So it's a price that
buyers and sellers were going to transact
that. When we start looking at Cal ISO, we
have DLAP, which is a price at load base, and
we have EZ Gen, which is a price that
generators are paid.
But more specifically, generators
are typically paid at their generation node
price, which is often lower than the DLAP
price, as both my testimony and TURN
witness -- TURN's witness Woodruff indicated
So if we were to use DLAP, I would
recommend using potentially the DLAP adjusted
for the historical difference between SONGS,
Gen nodes when they were running, and then do
a further adjustment for the price elasticity
function. That way, you would have a load
price and a Gen price.
Q Okay. On the next page of this
exhibit, in response to Question 13 B, there
is a response that provides the difference
between the average hourly SP-15 index price
and the average hourly DLAP price for
January 9th through December 31st, 2012.
Do you see that?
A I do.
Q And according to this response
provided by Edison, the average hourly DLAP
price for this period is $30.94, as compared
to $30.20 for the SP-15 index price; right?
Q And would this mean that a switch
to the DLAP price index for replacement
energy costs only would result in an increase
in the total amount calculated relative to
the use of the SP-15 index?
A It would.
Q And on the next page of this
exhibit there is a response to TURN's Set 2,
Question 19 A. And in this response Edison
states that the SCE DLAP is a close
approximation for the SP-15 trade hub index
and is a reasonable benchmark.
Is that still your -- is that still
A One thing I think we need to keep
in mind when we look at establishing a
reasonable benchmark, is that there is no
single definitive price benchmark that can be
used in a situation like this because our
energy procurement is conducted on a
multi-year forward basis, an annual basis,
quarterly basis, monthly basis, balance and
month, daily, hour ahead, real time. So
there is a continuum of prices in markets
that we transact in.
And so for purposes of doing a
calculation, we are trying to pick a
single-price reference to do both the
estimation of the costs of replacement
energy, as well as the estimation of the cost
of foregone energy sales. ]
And what we pick from conceptual
standpoint was the data index price because
again it represents the price that both
buyers and sellers were willing to transact
at in a bilateral market prior to the
operation of the IFM.
The Cal ISO's IFM has generation
prices and they have loaded prices. And they
differ. So if we are to separately price
replacement energy and foregone energy sales,
then I would say yes, it would be appropriate
to use the DLAP for the replacement energy
and that we would have to come up with some
sort of modified generation index to
calculate the foregone energy sales.
I personally think it makes more
sense just to use a single price point given
that there's a continuum of prices that we
have here and the data index conceptually
makes the most sense.
Q And you would agree that prices at
generation nodes tend to be lower than the
DLAP prices, correct?
Q So as a general matter, is it fair
to say that the average prices Edison paid
for its load exceed the average prices that
Edison received for its generation?
A That's correct.
Q Staying in Exhibit 37, starting on
page three -- actually, starting on page two,
you discuss the definition of replacement
energy costs. This gets to some of the
discussion we've been having about the
distinction between replacement energy costs
and foregone energy revenues; is that right?
A That's correct.
Q Starting at the bottom of page two,
the very last words on the page, you state
"Traditionally a replacement energy cost
calculation would consider the incremental
fuel and or energy a utility utilized to
serve load as a result of an outage."
What do you mean by
A I'm referring to the period of time
prior to restructuring in California. At
that time, a utility like Edison would have
been fully resourced with sufficient capacity
under ownership or contract to carry all of
its load plus its planning reserves. And so
when a particular power plant was unavailable
to operate, it just meant that the utility
used a less efficient power plant to generate
the required electricity to meet its
customers' load. And that difference in fuel
burn is what the replacement power cost
calculation would have done.
Q Moving to page four, you take issue
with some of the costs that TURN has included
in its definition of replacement power. And
starting on line five and going down, you
suggest that TURN should be raising these
concerns in Phase 3 of this proceeding; is
A That's correct.
Q So in Edison's -- from Edison's
perspective, this whole discussion about
foregone energy revenues doesn't belong in
this phase of the proceeding?
A No. What I am saying here is the
Commission was very explicit as to what it
was asking Edison and San Diego to calculate
as part of their Outage Memorandum Accounts.
First thing we were to calculate was
replacement generation, which in my testimony
I refer to as replacement energy. The second
thing we were to calculate was foregone
energy sales, which we do and separately
report that in our OMA. And the third thing
was all other market costs incurred to
maintain a reliable electric system for
So we categorized the cost in
accordance with the October 2012 OII. Which
categories of costs and how much of those
costs should be subject to disallowance is
component of Phase 3 of this proceeding.
We're just doing categorization and the
estimation consistent with the OII.
Q TURN isn't proposing any
disallowance in this phase, is it?
A I'll need to go back and look at
the TURN testimony specifically. But there
were recommendations for the Commission to --
there were sort of alternative disallowance
proposals to either remove costs -- remove
base rates from rates or to remove fuel
purchase power cost from rates. I would
consider that to be a disallowance.
Q Mr. Cushnie, are you familiar with
the basic approach that was used by Edison to
estimate the cost effectiveness of the Steam
Generator Replacement Project in Application
A I briefly reviewed some material
that was presented to me this morning.
Q That was material that we
circulated on Friday to your attorneys?
Your Honor, by
agreement, TURN's not going to introduce this
exhibit which we had prepared.
Q Mr. Cushnie, I believe you're
prepared to answer a couple of very basic
questions; is that right?
A Yes, I am.
Q Is it your understanding that
Edison assumed in the analysis presented in
that proceeding that all of the power that
would be produced by San Onofre off the steam
generator replacements would provide monetary
value to customers?
A I agree the study assumed that all
the energy produced would provide a value to
Q So Edison did not in that
application model only the value of SONGS
production sufficient to satisfy its net
A It looked at the entirety of the
Q And so if Edison had presented a
cost-effectiveness analysis that used your
current definition of replacement energy
costs as the basis for the amount of
production to be valued, the results would
have been different, correct?
A If Edison only looked at the
forecast generation that would have
technically net load in a short hour
situation, then the results would have been
Q Staying in Exhibit SCE-37, let's go
back to pages eight and nine where there are
Tables I-2 and I-3.
Are you there?
A Yes, I am.
Q Again, these tables separately
identify replacement energy costs and
replacement and foregone energy sales.
And so would it be fair to say that
the amount of SONGS generation that would
have been used to meet Edison's net short
would essentially be -- let me back up for a
Did you use as the basis for these
calculations a forecast of SONGS generation
that would be the sum of the replacement
energy megawatt hours and the foregone energy
sales megawatt hours, in other words, 8.5
million plus 5.17 million?
A The sum of the replacement energy
in megawatt hours and the foregone energy
sales megawatt hours would equal to total
plant output less a forced outage rate
Q And how did you create this energy
A Edison's share of the maximum
output of Units 2 and 3 multiplied by
24 hours multiplied by the number of days
that the unit was forecast to be available to
operate less the 2.15 percent forced outage
Q Let's move to page 19, still in
Exhibit SCE-37. And starting on line three,
you respond to arguments raised by TURN about
a downward bias related to the use of -- the
debate appears to be about the with or
without SONGS day ahead position.
Can you explain what the difference
is between those two?
A Edison's share of SONGS is
approximately 1,680 megawatts. And if SONGS
is not available and nothing else changes,
then Edison's net open position will be
different by 1680 megawatts. The issue here
is because Edison was aware that SONGS was
not available, how do we isolate the impact
of SONGS not being available relative to all
the other portfolio actions that we're taking
to manage our bundled customer exposure to
So what we said here is that the
best estimate of what our net open positions
would be as a result of SONGS being out would
be those positions that existed prior to the
daily trading activity that we entered into,
which again predates precedes the IFM by
Q Well, let's go through this a
little bit more carefully in TURN Exhibit 10,
Exhibit TURN-10 that I had circulated. Maybe
we can walk through these data responses.
The first page is a response to TURN Data
Request Set 3, Question 6A.
You're familiar with these data
responses, are you, Mr. Cushnie?
Q So this first response here
essentially says that Edison computes its
day-ahead energy position every day between
5:30 and 6:00 in the morning?
A It's saying it's calculated every
day between 5:30 and 6:00 in the morning as
shown in Column C of the subject spreadsheet.
We obviously calculate our net open positions
over a continuum of time. And we constantly
updated those. But for purposes of doing
this calculation, it is just updated once at
5:30 to 6:00 in the morning.
Q I'd like you to turn to the next
page which is Edison's Response to TURN
Set 3, Question 6C. My understanding is here
Edison is saying that the computation of
Edison's net position was based in part on
physical trades conducted after the SONGS
outages began; is that right?
A Are you asking about the response
to Question 6 or something I said earlier?
Q I'm asking about the response.
A So the Response to Question 6C is
stating that all utility-owned and contract
supply physical generation resources that are
included in our residual net position
modeling in the year 2012 were executed prior
to January 31, 2012.
So, in other words, we did not
acquire any new utility-owned generation.
And we did not acquire any physical supply
resources to be included in our portfolio
that -- we did not acquire any of those
resources in 2012 for use in 2012.
We did enter into many financial
products which also have the effect of
hedging our net open position. And those
transactions were provided in a separate data
Q And we'll get there in just a
moment. This is a confidential exhibit that
we're going to get to after this.
And specifically the Response to
TURN Data Request Set 3, Question 5, refers
to physical trades, right? That's what's
referenced here at the bottom executed --
What question were you referring to?
Q We're still on
Response to Question 6C. There's a reference
here to another TURN data request that I
believe you were mentioning, Mr. Cushnie.
A Correct. I was mentioning the
financial transactions which we responded to
in Question 6D. And then there's a list of
physical trades that we executed in 2012 that
we responded with to your question TURN
SCE-3, Question 5.
And what I want to distinguish for
you here is physical trades are just the
transaction of physical products as opposed
to what we were talking about in our response
in this question, which would be the
acquisition through contract of a generation
resource that we would be able to control and
Q And in the next response which
would be the next page, Edison's response to
TURN Data Request 3, Question 3, Edison
provides some general guidance about how it
manages its net open capacity position; is
A That's correct.
Q And Edison states it uses a variety
of products, term durations, and strategies
to ratably manage its net open position for
both RA capacity and energy; is that right?
A That's correct.
Q And that includes both physical and
Q And then in the final page of this
data -- this exhibit which would be Response
to TURN Set 2, Question 17D, very last
sentence states that Edison managed its open
position using daily and forward markets.
And by "forward market," does
Edison mean purchases that were made before
Edison makes its computations of its
day-ahead energy position?
A By "forward markets," we mean those
transactions that term greater than the
day-ahead transactions that we enter into.
