20040415Volume VIII.pdf

ORIGINAL
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR AUTHORITY
TO INCREASE ITS INTERIM AND BASE
RATES AND CHARGES FOR ELECTRIC
SERVI CE .
) CASE NO.IPC-E-O3-
Idaho Public Utilities Cpmmission
Office of-the Secretary
RECEIVED
APR 1 5 2004
Boise, Idaho
BEFORE
~j.~,
tWO
COMMISSIONER MARSHA SMITH (Presiding)
COMMISSIONER PAUL KJELLANDER
COMMISSIONER DENNIS HANSEN
PLACE:Commission Hearing Room
472 West Washington
Boise Idaho
DATE:March 30 2004
.vOLUME VIII - Pages 910 - 1145
CSB'REpORTING
Constance S. Bucy, CSR No. 187
17688 Allendale Road * Wilder, Idaho 83676
[phone] * [phone]
. Email csb~spro.net
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For the Staff:Lisa Nordstrom, Esq.
and Weldon Stutzman, Esq.
Deputy Attorney Generals
472 West Washington
Boise , Idaho 83720-0074
Barton L. Kline, Esq.
and Monica B. Moen, Esq.
Idaho Power Company
Post Office Box 70
Boise , Idaho 83707-0070
RICHARDSON & 0' LEARY
by Peter J. Richardson, Esq.
Post Office Box 1849Eagle, Idaho 83616
RACINE , OLSEN , NYE , BUDGE
& BAI LEYby Randall C. Budge, Esq.
Post Office Box 1391
pocatello, Idaho 83204-1391
Lawrence A. Gollomp, Esq.
Assistant General Counsel
u. S. Department of Energy
1000 Independence Ave., SW
Washington , DC 20585
McDEVITT & MILLER
by Dean J. Miller, Esq.
Post Office Box 2564
Boise, Idaho 83701
William M. Eddie
Advocates for the West
Post Office Box 1612
Boise , Idaho 83701
IVENS PURSLEY LLP
by Conley E. Ward, Esq.
Post Office Box 2720
Boise , Idaho 83701-2720
For Idaho Power
Company:
For Industrial Customers
of Idaho Power:
For Idaho Irrigation
Pumpers Association:
For The United States
Department of Energy:
For United Water Idaho,Inc:
For NW Energy Coalition:
For Micron Technology,
Inc. :
CSB REPORTING
Wilder , Idaho 83676
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APPEARANCES
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WITNESS
Magg i e Bril z
Idaho Power)
William Avera
(Idaho Power)
EXAMINATION BY
Mr. Budge (Cross)
Commissioner Hansen
Commissioner Kj e~lander
Commissioner Smith
Mr. Kline (Redirect)
Mr. Kline (Direct)
Prefiled Direct TestimonyMr. Kline (Direct-Cont I d)
Prefiled Rebuttal Testimony
Mr. Gollomp (Cross)Mr. Ward (Cross)Mr. Richardson (Cross)Ms. Nordstrom (Cross)Commissioner Smith
Commissioner Hansen
Mr. Kline (Redirect)
PAGE
910
928
938
940
942
947
949
1057
1060
1089
1109
1125
1129
1139
1140
1144
CSB REPORTING
Wilder , Idaho 83676 INDEX
PAGE
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Identified 1116
Identified 1116
Identified 1116
NUMBER DESCRIPTION
FOR IDAHO POWER COMPANY:
DCF Model - Dividend Yield
DCF Model - proj ected Earnings
Growth
DCF Model - "b x r" Growth
Risk Premi um Method Authori zedReturns
Risk Premi um Method RealizedReturns
10.Risk Premium Method CAPM
11.Qualifications of William E. Avera
FOR MI CRON TECHNOLOGY , INC..
711. Puget Energy, Inc., NYSE-PSD
712. Xcel Energy, NYSE-XEL
713. Discounted Cash Flow Model
Earnings Growth Rates
CSB REPORTING
Wilder , Idaho 83676 EXHIBITS
BOISE, IDAHO, TUESDAY , MARCH 30, 2004, 9:00 A.