The day-ahead transactions that we enter into
come in two forms. There will be bilateral
transactions that we enter into, which are
the basis for the SP-15 index that we propose
to use. And then there's the Cal ISO data
transactions that we enter into which give
rise to DLAP prices to EZ Gen prices to
specific generator node prices. So here
forward markets are anything that was
transacting more than a day forward.
Q Okay. I'd like you to turn now to
what has marked as Exhibit TURN-11C. This is
a Response by Edison to TURN Data Request
Set 3, Question 5. The first page that I
will ask you a question or two about is not
confidential, though. My understanding is
that the specific data that is provided in
the following pages is confidential. I'm not
going to ask you to recite any of the numbers
or even refer to the particular numbers.
Have you had a chance to take a
look at this response?
A Yes, I have.
Q And the question asks for Edison to
provide a list of physical forward products
including prices that Edison executed between
February 1st and December 31st, 2012.
What's your understanding of the
forward transaction information that was
provided in this response? What does it
A SCE provided all the transactions
it had engaged in that were contracted more
than a day in advance of day-ahead market.
And for a term typically of a month or series
of months, there were a few balance-a-month
Q And how did these forward
transactions affect Edison's computation of
its net position?
A They would have been included in
the net open position calculation. And
therefore if we were short, we would have
been less short. If we were long, we would
be more long.
Q Then going to the actual table
itself, I assume it's okay if I ask questions
about the headings of the columns.
Q I assume that trade date which is
the first column refers to the date on which
a transaction is executed; is that right?
Q And begin and end dates -- those
are the dates where the product began
delivery and ended delivery; is that right?
A That's correct.
Q And then "buy slash sell" -- that's
an indication of whether Edison was a buyer
or a seller?
Q So is it fair to say that many of
these forward transactions were made -- some
of them were made before the outages began on
January 31st of 2012?
A Number of them were made prior to
Q And other forward transactions were
executed before Edison realized the
seriousness of the situation at Units 2
A Any time we have a power plant
outage in a nuclear facility, we think it's
serious. I need some help understanding what
line you're looking for me to address.
Q I guess it would be between
January 31st and the date -- after
January 31st, but before Edison realized that
the units would not come back on-line as
A Okay. In terms of our procurement
activity, we utilized the best information
that was available to us at the time. I
personally was in contact with the VP at San
Onofre. And he would provide periodically
his assessment as to when we'd be allowed to
return Unit 2 to service and when we thought
we could return Unit 3 to service.
In all instances, we expected to be
able to return the units to service in 2012.
And our management of the net open position
therefore was very near-term oriented. And
it wasn't until the July 7th announcement
from our CEO Ted Craver we were shutting the
plants down did we then assume that the
plants were not returning to service.
You mentioned the 7th.
I said July. Was it June 7th?
Luckily we're still in
2012 for these hearings.
Q So is it fair to say
then that as Edison managed its net open
position during the outages in 2012, that the
expected date for the units to restart
changed over the course of the year?
A It periodically changed. They were
Q And how did these changes affect
Edison's purchasing strategy?
A The changes were always of a one to
two month forward return date beyond what we
were assuming. And so when we assumed that
the unit's returning at a later date than we
had originally planned, that increases our
net short position or makes our long position
And when that gets factored into
our overall management of the portfolio,
recognizing that there's other resource
assumptions that are changing as well, other
resources may be more or less available. And
we're also looking at updated load forecasts.
So I can't attribute any specific
transaction to SONGS planning assumptions.
But clearly the magnitude of SONGS outages
created a large open position for us that we
sought to manage in advance.
Q And is it fair to say that Edison
would not have made the same amount of
forward transactions that are shown in this
data response if SONGS had returned to
service as originally anticipated?
A It's hard to say because the
implied market heat rate with SONGS out of
service was a lot higher than what it had
been when SONGS was in service, which meant
that Edison resources were then running at a
greater rate than we would have forecast.
And so there's an offset that goes on there.
And so it's not clear to me in all instances
that we would have done anything materially
different than what's on this sheet.
Q Are you suggesting that Edison ran
its own units to a greater extent than would
have otherwise occurred without the outages?
A Correct. A lot higher market heat
rate meant that resources ran greater
durations than they would have otherwise
Q And did that affect the net energy
short estimates that Edison developed?
A Correct. The units that were
running more than we thought reduced the net
short calculation and increased the long
Okay. Thank you very
much, Mr. Cushnie.
Those are all of my questions, your
Thank you, Mr. Freedman.
It's about 11:35. Mr. Geesman,
you've requested half an hour; is that
ALJ DUDNEY: So my plan would be we'll
do Mr. Geesman before lunch. And then after
lunch, we'll start with Ms. George. Okay.
Go ahead, Mr. Geesman.
CROSS-EXAMINATION BY MR. GEESMAN:
Q Good morning, Mr. Cushnie.
A Good morning, Mr. Geesman.
Q Did Edison make any attempt to
coordinate the development of its testimony
in this phase of the proceeding with San
Diego Gas and Electric?
A I would not characterize our
interaction as coordination as much as we did
share drafts in some cases shortly before
Q Did you make any effort to develop
a common methodology?
A Based on intervenor testimony, we
did have several discussions as to whether or
not it made sense to see if we could coalesce
around a common methodology. And in some
cases, we were able to reach agreement. And
in other cases, we have different
Q In those areas where your
methodologies differed, what prevented you
A Difference of opinion.
Q Difference of opinion as to what
would help the Commission in this
investigation or difference of opinion as to
what would help the particular company?
A I can't speak for San Diego Gas and
Electric. I can speak for Edison. And in
our case, where there were differences, we
believe what we were presenting made the most
sense and we believe the most understandable
for the Commission to follow.
Q When you said made the most sense,
you mean the most intellectually appropriate?
A Conceptually appropriate.
Q And would you think that the
Commission had an interest in being presented
with a common methodology?
A Typically, the Commission prefers
the parties work out differences of opinion
prior to the hearing. It reduces the amount
of factual dispute the Commission has to
entertain in a hearing. And if it reduces
the policy differences, then there is that
much less the Commission has to decide in a
Q What would be an example of an area
where you were unable to coalesce, but felt
quite strongly that Edison had the more
conceptually correct position?
A The one that comes to mind is
Edison's choice of the SP-15 data index price
as the appropriate price benchmark, and I
believe San Diego Gas & Electric is using a
what they refer to as a Cal ISO SP-15 index
price, which I think is the EZ Gen up price.
And I've explained in some earlier
testimony there is not necessarily a right
price benchmark to use, but we do believe the
use of the SP-15 data index is the most
appropriate because it is a price that both
buyers and sellers were willing to transact
that bilateral negotiations, and we are using
the price index to price both short positions
with respect to replacement energy and long
positions with respect to foregone energy
Q Can you think of another aspect of
your methodology where the two companies were
unable to coalesce, but Edison felt its
position was more conceptually appropriate?
A I want to say that there were some
differences in how we categorized grid
management charges, so it was a matter of
which bucket that you put them in. But I
can't say for sure.
Q Can I ask you to turn to the
cross-examination exhibit that has been
identified preliminarily as A 4 NR
A So I have some materials that were
presented to me prior to the start of the
hearings and don't have exhibit numbers on
Q This is one with a cover that says
"Alliance For Nuclear Responsibility
A Correct, but the version I have has
a blank exhibit number.
Q Okay. Okay. It is a -- the first
page starts with the July 31st e-mail from
Edison to me transmitting the data response
which begins on the third page of the
exhibit, and it's identified as Question 29.C
Supplemental. Do you see that?
A I have that.
Q Are you familiar with this data
A I briefly read it this morning.
Q You had no familiarity with it
prior to this morning?
A I believe my attorney sent it to me
over the weekend, but I was not in a position
to access it in a written form and so I
waited until this morning to review it.
Q You did not participate in
compiling the response to Question 29.C
A I certainly did not draft it. I
cannot recall if I reviewed it or not. I
have been reviewing many data requests in
this proceeding, and some of them are very
similar in our responses. And so I just have
a hard time recalling if I actually
specifically reviewed this one.
Q Were you involved in any
discussions last week that may have
contributed to this July 31st response?
A Not to my awareness. I may have
been involved in a discussion that maybe
someone else would provide you with this
response, but I was not asked to speak to
this particular issue where we might be
amending our response to you.
Q Are you able to answer a few basic
questions about the content of the response?
A Yes, I am.
Q Are you familiar with Mr. Craver's
June 7th prepared statement which is posted
on the Edison website in which this exhibit
excerpts two paragraphs from?
A I've read portions of it. I did
not read it in its entirety.
Q Do you know what methodology
Mr. Craver's referenced analysis used for
buying replacement power from the market?
Objection, your Honor.
As stated in the data response, our position
is that the analysis that was done at the
time is privileged. So what's been provided
here is an explanation of how Edison -- as
stated here, how Edison believes a reasonable
analysis could be conducted. But the content
of the specific analysis that Mr. Craver
referenced we contend is privileged.
Your Honor, I asked if he
was familiar with the methodology. We can
get into Mr. Weissmann's objection, if you
would like. I would ask that he explain the
basis of the privilege.
Okay. So I think,
Mr. Weissmann, I'm not sure if I fully
understand the objection. But I think
Mr. Geesman's question as he just rephrased
it, which is simply is the witness familiar
with the method, doesn't seem to raise
privilege concerns to me. So let's go
forward with that and see what else comes up.
Q Mr. Cushnie, are you
familiar with the methodology that was used
to support Mr. Craver's statement?
A I believe I was familiar with
portions of the analysis.
Q Were there any variances from the
methodology used to support Mr. Craver's
statement from that which you have used in
Objection, your Honor.
Now we're getting into the privilege, yes.
The objection is that
the content and scope of this analysis that
was referenced is privileged; it was
attorney-client and attorney work product.
And so we object to inquiry into the contents
of what that historical analysis was done.
Your Honor, simply
labeling what is clearly an economic
methodology as attorney work product seems
pretty expansive to me. There is virtually
nothing that could not fall within that
I'm asking a very focused economic
question. I don't see where the
attorney-client privilege or the attorney
work product privilege comes into play.
Mr. Weissmann, I agree
with Mr. Geesman. I don't see why this would
be an attorney product. We have an economic
witness on the stand and we're asking an
MR. WEISSMANN: Well, I think to answer
this more fully, your Honor, we need to have
a fuller context of exactly how this analysis
was carried out and to what extent it was
directed by attorneys.
Okay. Mr. Geesman?
I don't understand what
he just said.
Well, what I'm saying
is that this is an analysis that was done
that was not just an economic analysis, but
also included direction from attorneys about
assumptions to be made that touch on legal
advice, and that's intertwined with the
economic analysis that was done.
We don't really have a full record
at this point, your Honor, as to exactly what
this analysis was and who was involved in it
and how it was undertaken. And so my
concern -- my concern is is that if we start
to go down this path of revealing parts of
the analysis, we don't want to be in the
position of having been said to have waived
any privilege that might attach to any
portion of this analysis. That's our real
So I -- frankly, I don't have a
particular concern about the economic part of
it. My concern is really that it's
intertwined at some point with legal
analysis. And we don't want to be said to
have waived the privilege that might apply to
any aspect of this analysis.
All right. Mr. Weissmann,
I think I agree with Mr. Geesman in that the
objection you're stating is rather vague and
broad. But I am sympathetic to the concern.
So, Mr. Geesman, if we can try and
ask the narrow questions focused on the
economics, let's see if we can steer clear of
Mr. Weissmann's concern.
Do you think that's a possibility?
Yes, your Honor.
You can try.
As long as your Honor
makes clear that the questions that are asked
and the responses that are given are not in
your view privileged, that addresses our
Okay. That is my view,
that I think we can stay clear of privileged
issues there. And I ask you to try and do
Thank you, your Honor.
Q Mr. Cushnie, were there variances
in the economic methodology used for
calculating replacement power costs between
that which supported Mr. Craver's statement
and the methodology you've used in your
A And to help me answer your
question, is there anything specific you mean
by your term "variance"?
Q Were the assumptions identical?
A No. The assumptions would have
been very different. The analysis presented
in my testimony in this proceeding as Phase 1
A proceeding is categorizing and estimating
the market costs that the Commission has
asked us to do and report in our OMA,
replacement energy, foregone energy sales and
other miscellaneous costs associated with
maintaining a reliable electric service.
The economic analyses that were
performed that underpinned Mr. Craver's
statements had to forecast prices as opposed
to using actual prices, had to forecast how
the system would evolve without San Onofre.
Our analysis that we did here in
Phase 1 A did not forecast what the system
was doing as a result of San Onofre being
out. You know, we had to make assumptions
about gas prices, power prices, carbon
prices, how the grid might evolve in terms of
So there were a lot of planning
level assumptions that we had to make that
far exceed what we had to do for a fairly
straightforward estimation of the costs that
were incurred as a result of the outages in
Q Focusing only on 2012, what were
the material differences between the two
A The analysis that Mr. Craver is
referring to was a forward-looking analysis,
the balance of 2013 through 2022.
And the analysis in my testimony
was specific to 2012. They were very
different time periods.
Q Mr. Craver's analysis did not cover
2012 at all?
A The analysis he was referring to
was analysis that the company was using to
assess the cost effectiveness of returning
SONGS Units 2 and 3 to service.
My analysis in Phase 1 A is looking
at what the costs are that we incurred as a
result of SONGS 2 and 3 not being available,
and we have categorized them and estimated
them in accordance with the Commission's OII.
Q Did the analysis supporting
Mr. Craver's statement address 2012 at all?
A I don't believe it did. But I was
not privy to the final analysis that
Mr. Craver and the management team looked at
when they made this decision; it was not
broadcast through the company; it was kept at
a very high level.
Q Did the methodology upon which
Mr. Craver's statement was based address
foregone energy sales?
A The economic analysis -- the
economic analyses that we did to support the
cost benefit and assessment for SONGS looked
at the entirety of the production of the
Q Was that an answer of "yes" to my
A We didn't calculate it as foregone
energy sales. We just calculated it as
market value of the energy.
Q Did the methodology upon which
Mr. Craver's statement was based include the
same other market costs as your testimony
A It included capacity related costs.
I don't specifically recall that it included
any of the other costs that we talked about.
So, for example, I don't recall
auxiliary load costs being part of it; it
would have been baked into the assumption,
presumably. We certainly would have captured
PIRP costs. Congestion would have been
Q Does that complete your answer?
A At this time, yes.
Thank you very much, Mr. Cushnie.
Your Honor, I'm complete.
Okay. Thank you,
All right. It is almost noon. So
let's take lunch and come back at -- can we
come back at 1:20 and get started?
All right. And, Miss George, we'll
start with you. If you would like, I'll come
down at about one o'clock.
I can't hear you.
ALJ DUDNEY: Off the record.
AFTERNOON SESSION - 1:20 P.M.
And on the record.
Welcome back from lunch. And while
we were off the record, Miss George has
passed out a couple of WEM exhibits. I
believe the witness has those.
Miss George, when you're ready, you
CROSS-EXAMINATION BY MS. GEORGE:
Q Hello. Is this on? Okay.
Good afternoon, Mr. Cushnie.
A Hello, Miss George.
Q What procurement authority were you
operating on under in 2012?
A SCE was operating under its
Commission approved AB 57 bundle procurement
Q Okay. Well, I have looked at your
compliance filings, and it says that the
first quarter you were operating still under
the D.07-12-052 from --
A That's probably correct.
Q -- from 0612 -- whatever that was
procurement proceeding. And then in the
second quarter it said that, you know, the
D.12-01-033 had been passed and so you were
operating under that. That's correct?
A That sounds correct.
Q And is that true for the rest of
the year or did it change from then on?
A Our procurement plan has not
changed, to the best of my knowledge, since
then. There may have been a very modest
modification with respect to who we're
allowed to transaction with, but the
framework of the plan itself remains
Q And for the purposes of the
replacement resources for SONGS, are we
talking about the system need or just the
A So Edison's AB 57 procurement plan
addresses our bundled customer need.
A So the procurement that we were
doing that is part of our ERRA account
entries is for bundled customers.
Q Okay. So that's what's in the
ERRA. But in practical terms did you need to
replace any energy in the system -- for the
A No. The California Independent
System Operators is responsible for running
the markets that secure all of the energy
requirements to meet the system requirements.
As a load serving entity, Edison actually
doesn't actually have to do anything, the Cal
ISO will procure on our behalf. But we elect
to be proactive, and so we do seek to build
and maintain a portfolio for our bundled
customers that we can then schedule or bid
into the Cal ISO markets. So we're
effectively self supplying most of our
resources when we do that.
The only thing that could be
considered potentially system related were
certain activities that the company undertook
to maintain grid reliability in the South
territory. We did enhance certain demand
response programs in 2012 to increase the
amount of demand response and its ability to
respond to an emergent condition. ]
And we did do some very limited
transmission enhancements on the system. I'm
not an expert as to what we did on the
transmission side. And the balance of the
system-related activity was performed by the
CAISO in the form of doing the CPM
designations that we talked about earlier
this morning where the Cal ISO contracted for
certain generation resources under its CPM
authority to backstop San Onofre's outage.
Q All right. So the things that you
did for the South Orange County grid
reliability -- you mentioned the enhanced DR
and some transmission fixes.
Are those being charged to the
bundled customers in this exercise with ERRA?
Or are they separated out?
A So the transmission enhancements
would be part of our TAC, TAC. It's
Transmission Access Charge that the Cal ISO
charges on behalf of the utilities. So that
would be paid for by all customers that pay
Q That would not be in the SONGSMA?
That would not be recorded in the SONGS OMA?
A The OMA?
A Bear with me. I'll take a quick
look at the account entry just to verify that
we did not record it in the OMA. Actually,
at line 41, 42, and 43, it looks like there
is a transmission upgrade sub-account. And I
would imagine that the Commission ordered
Edison to do this just to keep track of our
total expenditures. But, again,
transmission-related expenditures are
authorized through the TAC, which is a
Q All right. But other system-
related -- you mentioned enhanced demand
Was that charged to bundled
customers or to the system? Or is it somehow
split between them?
A I'm not an expert on our ratemaking
with respect to demand response. Most demand
response programs, if not all of them, are
charged to all Edison system customers. With
respect to these particular demand response
enhancements that we did, I believe they
would have been charged to all Edison
customers, not just our bundled customers.
But that is something that I would have to
double-check to verify.
Q So it would be fair to say that we
have kind of a mix between the bundled and
the system. When you need it more for the
system, that was included in this replacement
A Correct. So the demand response
enhancements we did were designed to provide
very targeted I'll call it resource
contributions to the South Orange County grid
during periods of time where we would have
had high loads and were potentially facing a
transmission contingency. We would have then
been able to fall on these demand response
programs, which would have either reduced
severity of the situation or mitigated it.
These resources were not procured
to meet the energy requirements of bundled
customers or system requirement -- or system
customers. The program is for exclusively
designed as a grid reliability measure.
Q If you'll open the Neil Miller
section of the exhibit, page 507.
A Which exhibit?
Which exhibit is this,
MS. GEORGE: This is Exhibit 24.
THE WITNESS: Yeah, I show 510.
Q My recollection it's
somewhere in here -- but I'll have to
check -- is that Mr. Miller testified in the
procurement hearings last summer in 2012 that
they were interested in using demand
response, but they didn't find any that they
could actually use.
Is this the demand response program
that we're talking about?
A I can't speak to what Cal ISO's
Mr. Miller was referring to. I can address
to a limited matter what the Edison demand
response programs were that we did to enhance
grid reliability in South Orange County.
Q I think what I'm asking is whether
or not the ISO recognized that as a resource
A They did not recognize it from the
standpoint of increasing the amount of
resource adequacy capacity that was available
to load-serving entities to use to meet their
RA requirements. In terms of their emergency
operations, I'm not sure what they did to
account for this. It may have been something
that just Edison was planning on employing if
Cal ISO wasn't going to recognize it.
Q All right. So in any case, you did
conduct some demand response programs for the
replacement of San Onofre?
A We implemented some programs. I
can't tell you to what extent we called upon
them. But we did implement some programs.
Q And is that cost listed?
A We did capture those demand
response costs. For 2012, we recorded
Q And there was also a 10/10 program.
Is that the energy efficiency incentive? Or
is that a demand response incentive program?
A The 10 and 10 is a demand response
program. It's one of the four programs that
we implemented in the summer of 2012.
Q So does this 2.7 million include
the 10/10 program?
A Yes, it does.
Q Okay. One of the things that we're
considering and the Commission asked us to
consider is the foregone sales of nuclear
Can you tell me why do you think we
should be considering the financial
implications of something that didn't happen?
A In what sense do you want me to
opine on that?
Q Well, I'm asking you what does it
have to do with replacement power cost since
it didn't happen?
A So consistent with what the
Commission instructed Edison to do in its
October 2012 OII, Edison is complying with
that investigation requirement by recording
in our OMA our estimate of the foregone
energy sales revenue. What the Commission is
going to do with that estimate presumably
will be heard in Phase 3 of this proceeding.