COMMISSIONER SMITH:I believe yesterday
afternoon we had Ms. Brilz on the stand and we were ready
for cross-examination by Mr. Budge.
MR. BUDGE:Thank you, Madame Chair.
Contrary to what usually happens, I was able to shorten
things up considerably.
COMMISSIONER SMITH:And we'll take your
word for that, Mr. Budge.
MAGGIE BRILZ
produced as a witness at the instance of Idaho Power
Company, having been previously duly sworn, resumed the
stand and was further examined and testified as follows:
CROSS-EXAMINATION
BY MR. BUDGE:
Good morning.
Good morning.
Ms. Brilz , starting on the bottom of page
2 of your testimony you discussed the class
cost -of - service study and indicate that the Company used
the same methodology as previously filed in the three
CSB REPORTING
Wilder, Idaho
910 BRILZ (X)
Idaho Power Company83676
previous cases identified; is that correct?
That is correct.
And historically in those previous cases
didn I t the Company simply use a weighted 12CP
methodology?
In the previous studies the Company used
marginal costs to weight the 12 monthly coincident peaks
applying the marginal costs that were identified to those
months in which there were marginal costs.
In this study the Company I s done time
methodology.We have applied the identified marginal
costs to the monthly coincident peaks.
The thing that I s different in this case,
isn I t it, in this case you chose to average a weighted
12CP methodology with a 12CP methodology?
That is correct.In previous cases the
Company has simply taken the monthly marginal costs and
applied them to the actual coincident peaks on a monthly
basis for customer classes.In this study we took the
marginal costs, applied them to the actual monthly
coincident peaks , and then averaged them with the actual
non-weighted monthly coincident peaks.
And also a fundamental difference in this
case, is this not the first time that the Company used
zero allocators in certain months?
CSB REPORTING
Wilder , Idaho
911 BRILZ (X)
Idaho Power Company83676
It is not the first time.No.In the
94 - 5 case the Company al so had months where there were
zero weighting factors.
In that previous case they were proposed
by the Company?
Yes.
In how many months did you propose the
weight zero in previous case?
In the previous case our cost of service
- -
or our marginal cost analysis indicated two months
wi th no capacity-related marginal cost.
Just two months?
Two months.
And was that adopted by the Commission?
No, it was not.The Commission decided
that it was important to include each monthly recognition
of coincident peaks in the computation process.In this
study that we have filed and the calculation of those,
the demand allocators, we I ve taken the actual and the
weighted to come up with allocation factors for each
customer class.
In fact, this Commission has never adopted
a 12CP methodology with a zero allocating factor in any
month; have they?
I am not aware that the Commission has
CSB REPORTING
Wilder, Idaho
912 BRILZ (X)
Idaho Power Company83676
adopted a weighted 12CP methodology with a zero in a
particular month.
And are you aware of any of your
neighboring utilities, Washington Water & Power, Pacific
Corp., that have made a proposal of this nature or had
adopted by a commission where zero weighting factors are
used in certain months under a 12CP methodology?
I am not aware of any methodologies other
utili ties may have used.
Just so I understand how this works, for
purposes of allocating demand-related costs the Company
proposing to use a zero allocator in seven of the months.
No, I wouldn't say that's correctly
representing it.What the Company has done is taken
actual coincident peaks, weighted those by what we'
identified as the five months where there is capacity
related marginal cost.We have then , in order to
incorporate each monthly cost causation responsibility by
customer class, taken the actual 12 months of coincident
peaks and have averaged those into the weighted factors.
So each month has some representation in the allocation
process.
That I s the weighting between the weighted
12CP and the 12CP that we discussed.The two methods
were averaged?
CSB REPORTING
Wilder , Idaho
913 BRILZ (X)
Idaho Power Company83676
That is the methodology that I used to
come up with the demand allocators.
I might not have phrased this clearly, I
apparently didn't, but I was referring - - and these
questions will refer simply to the weighted 12CP portion
of the methodology that you averaged
- -
with respect to
the weighted 12CP , the affect is to have an allocator of
zero in seven months with respect to demand related
costs; is that correct?
The first
- -
that is correct.The first
step in the process was to weight only using the five
capacity marginal cost months.
Okay.And focusing on that first step,
the weighted 12CP, effectively that becomes a 5CP
methodology by reason of the ' zero weighting factors
the other seven months?
In you were to stop at that point it would
effectively be 5CP.
And similarly for purposes of allocating
transmission-related costs, the Company proposes a zero
allocator in nine months, so you effectively have a 3CP
allocation methodology for that half that relates to the
weighted 12CP?
I wouldn I t say that's an accurate
representation.The component or the first step where
CSB REPORTING
Wilder , Idaho
914 BRILZ (X)
Idaho Power Company83676
we used a weighting factor , yes , there are three months
where capacity related transmission marginal costs are
identified.Then we al soThat's the first step.
incl uded each of the twelve months of actual coincident
peaks in the calculation of the actual allocation factors
that were used to allocate costs.
But as to the weighted 12CP portion you
essentially have weighted factors in three months?
For that first step process, yes.
And referring, again, to the weighted 12CP
half of that methodology, the effect of having the zero
allocators , is it not, is to heavily weight the cost to
customers who use power in those particular months where
the weighting factors are applied?
The weighting factors do give more weight,
if you will, to loads that are utilized during the months
where marginal monthly costs have been identified, yes.
And since three of those weighted months,
three of the five demand-related costs of June, July, and
August when the irrigators are all on, the effect of this
methodology weights substantially more costs to the
irrigators than otherwise would have been the case under
traditional weighted 12CP where you have no zero
allocators?
The methodology allocates costs to those
CSB REPORTING
Wilder , Idaho
915 BRILZ (X)
Idaho Power Company83676
customer classes that utilize the system during those
higher-cost months.I I ve not done an analysis to see
exactly what the outcome would be if there were some
methodology that would assign a marginal cost to the
other months.We used the marginal costs that we
identified and those happen to be in those higher-cost
months , June, July, August.
And just so I understand how this would
work.If, for example, the Company then incurs a
substantial amount of transmission-related costs to serve
new residential or commercial load, which I think some of
the filing indicates there have been a considerable
amount of expenditures in the last ten years, and given
the anticipated growth over the next several years,
that I S a substantial portion of that capital budget of
new expenditures.
So under the weighted, again , 12CP
methodology, those particular classes that are fueling
the need for this growth , residential and commercial,
would in fact only be weighted cost based upon their
usage at the coincident peaks in the months of June,
July, and August transmissions; correct?
That I S not totally correct.The weighting
is applied to June , July, and August because that is when
we have identified that we have transmission-related
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
916
83676
marginal costs.However , because we I ve taken all twelve
actual coincident peak demands and included them in the
development of the allocators to actually allocate cost
to customer classes , each customer class's responsibility
through all twelve months of the year is included in the
allocation process.
Because you I re, in fact, again referring
back to the average of the 12CP and the weighted 12CP in
coming up wi th your final numbers?
Yes , that is correct.
But if my question was focused as intended
to, simply on the weighted portion of the 12CP, on that
half of the averaging you would be allocating costs to
those particular classes driving the growth , residential
and commercial only, based upon the usage in the three
months?
I f you only looked at those three months
it would be allocating cost to all customer classes that
are utilizing the system based on their peak loads during
those three months.
I have some questions regarding the
identification of the deficit months based on the IRP
that I wanted to clarify with you.I have discussed with
Mr. Said some of these, and I believe he deferred those
questions to you.
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
917
83676
If I understand it correctly, looking at
page 15 , lines 15 through 22 in your direct testimony,
you basically state that the 2002 IRP lists the five
months with capacity deficits.In other words, you
looked to the IRP to identify where we have capacity
deficit months that you were attempting to address by
your weighting methodology.