Edison has not taken a position at
this point in time as to what the Commission
should do with any of the costs that we have
recorded in the OMA other than to say we
should be entitled to recover all prudently
incurred cost, which is what the quarterly
compliance review process and the ERRA review
process reviewed to determine and then allow
us recovery in rates.
Q So with the nuclear power costs,
the foregone sales -- would that increase the
amounts that Edison would receive?
A No. That amount that we had
calculated recorded into the OMA does not go
into the ERRA. It's just an accounting
Q Generally speaking, does Edison
follow the loading order in its procurement?
Q And does it follow the loading
order in terms of the requirement in DO
712052 to go back and look for more renewable
energy in its procurement -- more than it got
from its other programs?
A So all of us in procurement is open
to resources that meet the identified need.
So we're purchasing just energy. Any
resources that can provide energy is eligible
to bid their output to us. And we will award
based on the lowest evaluated cost. To the
extent that there's an RPS resource that
would be bidding into that solicitation, we
will give it credit for its RPS value.
The challenge we have in doing RPS
procurement outside of the Commission-defined
programs is that the Commission requires all
of our contracts to be preapproved. And
that's a very lengthy process. So if we need
energy for tomorrow, for example, I can't buy
an RPS-eligible product because I have to get
it preapproved. And we have asked the
Commission for authority to do short-term RPS
procurement. And to date, the Commission has
not granted us that authority.
Q My understanding is that there are
small providers of preferred resources that
are in a queue that had been waiting for
years and, in fact, that Edison has been sued
by one of them for not allowing them to
Is that a preapproval problem?
A I would need to know the specifics
of that situation. What I will say is that
Edison has a lot of standard procurement
programs for small renewable projects. We
refer to them as feed-in tariffs.
And to the extent that they meet
the criteria of that feed-in tariff and
they're awarded a contract, then it's
incumbent upon that resource to get on-line.
And there are resources both renewable and
nonrenewable that encounter inter-connect
challenges for a variety of reasons. And
some of those energies challenge Edison on
those inter-connect challenges that they
And so without knowing the
specifics of what I think you're talking
about, I really can't opine any more on it.
Q But there are hundreds of these
small projects in the queue; is that right?
Your Honor, excuse me.
I'm going to object on scope. I believe that
the scope of this phase is costs that were
incurred, not alternative resources that
might have been procured.
Sustained. Ms. George --
This is a question of
availability of the resources, I believe.
That's the way I'm looking at it.
Right. But the intent of
this phase is to quantify the costs that were
incurred more than to understand what other
options there could have been.
Q Were there
any preferred resources that were used to
substitute for San Onofre's power except for
the demand response programs that you
A Edison bid or scheduled all of its
preferred resources into the market on a
regular basis. Except to the extent those
resources were provided schedules by the Cal
ISO, they met a portion of system
Q When you say Edison its preferred
resources, and so these are preferred
resources that Edison already owned or had
A Most of our preferred resources are
under contract. There are very limited
amount of small hydro projects that are
considered preferred resources. And we have
a very limit amount of solar projects that
are utility-owned. So most of the preferred
resources are contracted. All of our
contracted and utility-owned resources were
bid -- were scheduled into the Cal ISO
markets and were utilized in 2012.
Q Was there a solicitation by which
new resources were allowed to compete for
replacing San Onofre?
A Other than the standard programs
that we run for renewable resources, these
feed-in tariffs that I was discussing, there
was not a solicitation that I recall beyond
Q And did you have a solicitation of
any kind for conventional resources to
replace San Onofre?
Q Why not?
A In 2012, we were operating under
the premise that San Onofre would be
returning to service within one to three
months of any given operating day. So our
planning horizon showed Units 2 and 3 --
Units 2 and 3 returning to service in fairly
And so it didn't make sense to
conduct a solicitation that would take months
to run for a need we didn't think was going
to exist. So we did our procurement as we
typically do in the shorter term markets.
And we sought to maximize the dispatch of the
resources that are in our portfolio.
Q When you decided to put Unit 3 in a
preservation mode, didn't you need to procure
resources to replace that power?
Your Honor, objection. Scope.
I'm just trying to
understand how the decisions were made about
this supposed emergency replacement problem
that they had.
---+++ MR. WEISSMANN:
My objection, your Honor, is we're getting beyond subject of the
costs that were actually incurred.
ALJ DUDNEY: Yeah.
We're actually not
getting -- you'll see I have a lot of
questions about the actual cost. But the
question of whether or not resources that
were already being paid for, in part, whether
they were allowed to participate in this
exercise of replacing San Onofre.
Okay. Ms. George, go
ahead. I think that keeping it focused on
how the resources were used and what
resources were procured is appropriate. Go
Q Does Edison design its
energy efficiency portfolios?
A Edison participates in a CPUC
proceeding on which the parameters of the
energy efficiency programs are established.
And then Edison executes on those programs in
accordance with the Commission decisions.
Q And so it does design some of the
A It proposes designs.
Q Proposes designs. And then does
Edison decide which third parties are allowed
to design and execute third-party programs?
A Parties that are conducting energy
efficiency measures outside of the utility
procurement process are free to do whatever
they want. Edison doesn't control that. For
third parties that are participating in the
utilities energy efficiency programs, then
they would have to conform with the
requirements of the energy efficiency program
that the Commission approved and that Edison
Q In other words, Edison has control
over the ratepayer energy efficiency funded
A Subject to Commission direction.
Q Subject to Commission direction.
And there are no competitors for that?
A Not that I'm aware of. Not for the
CPUC-authorized energy efficiency
expenditures that are allocated to the
utilities for administration purposes.
I'd like to refer you to
Edison's SCE-3, the ERRA testimony.
What is the number because I got
SCE-03 on one that came out in April.
Yeah. I believe for purposes of this proceeding, this hearing,
it's been marked as 38.
38, okay. Thanks.
Q This is talking about the foregone
energy sales net revenue. And there was
actually a similar quote in the very first
page about the market prices whether they're
lower. I mean, this one says the market
prices would have been lower if SONGS-based
load generation had been available to the
market. But the actual price reduction
cannot be known.
Do you see that section?
A Yes, I do.
Q And then at the end of that
sentence, it says "An estimate of the
impact" -- I'll just read the whole thing:
"The actual price reduction that
would have been realized cannot be known
because market participants would have
undoubtedly bid and operated the resources
differently in an environment in which SONGS
was not experiencing an extended outage. But
an estimate of the impact can be provided by
examining previous changes in market prices
as a result of changes in load and
What sorts of things would affect
changes in load?
A My reference here was primarily to
weather. So as temperatures change, as cloud
cover changes, as humidity changes, that will
drive a different load result. And if you
think about the market clearing function that
we have in California, at its essence, it's a
supply and demand curve. So as you move
further up the demand curve, you're paying a
higher price. As you move down the demand
curve, you're paying a lower price.
Q Are there other things that affect
changes in load?
A Obviously, demand-side management
programs can have a permanent effect on load,
if they're energy efficiency. For demand
response, if it's a permanent load shift,
that will change the load. If it's just a
callable program, then it will just have a
episodic change on load.
Q Take a look at O&M 24, page 673, at
the bottom of the page. It says "Have you
used energy efficiency funding to reduce the
needs for power in the emergency with SONGS
out of service?"
Do you see that?
A Yes, I do.
Q And you state that you didn't know
about any -- "I'm not aware of any
incremental energy efficiency programs that
the company has undertaken as a result of the
San Onofre being out of service."
Is that still your position that
you don't know of any energy efficiency that
A No. Since the time of the hearings
and long-term procurement plan, I have become
aware of four programs that the company
undertook to enhance local area reliability
in South Orange County area.
Q But those were demand response
A Those were demand response. I'm
still not aware of any energy efficiency
Q I wanted to refer you to the page
674 in that same exhibit, bottom of the page:
"Are demand side resources required to be
cost-effective, energy efficiency in
A Yes, I have that.
Q And you stated -- this is in the
procurement hearings last summer in 2012 --
that your understanding is that they're all
required to be cost-effective as defined by
And then you defined that as
cost-effective as they are cost-effective
relative to the next competing resource to
meet that particular need.
So when you say that you used
Edison's -- the resources that Edison had and
deployed them based on which one was more
cost-effective, this would indicate, would it
not, that energy efficiency was the most
cost-effective resource that you had?
Could you restate the
question? because I lost it. I apologize.
Q Given this statement in
the procurement proceeding about cost-
effectiveness, would you say that regarding
the need for replacement power for SONGS,
that energy efficiency would be the most
A I'm going to answer that question
in two parts. My testimony that you referred
to here in last summer's long-term
procurement plan proceeding was referring to
cost-effective in the context of other
resource commitments that a utility could
make. So it's a long-term resource
assessment; it's not a dispatched decision
from day to day.
From what I understand your
question to be, you were asking if because we
needed to replace San Onofre generation at
times, should we have been purchasing energy
efficiency because it's more cost-effective?
Energy efficiency programs, as I'm sure
you're aware, take a while to implement and
put in place.
Edison has limits on what it could
do with its energy efficiency programs
governed by the CPUC's authorization of our
energy efficiency spending. And so for
purposes of day-to-day procurement, there are
no energy efficiency programs available to us
to acquire relative to other resource types.
Q There are none available to you?
A I cannot buy energy efficiency for
Q How long does it take for Edison to
screw in a light bulb?
A That's not an energy efficiency
Q There are many energy efficiency
programs that involve screwing in light
A No. I understand. But energy
efficiency as defined by the Commission's
programs -- again, I'm not the expert here --
establish a minimum baseline using existing
codes and standards. And the energy
efficiency program that you implement has to
produce energy savings above that baseline
And these programs have to be
performed in accordance with the program
rules of the Commission's energy efficiency
decisions. And so when we look at something
like day-to-day procurement, we can't do
programs like that for tomorrow and the next
day. These are long-term programs that we're
Q I'd like to refer you to the I
think it's 118. It's energy efficiency --
this is the energy efficiency report from
Edison, monthly report as of January 31st,
2012. And what I've done here in this
exhibit is to spare everybody the multiple
pages of program descriptions. We just cut
to the chase, and we're focusing on the
bottom line, the actual totals of the budgets
And it's the third page down. So
in the budget, you'll see it's divided into
four pieces. And the first one is adopted
budget. And the second is the revised
budget. And then it's a program expenditures
to date. In other words, the expenditures
starting in 2010. This is a three-year
cycle. So the 2012 is the last of the
three-year cycle, as you mentioned in your
And then the fourth line was the
report month, how much was spent in that
month. And then there were -- the last one
is commitments. Those are -- commitments
means future programs.