That is correct.
Okay.And for purposes of the summer
months you identified June, July and August, and the
winter months you identified November and December.
Those are the months that were identified
yes.
And if I understand correctly, the basis
in the IRP for identifying these generation needs was
looking at a five-year time frame from 2003 to 2007.
That I cannot specifically answer.I'd
have to defer that to Mr. Said or Mr. Gale.
To who?
Mr. Said or Mr. Gale.
Okay.I bel ieve , well , subj ect to check,
I bel ieve the Company I s response to one of DOE I
discovery requests indicated that that was the time
frame, but subject to check, if you'll accept that.And
did in fact the Company also utilize in identifying those
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
918
83676
deficit months under the IRP, the 70th percentile water
and load data?
That is my understanding.
And as I look at the 2002 IRP
specifically the pages I discussed with Mr. Said, pages
3, 4 , 6 and 28, when those capacity deficit months are
discussed, nowhere do I find the month of August.And
understand that since yesterday you've been able to look
further into that and explain why you have included
August as a deficit month when, in fact, it's not
reflected as such in the IRP?
Yeah.Subsequent to the document which
believe you are looking at, the Company had a supplement
to its IRP once the Garnet proj ect was no longer going to
be constructed.And with removal of Garnet the deficit
months changed and August shows up in that process.
So when the irrigators made their
discovery request for the 2002 IRP and supporting
documents, this supplement you refer to wasn It included.
And is it your testimony here now that there I s a
supplement of some sort that revises these numbers as a
result of Garnet being eliminated?
That is my understanding, yes.
And do you have that available with you?
I do not.
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
919
83676
Is that something that you could produce
to me during the course of proceedings simply to verify
the change?
Certainly.
What you re testifying to is that you
believe the amendment or supplement to the IRP, which we
don I t have, that takes Garnet out, adds in August as a
deficit month even thought it doesn t appear as such in
the 2002 IRP?
That is my understanding that August shows
when the Garnet proj ect is taken out.
I suppose, without having an opportunity
to have that in front of you, then , we can I t very well
discuss the graph to identify when the deficit month of
August would appear in this five-year time frame of 2003
to 2007 that we're looking at.
I couldn't specifically speak to that
wi thout the document in front of me, that's correct.
Okay.In looking at, at least the one IRP
that was produced on page 30, it doesn t identify August
at all as a deficit until you get out beyond this period
in question 2008 or 2009.Are you able to tell me when
it was anticipated that Garnet was going to come on line
as reflected in this IRP?What was the in-use date
planned for Garnet?
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
920
83676
I can't tell you that.
Okay.Could we refer to your Exhibit 40
please?And if you could, Mrs. Brilz , look at page
CSB REPORTING
Wilder , Idaho
Do you have that available?
I do.
The lower part of that particular exhibit,
which is entitled Monthly Energy Requirements Weighted by
Marginal Energy Costs, under that for power supply
service generation, you've identified the twelve months
of the year; is that correct?
That is correct.
And is the number adj acent to that the
weighting factors that were utilized as demand and energy
The numbers in the column immediately to
the right of the month is the weighting factor.
As I look at those weighting factors, the
weighting factor for June is about the same as November
While July and August have a weighting
factor higher than November and December.Do you see
Yes, I do.
And when I go back to the IRP , and again
this may be a bunch of change that I I m working from, but
when I go back to the IRP on page 30 and try to corollate
allocators?
and December.
that?
921 BRILZ (X)
Idaho Power Company83676
the deficits the IRP is projecting with the weighting
factors , there doesn't seem to be any correlation.
In other words, the IRP is showing that
November and December have actually a greater deficit
than the month of June.Yet in your weighting factors
you have a higher weighting factor in June than you do
for November and December.So I guess my question is, if
the IRP is identifying a different amount of capacity
deficit than your allocators are, there's no direct
correlation between the two.How do you explain that
difference?
Well, first, the IRP was used to identify
the capacity deficit months in utilization of the
weighting factors for the capacity-related allocation of
What you I re referring to here is the energycosts.
component.
Well, if you look at the capacity factors,
which I believe are on page 1, the same thing appears
there.There's no direct correlation between the
deficits identified on the IRP and the weighting factors
that you reflect.So I guess my question is, if you
didn t rely upon the deficits shown in the IRP to develop
the weighting factors, how did you come up with the
differences between the summer months and the winter
months that you use here?
CSB REPORTING
Wilder , Idaho
922 BRILZ (X)
Idaho Power Company83676
On page 1 of my Exhibit 40 where you I re
referring to the capacity-related weighting factors,
those do tie directly to the IRP in that we've identified
capacity deficits in the months of June, July, August,
November , and December.And the weighting factors that
you see are only for those months related to the
derivation of the marginal costs for capacity-related
resources.
The numbers that you re looking at on page
5 are related to energy marginal costs, which are the
marginal energy costs we can expect through any month of
the year purchasing energy, not capacity.
Okay.Well, let I s look at page 1, then
relating to the demand cost.The same thing is there.
There s considerably heavier weighting in June and August
than there is in November and December.And the IRP
identifies those to have either close correlation or
almost actually a greater deficit in November and
December than certainly June or August.And so I I m
wondering how did you arrive at the allocation factors
that don t appear to tie to the deficits that were in the
IRP that supposedly was the basis of these allocators?
Okay.The capacity marginal cost is
derived by looking at a resource.The resource has an
annual cost.We identified the monthly component of that
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
923
83676
annual cost by looking at the relative value of the
coincident peaks on the system during the five months in
which capacity deficits were identified.
We have a higher load, coincident load, in
the months of June , July, and August, than in November
and December.And that factored into the calculation of
the monthly weighting factors.
Let me go into one other area, if I may.
The Company proposes in this case to cap the increase to
the irrigation class as a whole at 25 percent; is that
correct?
That is correct.
And if they removed the full cost of
service under the methodology the Company proposed it
would require an increase of something like 62 percent to
the class as a whole?
Roughly that percentage, yes, correct.
Could you explain the reasoning for the
Company's cap and why it was selected at that percent
level?
Well , the Company certainly starts with
costs as the basis for identifying what the revenue
requirements for any particular customer class should be.
However , we did take into account in this particular case
what impact customer classes would have.And we
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
924
83676
, 25
determined that a 25 percent cap would be a reasonable
level to establish as the ceiling for the irrigation
customer class taking potential rate shock into account.
, rate shock was the only factor that
you considered?
That is correct.
Was there any consideration given towards
the economic impact on that class of customers, or the
farm economy in general?
No, there was not.
So when you say we looked at the concept
of rate shock and decided that 25 percent was reasonable,
how did you - - what was the reasoning that you got to
reasonable?Was there any kind of technical analysis or
is that simply a judgement call on behalf of you and
others that were making the call?
That would probably be better asked of Mr.
Gale.It relates to his testimony.
When you viewed the principle of rate
shock to class of 25 percent I take it you were analyzing
that from the perspective of the class as a whole, not a
particular irrigator?
That is correct.We looked as the class
as a whole.
And in fact, the concept of rate shock,
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
925
83676
doesn't it normally apply from the individual customer'
perspective as to what might impact them if a rate goes
up or down too much?
Well , certainly individual customers have
different impacts from various rate designs.
And as I understand it, there wasn't any
economic analysis performed as to some of those customers
who might get substantially greater than a 25 percent
increase, even though the overall class is held at 25
percent?
Well , the Company identified the potential
impact to the individual customers wi thin the class.
believe, in fact, if you look at my Exhibit 44 you 'll see
the results of that analysis.
Okay.I would like
- -
let I s turn to that
exhibi t, if we could.