So just focusing on the
expenditures to date and the adopted program
budget you'll see that the expenditures are
about $608 million, and the total budget is
12 -- you know, 120 million. So it's
essentially half of that money is left to be
spent in 2012, around $600 million at that
So is that more than all of the
other money that was spent on replacement
costs in 2012?
A Are you asking if the 608 million
that the company reported spent to date is
more than the replacement costs or the
Q I'm asking you to do a little
subtraction in your head. You know, how much
it spent to date was 608 million. It has a
budget of 120 million. And so 6 is half of
12. So, essentially, you've got 600 million
left to spend in 2012, minus the commitments,
of course, which are 99 -- so it's actually
500 million. But, essentially, $500 million
that is more than all of the replacement
costs; is that correct?
A So I'll answer your question this
way: Edison has calculated roughly 259
million of replacement energy expense in
2012; 131 million of foregone energy sales;
offset by 66 million of estimated costs in
replacement energy sales that would not have
been realized because the units would have
been on a planned outage.
Further, we had capacity related
costs of 33 million, and other miscellaneous
costs of 16 million. The net total of all
those are 373 million, which is less than 500
Q And you agree that energy
efficiency is cost effective compared to the
next competing resource?
Objection, your Honor. Misstates testimony.
Q Well, we had the cost
effectiveness discussion a little while ago
from the procurement proceeding. If you
don't like my paraphrase, would you like to
offer another one?
A I believe what I said were words to
the effect that energy efficiency must be
cost effective. And the Commission, as I
understand it, defines "cost effective" as
relative to another long-term planning
resource that you would otherwise install but
for the energy efficiency. It's not related
to the day-to-day procurement and dispatch of
Q All right. Well, you had Unit 3
was in preservation mode as of June. Is that
the correct date?
A I don't recall the exact date that
Unit 3 was laid up.
Q I believe that was in the time
line. Let's say give or take a few months.
It was almost half of the year. So at that
point in June, right at the beginning of
summer, you knew that that resource was not
available for the rest of the year.
So saying that you're -- that you,
you know, thought it was going to come -- you
didn't think it was going to come back on
line. So in that sense would it have been
cost effective to use energy efficiency?
Your Honor, I object to
scope. We're really getting into an
alternative procurement plan idea.
I'm going to sustain it at
this time, Mr. Weissmann.
Yes, Miss George, I think we have
strayed beyond quantifying the actual costs
I'm trying to determine
whether the energy efficiency costs are going
to be counted or not. Energy efficiency
costs were incurred.
Well, I think counsel
is pointing out other energy efficiency funds
that might have been available. That might
be an appropriate subject for the Commission
to consider in the energy efficiency docket.
But here we're focused on the costs that were
I'm sorry. If you'll let
me pursue a line of questioning, I believe
you will see that this has everything to do
with the cost of the resources.
This has to do with the
cost of the replacement resources or the cost
Yes, the cost of
replacement resources, including, you know,
whether or not you're going to count the
energy efficiency costs.
Q You know, for example, your energy
efficiency programs, are you telling us that
there was no energy efficiency done in the
West LA Basin in 2012?
A I'm not going to tell you that.
I'm not aware of anything that was
specifically done as a result of the San
Onofre outages. It doesn't mean the company
didn't do something. I'm just personally not
aware of anything that we specifically did as
a result of the SONGS outages.
Q I believe that you -- your
testimony states that any -- a resource is
not -- let me find this. It's in SCE-38,
SCE manages its bundled customer
requirements on a portfolio basis; therefore,
it does not ascribe a specific demand or need
for its individual energy related
transactions; therefore, it is not possible
to tag specific energy transactions as having
occurred as a result of the SONGS outage.
Why would you exclude energy
efficiency when you say that it is not
possible to tag specific energy transactions
as having occurred as a result of the SONGS
A So to make sure we are not
confusing concepts here, this passage that
you just cited pertains to how Edison manages
its bundled customer portfolio. So how does
Edison meet the energy requirements of its
bundled customers? How does Edison meet its
resource adequacy obligations for its bundled
customers? And SONGS is just one resource of
many that we manage.
Q And isn't energy efficiency
A Energy efficiency is managed
through energy efficiency programs. And once
those energy efficiency programs are
implemented, the reduction in load accrues to
the benefit of all benefiting customers. So
that energy efficiency savings may accrue to
customers that aren't Edison's bundled
customers; they may be direct access
customers, for example.
We account for the reduction in
load as a result of energy efficiency in our
load forecast. So we forecast lower
requirements. And if our forecasts are
correct, we will actually meter lower
requirements. And a lowered metered load
results in a lowered bill from the Cal ISO.
So energy efficiency is captured in our
portfolio of management through load
My passage here is talking about
how do we handle our resource procurement.
And our resource procurement doesn't tag
particular transactions to a cost. We have a
net open position; it's either long or short.
And so if we're short, we're buying. If
we're long, we're seeing selling. But we
don't attribute the purchase or the sale to a
particular action in the portfolio.
Q But energy efficiency reduces that
A Yes, it does.
Q And in that sense it does meet --
it is an equivalent, isn't it?
A Well, it's the highest resource in
preferred loading order. So all else being
equal, we prefer to reduce the load through
energy efficiency than to procure a supply
side resource to meet the load.
Q And but you said you didn't do that
when you had a major emergency?
A The second component of your
question is what are we doing as a result of
the San Onofre outages as it pertains to
maintaining system reliability. So from a
Q Well, pardon me.
Can you let him answer
the question, please?
Go ahead, Mr. Cushnie.
From grid reliability
perspective, Edison did do things. Edison
sought to implement demand response programs
that were within our control that were
targeted to the South Orange County area. We
did some limited transmission upgrades that
were within our wherewithal to do in a short
period of time.
The Cal ISO did their CPM
designations on a handful of resources to
make sure they were available and could
operate to maintain grid reliability, again,
in the South Orange County area. But we did
not do any targeted energy procurement
because that's a bundled customer
Q In energy procurement
or energy efficiency program?
A Energy procurement. Just general
energy procurement. We did not do anything
targeted for the loss of SONGS.
And on the energy efficiency side,
I am not personally aware of anything that
the company did to have a targeted energy
efficiency program that was outside of what
we were already authorized to do to deal with
the Summer 2012 reliability concerns. I can
surmise why we didn't, but I don't know for
Q You could surmise why you didn't?
A Why we didn't, yes. Because those
programs would not have been consistent with
the -- with the adopted energy efficiency
programs that we have from the Commission or
they would not have been able to be
implemented in a timely manner.
Q Even though that money was supposed
to be spent by the end of the year?
A The company's management of its
energy efficiency budget is governed in the
energy efficiency dockets that the Commission
oversees. I don't know what the spend
projection was that they had for the balance
I do believe that the spending that
was authorized for -- into 2012 was granted
late in the cycle; and, therefore, that may
have been why they weren't able to spend as
much as they might have otherwise been able
Q Is there any communication between
the procurement department and the energy
A There is much more communication
with the demand side management folks because
those resources are dispatched. Energy
efficiency, when the programs get
implemented, they communicate that to us so
that we can account for our load forecast.
Q You mentioned in response to
Mr. Shapson this morning that there was
congestion in the LA Basin due to the SONGS
A Correct. I said the levels of
congestion were higher post-outage than prior
to the outage.
Q And so that costs money. The CRRs,
Congestion Revenue Rights, is that a cost or
is that a benefit? I'm not clear.
A So the congestion is a cost to
generators. And if you have a CRR, which is
a Congestion Revenue Right, a financial
instrument, you get paid the cost of
congestion. And so it nets out. So if you
are a generator that incurred $10 of
congestion costs and you have a CRR that gets
$10 of congestion revenue, they net out and
you're indifferent to the cost of congestion.
Q You, as the utility, are
indifferent? Or the generator is
A The generator that holds CRR is
Q And what about the utility?
A The utility is impacted to the
extent that it holds more or less CRRs
relative to the congestion that was realized.
If we have more CRRs, then we're better off
because the higher congestion means more
revenues for our customers. If we have less
CRRs, it means that our customers incurred a
net cost increase as a result of the
Q So you're saying there is a benefit
to having a congestion situation.
A Theoretically there is a benefit if
you are long CRRs and you are basically
resource for the balance of your energy
There's a lot of other things that
you would need to consider. You can't just
look at that in isolation. But you could
conceivably be better off with congestion,
depending upon your CRR position and your net
Q Does the congestion drive up the
A Congestion drives up --
Q -- of the energy?
A It drives up the market bearing
price of energy.
Q So in that sense does the utility
see that as a benefit or as a detriment?
A Edison prefers to see market prices
be set at a competitive level, which
generally would mean lower than what we
Q And would energy efficiency reduce
A It depends. Congestion is from
point to point. And so certain energy
efficiency or supply side resources can
actually aggravate the congestion. If you
have a constrained path and you put less load
on the constrained side, then you have more
energy that is trying to move from the
constrained side to the unconstrained side,
and that will actually aggravate congestion.
So it has to be in the right location.
Q And you would know what's the right
A Generally we do. But the grid is
very dynamic. So at any given hour,
depending on what our plants are operating,
the congestion can flip on you in certain
Q So --
A So, for example, sometimes
congestion coming from Northern California
into Southern California can be quite
expensive. In the Spring, for example, when
there is a lot of hydro energy coming out of
the Pacific northwest and there are not a lot
of loads in the northwest, there is energy
flowing north to south. But in the summer,
in the old days, there would be more energy
flowing south to north.
So congestion could be north to
south or south to north, depending on the
conditions of the year.
Q So could Edison plan for a power
plant to go into any area where there was a
congestion? I mean, is that one of the
things that you could do is have a resource
that was in the right place for the
A That's our objective is to site
resources and DSM programs in locations where
they relieve congestion on average.
Q And energy efficiency can be done
almost anywhere; right?
Q So that would be very easy to
deploy in a particular location?
Q And so it could have been deployed
in South Orange County, and probably was in
these programs; is that true?
A I would imagine that our energy
efficiency programs did capture some
opportunity in South Orange County. But that
would have been done as part of the
system-wide energy efficiency programs that
we have. Orange County being part of the
system-wide requirement, would have picked up
a portion of our energy efficiency programs
What I'm not clear about is whether
we did anything targeted to South Orange
County as a result of the SONGS outages.
Q Did you keep track of what you had
accomplished in energy efficiency in South
Orange County so that you could know whether
you benefited from it or not?
A The Edison company would be keeping
track of it. My organization does not, other
than to take into account the aggregate
energy efficiency savings that we believe are
being realized because that's an input into
our load forecast.
Q Thanks. Was Huntington Beach an
effective location for replacing power from
A The Cal ISO determined that
Huntington Beach was an effective resource,
and, therefore, location to maintain grid
reliability as a result of the SONGS outages.
Q There are a number of once-through
cooling old power plants down there. Is that
the only one that was available to be
A I believe the other once-through
cooling facilities were largely available and
already made available to the Cal ISO under
the State's resource adequacy program. And
Huntington Beach 3 and 4 had been retired,
and Cal ISO brought them back for a limited
duration in the Summer of 2012 to help
enhance grid reliability in the South Orange
County region and the San Diego service
Q I would like to refer you to the
WEM-24, Dr. Hunt's testimony.
A Do you have a page number, please?
Q I'm looking for it. Hang on a
second. 861. I think it's in the end of it.
I don't have a physical copy here.
A I have that.
Q Do you see on line 4 that "AES
filed a petition with the Energy Commission
requesting the transfer of ownership of
Huntington Beach 3 and 4 from AES to Edison
Mission Huntington Beach"?
A I see that.
Q Your rebuttal testimony said that
you didn't own the resource. Is that --
would it make a difference if Edison mission
Energy did own the resource?
A Yes. Edison Mission Energy and
Southern California Edison Company are two
separate legal companies, and Edison Mission
Energy at that time was an affiliate of
Southern California Edison. Both were owned
at that time by Edison International.
The PUC has strict codes of
conflict in place to prevent the unregulated
affiliates from utilizing regulated assets to
further their business interests.
I work for Southern California
Edison, part of the regulated utility. I do
not have insights into what Edison Mission
Energy is doing, nor do I provide them
assistance in their work objectives.
Q I understand that. However, your
statement in your rebuttal testimony was that
Edison International or Edison Mission Energy
did not own Huntington Beach; and Dr. Hunt's
testimony last year was that they do. And so
what I'm asking is since that was a resource
that you -- you mentioned that the ISO
procured that resource.
So did Edison not have any contract
with the resource? Cal ISO market?
A The California Independent System
Operator issued CPM contracts to Huntington
Beach 3 and 4, and those contracts were
issued to AES. So the arrangement to run
Huntington Beach 3 and 4 were between the Cal
ISO and AES.
AES sold its ownership interest in
Huntington Beach 3 and 4 to Edison Mission
Energy so that Edison Mission Energy could
acquire some emissions offsets to build their
Walnut Creek power plant.
When Cal ISO sought to return
Huntington Beach 3 and 4 to service, Edison
Mission Energy made arrangements with AES to
return those assets back to AES to be able to
be utilized in a CPM contract with the Cal
I don't know the arrangements that
Edison Mission Energy had with AES to first
purchase the units, and I don't know what the
arrangements were to return the units back to
AES. Those were contracts that were between
those two entities, which Edison has no part
of -- Edison utility has no part of.
Q But this testimony of Dr. Hunt is
in August of 2012, and he's not mentioning
any return of Huntington Beach to AES.
A His answer at line 10 says, "Well,
I'm familiar with the ownership change. Now,
what this document doesn't incorporate is
that Huntington Beach was then leased back to
AES. And AES is now operating Huntington
Beach, not Edison Mission Energy."
I don't know whether it was leased
or sold. I just know there was a commercial
rrangement to return the ability to operate
the units back to AES.
Q Thank you. And you mentioned in
SCE-37 on page 21 -- this has to do with the
preferred resources: "So the extent that SCE
failed to meet the State's goals in this
regard, the Commission should address the
deficiency in the relevant Commission
Are you suggesting that SCE missed
A You said page 21?
Q Page 21, yes.
A And line numbers, please?
Q 1 to 3. Maybe it's 38 and not --
A No. I have the cite. I'm just
Q It's the rebuttal testimony.
A So, to begin with, no, I'm not
suggesting that Edison did not meet its
obligations or goals with respect to
utilizing preferred resources.
What I was attempting to address
was to the extent that a party such as WEM
was indicating that Edison should have done
more, that that would be a subject of review
in the applicable docket for that resource
Q Do you have the chart, the colored
chart for -- I handed those out. Here. Here
we are. These are -- should I give one to
Is this something that
was distributed in advance?
This was part of our
comments in December and it's out of the
procurement proceeding in --
Here, I'll give you one for the
Consistent with the
ground rules, your Honor, we have not been
given this exhibit in anticipation of this
cross-examination, so we would object.
All right. Mr. Weissmann,
would you care to take that a step further?
Could we -- and propose a solution, perhaps?
Could Miss George mark this as an
exhibit, and we'll talk about it tomorrow,
Well, I was hoping
Mr. Cushnie would be excused today. But
perhaps we could look at it over a break.
Miss George, would that suit you to
perhaps pursue another line of questioning?
Yeah. I can finish my
other questions and then come back to it
afterwards. That's fine.
Is the nuclear fuel -- has that
been removed from this part of the
proceeding? I'm a little confused. Are we
still talking about nuclear fuel costs here?
There was rebuttal --
there was DRA testimony and rebuttal
testimony on the subject of nuclear fuel as
it relates to the computation of the
replacement power cost.
Okay. That's what I
thought. And then I heard from someone else
that it was removed, and I thought maybe I
Q I want to ask you just a couple of
questions about the greenhouse gas costs. At
what point is SCE involved in the creation of
nuclear fuel? Do you buy it at the mine and
then take it all the way up? Or at some
A Miss George, that's not my area of
esponsibility, and I don't think I'm
competent to address our nuclear fuel
procurement practices. That was done at the
Q What about greenhouse gas costs?
Are you familiar with those?
A I'm familiar with those, yes.
Q Are you aware of any greenhouse gas
costs involved in the procurement of nuclear
A There's not any GHC emissions
created that I am aware of in our purchase of
nuclear fuel. Keep in mind that California's
Cap-and-Trade Program is looking at GHG
emissions that are produced in the State of
California. And for energy that's delivered
to California, the originating source will
make assumption about what the portfolio mix
of GHG emissions would have been for that
The mining and enrichment of
nuclear fuel, to the best of my knowledge, is
done outside of California; therefore, it
wouldn't be subject to California's
Q And no other states have any
greenhouse gas costs that might be imbedded
in the cost of the vendor to you?
A I'm not aware of any other
formalized GHG programs. There may be some,
but I couldn't answer that question.
Q What about the back end of the
cycle? Did Edison pay for the greenhouse
costs to haul away the steam generators?
A The Cap and Trade Program went into
effect January 1, 2013. And it applies to
generation resources. I don't believe the
program applies to mobile sources in the
Commission at this point in time. I don't
know that it ever will.
Q Did Edison build that truck? Or
did you pay somebody to build that?
A I believe the truck previously
existed, but I'm not sure.
Q The 80-wheeled truck or whatever it
A I seem to recall reading an
article -- internal company newspaper article
that it's a very specialized truck to make
arrangements to utilize it. But that's the
best of my recollection.
Thank you. Those are all
my questions for now.
So, Ms. George, just to
make sure I understand correctly, that's all
your questions except for this colored chart?
MS. GEORGE: Yes.
ALJ DUDNEY: So we'll take a 15-minute
break. And then you come back at 2:45, and
we can move on. Okay.
Off the record.
Let's go back on the
While we were off the record, I told
the parties about the idea of ending early
today and starting early tomorrow morning.
So that would be try to wrap up around 3:30
this afternoon and resume at 9:00 a.m.
tomorrow. Everyone has I think indicated
that that's okay.
Mr. Geesman noted that he may not be
able to get here promptly at 9:00 due to
obligations in another proceeding. But I
think it's quite feasible that we will just
schedule his turn to cross-examine the
witnesses after he's here.
So is there any objection to that
None from DRA, your
Hearing none, we will plan
to do that. But, again, we'll just review
whoever's at the stand at the end of hearings
So, Ms. George, go ahead.
Q During the break, we
were looking at this exhibit. And do you
understand that it's from a planning
assumptions in the procurement Case
Your Honor, I'm not
sure what the question is, but we do object
to the use of this exhibit as something that
we don't know the data sources or anything
else about this chart. This is not something
Well, the data sources are
the administrative law judge ruling in the
procurement proceeding. I filed this in the
comments in December -- and WEM's comments.
And so that is already in the record. And
this was part of that document, actually.
It's not in the record
of this proceeding, your Honor. There's no
foundation for this document. With that
said, if she wants to ask witness a question
about it, see where it goes. But I just want
to register our objection to the document.
I'm a little confused.
When you have comments in a proceeding -- in
this proceeding, and my understanding is that
those are in evidence. All of our comments
are on the record in this proceeding. And so
I'm a little confused about you're saying
that it's not in evidence in this proceeding
because I believe it is.
I thought you said it
was in the long-term procurement proceeding.
No. I'm saying the source
of this document is the long-term procurement
proceeding. But the chart itself was filed
in our December comments. I think it was
actually in our reply comments, but.
Well, that wouldn't be
That would not
That's what I'm asking.
So, Ms. George, let me see
if I can state my understanding of this
document. And both of you can go from there.
And we'll figure out what to do with it. So
in the long-term procurement proceeding,
there was an administrate law judge ruling
that set forth some planning assumptions.
And then what Ms. George
has done here is redisplay some of those
planning assumptions and make some additional
calculations there. And then this document
as it's presented here was submitted as an
attachment to earlier WEM comments in this
proceeding; is that correct?
Actually, it was on the
page. We just stuck it in the documents.
Okay. This was in --
It was in our comments in
this proceeding, yeah.
Okay. Mr. Weissmann.
Again, your Honor, we
don't have any record about how this has been
compiled, what data sources were used, what
assumptions were used. It's not in evidence.
And having said that, if she wants to ask the
witness a question about it, he can answer to
the best of his ability. But I do object to
the introduction of this document into
Okay. So Mr. Weissmann
has agreed to allow Ms. George to ask
questions about this, and we'll see how it
Okay. Ms. George, go ahead.
Q You a witness in the
procurement proceeding in 2012, right?
Q And also in 2011?
A I don't recall being a LTPP witness
in 2011. I would have to search my records.
Q I think you actually were.
Are you familiar with the LTPP
A I'm generally aware of the planning
assumption process the Commission employs for
Q And, essentially, it lays out the
different resources, the amounts expected in
future years, usually a ten-year window; is
A That's correct.
Q So this particular chart utilizes
the planning assumptions from that proceeding
in 2011. And then it just subtracts the
nuclear power plants and demonstrates that
there's plenty of power even without nuclear
power plants, that as of 2011, with nuclear
power in place, there's 150 percent of demand
statewide, given all of the programs that we
And if you took the power -- the
nuclear power plants out of that picture,
you'd still have 140 percent. This is just a
mathematical exercise that we did in this
And then there's a visual upper
right hand that shows how much that excess
power there is and the fact that it's sort of
a flat, not really -- there's not really an
expansion of energy need.
And nuclear power is just a pink
line across the top. So you're pretty
familiar with the demand in California and
the demand in Edison's territory, right?
That's what you deal with as a procurement
planner all the time.
Wait, wait, wait, wait.
I'm not sure what he's supposed to do with
Q I'm just asking whether
that's his bailiwick, is understanding how
the procurement -- you get this many demand
side resources and then this many supply side
resources. And you try to make the system
work. That's the basic idea.
A So my job as director of portfolio
planning and analysis for Southern California
Edison -- my organization is responsible for
developing all of our price forecasts, our
load forecasts, our developing or portfolio
planning assumptions with respect to
procurement, and for doing our flow modeling
of the system to understand the impact of
congestion. We do a few other things as
All of this comes together to help
us develop a procurement plan for meeting our
bundled customers' requirements. We have a
separate organization in the company called
Integrated Planning that does the traditional
utility resource planning functions where
they look at the physical structure of the
grid. And they look at the interplay between
transmission, new resources, long-term demand
side management programs. And they are the
organization that participates in these
long-term procurement plan proceedings
consistent with the values that you've
provided here in this table.
So, in summary, my group is
responsible for figuring out what actually to
buy and how to buy it, where to buy it. And
the other group is responsible for figuring
out what does the state need.
In looking at this table and
subject to the recognition that I haven't had
a chance to verify all of these data points,
the energy demand that's being record for SCE
seems very low compared to what our system
demand is. Our system demand I would think
would be between 22 to 23 thousand megawatt
level. And everything here is three to four
thousand megawatts below that.
Q Well, that could account for -- I
mean, some of the demand side resources are
obviously incorporated. The goals of the
energy efficiency programs and the
expectations for demand response and CHP --
they're all incorporated into these figures.
That's how the planning assumptions work. So
it sounds like your other department is
more -- would be more familiar with this type
But so you think the demand is
actually a little higher than what this
A Well, certainly in 2011, 2012, and
2013, that's a -- it's lot higher. The
demands that we've realized have been
considerably higher than these. And they are
not our peak demand. Our peak demand
occurred I want to say in 2006 or 2008. So
these demand levels are significantly below
what we actually experience today.
Q So you would disagree with the
planning assumptions, if they were in fact
the ones here. And I also want to put a
caveat -- I know this is getting to be a
compound question. But basically these do
not reflect the need, the once through
cooling replacement needs. This was the
previous LTPP where they did not look at those numbers?
Your Honor, objection
May I describe what the
issue is here?
Go ahead. Describe where
Q Was there really a
power shortage due to the SONGS outage? Your
testimony says that the market prices were
higher due to the SONGS outage.
Is that really the only possible
reason why the market prices were higher?
A No. TURN actually introduced an
exhibit that was an excerpt from a Cal ISO
study that said market prices were higher for
a variety of reasons including higher than
average demand, hydro conditions being lower
than average. And I don't recall the third
one. But the fourth was San Onofre's being
on a forced outage.
Q Was market manipulation one of
A Cal ISO did not identify market
manipulation as a reason why prices were
Q But there was market manipulation
in 2011 and 2012; is that correct?
A It's not my place to say whether
there was market manipulation. That's the
FERC's job. I will note that the FERC has
fined several entities for market
manipulation. So presumably there was
something going on. But I don't have access
to understand whether the markets are being
manipulated. I can have my own personal
opinion on that, but I don't have any facts
to back it up.
The other thing I wanted to
address, Ms. George, is my testimony did not
say that there was a energy shortage. My
testimony said that with the absence of
SONGS, that there was a local grid
reliability concern in South Orange County.
What that means is in the event of
high loads and transmission constraints,
there may not be enough generation to
reliably serve the load in South Orange
County. And by that, we mean not there's not
enough energy, but that the grid itself will
collapse because it becomes unstable because
the generation is not in the right location.
My testimony on prices being higher
are just a simple supply and demand
observation. If you remove 2150 megawatts of
low-cost baseload generation from the supply
demand market design that we have, you move
higher up the supply curve to serve the same
load. And therefore prices are higher.
Q But there's no energy shortage. Is
that what you're saying?
A There's no energy shortage. There
are sufficient resources to meet the load
except for the potential for transmission
constraints during peak demand.
Q Is there a glut of power?
A I would not define it as a glut.
There are times where we have more energy
than we can use.
Q Was San Onofre part of the energy
that you had that was more than you could
A Since late January, both units were
unavailable. So, no, San Onofre was not part
of the energy that we received that we could
Q Was it in January 2012 or earlier?
Your Honor, objection to scope.
Q Was J.P. Morgan
subsidiary acting as a broker for SCE in
A Not as a broker. Edison did have
contracts that J.P. Morgan was a counter
party to. Therefore, we would have to
exchange the necessary information to
Q I'm talking about their
subsidiaries as a -- I believe as a broker,
J.P. Morgan Energy Ventures and another one
called Becka (phonetic). Are you --
A I'm familiar -- I'm responding to
your use of the term "broker." A broker
typically is an entity that facilitates the
transactions between parties. They know what
the prices people are willing to pay to buy
power, what prices people are willing to
accept to sell power. And they bring counter
parties together to consume or to execute
Q Okay. So the answer to that
question is no?
A No. J.P. Morgan and its affiliates
were not brokers for Edison.
Q But they were counter parties?
A Certain affiliated companies to
J.P. Morgan were counter parties with SCE in
Okay. Thanks. That's my
Thank you, Ms. George.
* CROSS-EXAMINATION (CONTINUED) BY MR. SHAPSON: *
Q Just a couple questions here. I
want to ask you about the ANR-20 which
contains Mr. Carver's statement.
A I have that.
Q You had some discussion with
Mr. Geesman about the analysis. And I'm just
curious. Please, I'm not asking anything
about the content of the analysis. I'd like
to know if you can tell me though what the
format of the analysis was. And by that, I
mean, for example, was it a database,
spreadsheet, or report, something like that?
A I can only comment on the
components of the analysis that I was
responsible for. I don't have complete
visibility to everything that was rolled up
and aggregated for Mr. Craver and his
management team's consideration. The work
product that we delivered to the managing
team of this effort was predominantly in the
Q And again without reference to any
information that was contained in there, how
many spreadsheets are you talking about?
A It was an ongoing exercise. We
provided updates sometimes as frequently as
twice a week and at other times three or four
weeks would elapse before we would provide
updates. It would take me a while to sit
here and try to think about exactly how much
it was to give you a good idea. It was a lot
of data flow.
Q Okay. And just so we're clear, I'm
not looking for exactly. If you can estimate
how many Excel spreadsheets we're talking
A Recognizing that some spreadsheets
contain numerous tabs.
Q Thank you for that clarification.
A Probably anywhere between I'd say
40 and 60.
Thank you. And just so
we're clear, your Honor, I understand that I
asked a question about CRRs for 2013, which
was objected to. And I believe that was
sustained, correct? And that just for the
sake of time, if I ask Sempra the same
question, I assume that will be objected to
and sustained as well.
Can I go on that assumption?
Mr. Walsh's witnesses?
Thank you. No other
ALJ DUDNEY: Thank you, Mr. Shapson.
EXAMINATION BY ALJ DUDNEY:
Q All right. Mr. Cushnie, I have a
few questions for you as well. So in Exhibit
SCE-3, I don't think you need to turn to it.
This is kind of a general question. At
different points in that document, in
describing the term Q, which is the quantity
of power purchased, I think there are some
slight differences in the way you describe Q
you in terms of the net short and net long
calculations. I just wanted to ask you to
Is there an actual difference in
how a net open position would be calculated
in those two situations?
A And you're talking about Exhibit
Q I was looking at Exhibit -- yes, I
think it's what's now called SCE-38.
A So Q is defined differently
depending on whether we're calculating the
replacement energy megawatt hours or the
foregone energy sales megawatt hours. When
we're calculating the replacement energy, Q is
defined as those megawatt hours in which
Edison had a financial net short position.
And when we're calculating foregone energy
sales, Q is equal to those megawatt hours
that Edison was financially long had San
Onofre been operating. And they are capped
by the amount of generation that San Onofre
Q Okay. Thank you. Now, the forced
outage rate we talked about a little bit --
can you explain how that is factored into Q?
For instance, that percentage is subtracted
off of the generation in every hour? Or is
it only applied to 2.15 percent of hours?
A So we reduce each hour by the
2.15 percent forced outage rate assumption
that we calculated.
Q Okay. Thank you. Then can you
explain how the price elasticity assumption
was applied in different time periods?
A So we calculated price elasticity
on an on-peak and off-peak basis for each
month of the relevant reporting period. And
we -- and it was basically in a regression
analysis that looked at how implied market
heat rates differed between a scenario where
SONGS operated versus a scenario where SONGS
did not operate. So we looked at the
difference in implied market heat rates
multiplied by the assumed gas price for that
applicable period to get a price elasticity
And then we compared that delta to
the power price that existed to come up with
a percentage. And then we used that same
percentage difference to apply to the actual
index prices that we were using for our
calculations for the foregone energy sales.
Q Okay. So just to make sure I
understood your answer, so for each month,
you would have an on-peak adjustment and an
off-peak adjustment. And you would apply
those adjustments to every hour during that
A For the relevant on-peak or
Q Okay. Thank you. In your
testimony, you suggest using that price
elasticity adjustment only for foregone sales
and not for the purchased power. Why the
A So for replacement energy, Edison
when it had to buy energy to meet the
financial net short position as a result of
the outage was paying the price that was
reflective of what the market settled at as a
result of San Onofre not being available. So
by way of example, if the market price was
$40 had San Onofre been operating, then that
was the price we had to pay to serve our
customer's short position.
In contrast when we calculate
foregone energy sales revenue, what we're
looking at is for those hours where we would
have been financially net long had San Onofre
been operating, what would have been the
market price we would have got for selling
the nuclear output?
We don't have that price available
today because the only price we have is the
price that existed without SONGS. So we view
this price elasticity function adjustment to
estimate how much lower market prices would
have been had SONGS been operating. And then
that is the -- that lower market price is the
one that we used to calculate the foregone
energy sales net revenue.
Q All right. Moving on a little bit,
we talked earlier about the difference
between the day ahead -- and that's the
Platts Index of the SP-15 data prices versus
the day ahead IFM prices in the ISO market.
Can you just briefly explain what
the causes of those differences are? And in
particular, if there's any systematic
A In the IFM, there's two general
types of prices. There's a price that load
pays to be served through the IFM. There is
a price that generation receives for selling
its electrical output into the market.
The Cal ISO's MRTU market design is
comprised of many hundreds of load nodes and
generation nodes. For I'll call it ease of
understanding, the load points can be load
weighted averaged up to a single price, which
is what we refer to as the DLAP. And the
generation nodes can be generation weighted
averaged to a single price, which we can call
the EZ Gen hub price. The DLAP price tends
to be higher than the EZ Gen hub price
because in order to move generation to load,
you incur transmission line losses and
congestion. And it's the delta between those
two that is effectively the combined
congestion and line losses that are incurred
to serve load.
And for that reason, why I have
been advocating to use the Platts test SP-15
index price, which is a price that both
buyers and sellers are willing to transact
that bilaterally prior to the operation of
the IFM. And in theory, that price should
land somewhere in between the DLAP and the EZ
Gen hub price. And it allows us to use a
single price reference point for doing our
Q Okay. Now, in Exhibit SCE-37 you
comment that many of Edison's financial
hedges besides CRRs were more valuable
because of the SONGS outage.
Can you give a quick example of
some of the other hedges that might have been
more valuable in that situation?
A Sure. So Edison may have purchased
a 10,000 heat rate call option. And when
SONGS was running and the applied market heat
rate was running around 8500, that 10,000
heat rate call option would not strike, there
would be no return to ratepayers on that call
With SONGS out of the marketplace,
the applied market heat rate may have risen
to 10,500, causing the call option to be in
the money by 500; and now there's revenues
that are flowing to customers as a result of
that call option.
So this is what I was referring to
saying that the higher implied market heat
rate higher market prices as a result of
SONGS being out of commission, resulted in
many of Edison's forward transactions being
more valuable for its customers. And nobody
has suggested that that additional value also
go into any sort of replacement power cost
calculation in reducing the impact, just were
cherry picking the one that lost money.
Q Okay. Did SCE buy any CRRs during
2012 because of the SONGS outage for part or
all of the remainder of 2012?
A Are you asking did Edison buy CRRs
at the SONGS nodes, or did we buy CRRs at
other generation nodes?
Q What I'm trying to ask is in
response to the changes in congestion
patterns that I guess would be expected due
to the SONGS outage, did SCE in any of the
monthly auctions for 2012 make purchases in
A So without revealing anything
confidential, Edison's AB 57 procurement plan
allows Edison to acquire CRRs where there is
an expected use of the grid. And what that
means is if we anticipate flowing energy from
point A to point B, we can seek to acquire
CRRs through the Cal ISO's allocation process
and then, subsequent to that, through the
And what we do in prioritizing our
CRR allocation nomination request is we look
for the highest value CRRs first and seek to
maximize our allocations at those points, and
then move down in descending order those that
are deemed to be less valuable.
So by design, as we observed
congestion patterns shifting on the grid, our
assessments of value for particular CRRs
would go up or down and, as a result of that,
our allocation requests would potentially
shift from the ones that were previously
considered valuable to those that are now
considered more valuable.
But there was not specific effort
made to say: SONGS is out. Here's what we
need to do as result of that. All of our
CRRs are managed on portfolio basis, and our
allocation and auction practices did not
hange as result of SONGS being out. The
values may have changed as a result of SONGS
being out, but we didn't change anything.
Q Okay. So in the numbers presented
in your testimony for the CRR revenues, do
those numbers include any CRRs that would
have been procured after the beginning of the
outage because of the events you just
described in terms of the change in
A A two-part answer here. First,
Edison did not seek to acquire CRRs at the
SONGS generation nodes once the units were on
outage because we didn't have an expected use
of the grid.
Second, through the Cal ISO's
management of load migration, as customers
moved from one LSE to another, the Cal ISO
does apportion CRRs in very, very small
amounts between the load-serving entities.
And so I do believe that Edison over the
period of 2012 did pick up, you know,
somewhere in the neighborhood of 5 to 10
megawatts of CRRs at the SONGS locations as a
result of load migration. But it's not
anything we requested. It's just something
that occurs as part of the Cal ISO's load
migration allocation process.
Q Okay. So my next question is kind
of comparing the Edison testimony and the San
Diego testimony. One thing that jumped out
at me is that what's listed as the real-time
imbalance charge line item is actually far
larger in San Diego's case than in Edison's.
And I suspect that the reason for that is
that San Diego perhaps included some
additional, I think it was, station loads in
their line item. And so I wanted to ask you.
There is no reason that the
real-time imbalance charge per se would be
larger in San Diego's case than Edison's;
A Assuming that San Diego was not
scheduling output from San Onofre the day and
hour perhaps the unit was forced out, our
numbers should be proportional. Edison
reported for its real-time imbalance charge
just the imbalance charges that we incurred
for the balance of January 31st, when Unit 3
first went out, and the entirety of
February 1st, 2012, because that day that
schedule had already been submitted to the
Cal ISO. After that there were no imbalance
charges incurred as a result of day ahead
We are charged for the auxiliary
load at the power plant in the real-time
imbalance market because the auxiliary load
is not load that can be scheduled with the
Cal ISO. It's normally served by the power
plant. And so Edison elected to call that
auxiliary load and showed it as a separate
component of our miscellaneous costs.
And you have refreshed my memory,
as I believe San Diego was reporting it as
imbalance energy charge, which is how it's
served in the Cal ISO's market.
Q SONGS station power costs, which I
think is what we are referring to as the
auxiliary load costs, is -- how is that
counted in the SONGSMA? Is that an O&M cost?
A Edison is recording it as an OMA
cost. We report it under our Huntington
Beach sub account line item.
For example, if you were to look at
Edison's August 1, 2013, OMA submittal to the
Energy Division, on the last page there is a
memo item that identifies the components of
the Huntington Beach sub account and we have
a line item there that says: Auxiliary load
costs charged in real-time imbalance market,
and we detail what those are.
Q And then can you briefly describe
how their real-time imbalance charges and the
PIRP, Participating Intermittent Resource
Program, charges are calculated by the ISO?
For example, is that a fixed
dollars per one hour charge or is there some
A So the real-time imbalance energy
charges accrue based on the Cal ISO's
five-minute real-time market. And if you are
short, you are charged the real-time
The PIRP charges are part of the
Cal ISO's Participating Intermittent
Resources Program that allows intermittent
resources to schedule into the Cal ISO
consistent with the Cal ISO's forecast for
their output. And if they do it that way,
then Cal ISO integrates all of their
imbalances so that they're not subject to the
five-minute imbalance market; that they have
net in balance over the period of the month.
And then there is uplift that
occurs because of that. And the Cal ISO
allocates that uplift to all negative
uninstructed deviations in the market.
So the auxiliary load at the plant
because it's being served in the imbalance
market, it shows up as a negative
uninstructed deviation. And so portion of
these PIRP charges are allocated to that
negative uninstructed deviation. So it's
just a cost that follows the imbalance.
Q So if SONGS were simply treated as
a customer rather than a generator, those
charges would not be incurred; is that
A I believe the PIRP charges are only
allocated to generators.
Q Okay. Now, I would like to ask a
When you discussed with Miss George
earlier the Edison Mission Energy purchase of
Huntington Beach, do I correctly understand
that Edison Mission Energy had purchased the
air credits only, or had they purchased also
the physical plant?
A My understanding is that Edison
Mission Energy purchased those components of
Huntington Beach 3 and 4 that would be
necessary to qualify for retiring the units
and being eligible to access AQMD's Priority
Reserve Bank for air emissions credits. And
in order to do that, they had to disable
Huntington Beach Units 3 and 4, which I
believe they said they put holes in the
When Cal ISO determined that they
wanted to return Huntington Beach Units 3 and
4 to service, then Edison Mission Energy
entered into some sort of contractual
arrangement with AES to return the components
of Units 3 and 4 that they had purchased to
allows AES to operate them as units, and AES
then repaired the boilers so the units could
I don't know if the components were
returned in the form of a lease or a sale.
That's beyond my knowledge. But to answer
your question, Edison Mission Energy actually
purchased certain components of Huntington
Beach 3 and 4 so that they would be eligible
to access the Priority Reserve Bank.
All right. Thank you,
Mr. Cushnie. That's all I have.
I'll be fast. I know
we're almost out of time, so I'll try and be
REDIRECT EXAMINATION BY MR. WEISSMANN:
Q Just a few questions, Mr. Cushnie.
First of all, Mr. Geesman earlier
today asked you about some of the work that
was done to support the -- that was
referenced by Mr. Craver, and there was some
question about whether that analysis looked
at costs incurred for procurement in 2012.
Over the course of the break, were
you able to ascertain whether 2012 costs were
A Yes. I was able to confirm that we
did not look at 2012 costs. It was a
forward-looking assessment that began in 2013
in its initial form.
Q Okay. Mr. Shapson asked you some
questions at the beginning of the day about
forced outage rates and what they would have
been if you looked at a 15 or 20-year look
back on SONGS operations.
Over the course of the day, were
you and your staff able to compile some data
on that question?
A Yes, we were. My staff reports
that if we used a 15-year forced outage rate,
the forced outage rate would be 2.98 percent;
and if we used a 20-year average, it would be
Q And just remind us: What was the
rate that was used in your testimony?
A The 10-year average was
2.15 percent, almost a full percent lower.
Okay. Thank you,
Mr. Cushnie. Those are all the questions I
RECROSS-EXAMINATION BY MR. SHAPSON:
Q I'm sorry. The numbers that you
just gave are the averages for SONGS?
Q Okay. So you were able to contact
your staff and get this information during
the lunch break or some other break?
Q Did you ask them to find out for
you the industry average for those two time
periods as well?
Q Why not?
A There is only so much information
they are going to be able to obtain in a
limited period of time.
I will tell you it took one of my
staff members a long time just to get the
10-year average -- industry average that I
put in my testimony. And the document that
we used only provided ten years' worth of
All right. If you have nothing
Nothing further, your
I assume we can move exhibits later
ALJ DUDNEY: Sure. We can move the
exhibits -- let's do that first thing in the
All right. Mr. Cushnie, you're
And we will resume at 9:30
in the morning. Excuse me -- 9:00 a.m. in
the morning. Thank you.
(Whereupon, at the hour of 3:33
p.m., this matter having been continued
to 9:00 a.m., August 6, 2013 at
San Francisco, California, the
Commission then adjourned.)