It appears to me you re anticipating my
next question.Which page was that of
It would be page 6 of
Okay.Looking at page 6, which is
entitled Idaho Power Company Billing Impact of Proposed
Rates , State of Idaho to Agricultural Irrigation Service
Schedule 27.If I understand that correctly, this
exhibit purports to identify how many customers would get
raises of a different percentage?
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
926
83676
It tries to identify within a certain
percent change how many customers fall within each range.
CSB REPORTING
Wilder , Idaho
And the second column reflects the number
of customers that would be in each of those ranges?
That is correct.
So if I look at the first line you'
showing 2950 customers would get less than a 25 percent
That is correct.
And by percentage, that would be, if my
math is correct and you accept subj ect to check, about 22
and a half percent of irrigators would have a raise of 25
That is correct.About 23 percent or so,
would get less than the average increase for the class.
So conversely then, the other 77 and a
half percent would have a raise of greater than 25
percent under the Company s proposal?
They would have an increase equal to or
greater than 25 percent , yes.
And those various degrees of increase
would be reflected further on that exhibit.
That's correct.
And as I look at, toward the bot tom of it,
raise?
it would depict that 46 percent of the class would have a
percent or less?
927 BRILZ (X)
Idaho Power Company83676
raise of somewhere between 32 percent and 50 percent?
I don't have the percentages here but
would, subj ect to check , accept your numbers.
But what percentage increase in rates does
the Company believe the increase would be so drastic as
to constitute rate shock?
I can I t say there's a specific number.
try to look at the picture as a whole and determine for
the class what seems to be reasonable.
Thank you, Ms. Brilz.
MR. BUDGE:No further questions.
Thank you,COMMISSIONER SMITH:
Mr. Budge.
COMMISSIONER SMITH:Are there questions
from the Commission?Commissioner Hansen.
A couple of questions.COMMISSIONER HANSEN:
EXAMINATION
BY COMMISSIONER HANSEN:
At our public hearings in Pocatello and
Jerome we had several irrigation customers state that
they had to pay the entire cost of service to bring
electricity to their pumps.Is that true?
Are you referring to line extension
CSB REPORTING
Wilder, Idaho
928 BRILZ (Com)
Idaho Power Company83676
construction, or I I m not sure what you re asking for.
Right.
The Company has under its lineNo.
extension provisions , allowances that are provided to
help pay for the cost of extending those lines.
Is that to a new customer?
Yes.
So how about if an existing customer
- -
had some that said they had moved or changed location of
their pump and they had to pay the entire cost.And they
quoted, like , 20 some odd thousand dollars it cost them
or so forth.Did they pay the entire cost of that?
that true that they paid that?
Well, the Company has provisions for line
extensions or relocation of facility covered under our
Rule H , which this Commission has approved.There are
specific provisions for what customers pay and what the
Company provides, the allowance, or the individual
services that are provided.It I S not my area of
expertise so I can't give you an absolute answer , but the
Company would follow the provisions under that tariff.
And any customer who would need some of the services
offered under that schedule would pay the proportional
cost as determined under that schedule.
Would you have any idea why the irrigation
CSB REPORTING
Wilder, Idaho
BRILZ (Com)
Idaho Power Company
929
83676
customer thinks that they are saddled with the entire
cost of paying for that when you re, if I'm hearing you
correctly, you I re saying they're not?
I don't know why they might feel that.
Perhaps they aren t familiar with what services they
receiving.I just honestly do not know why they would be
perceiving that.
How are the new irrigation customers, or
existing irrigation customers I paYments for hook-ups, and
moves, and changes, tracked in the Company
cost -of - service allocation?
Well , when a customer makes any kind of
contribution towards their line extension provisions,
those monies have a five year time frame in which to be
refunded if additional applicants come on board.
those monies are not refunded, they are closed to our
plant accounts which offsets the Company s investment in
that plant account.And so a reduced amount of plant is
on the Company I s books and is allocated to customer
classes.So that benefit does come back to those
customers who have made a contribution.
So if a customer pays for movement or
relocation of their service, is that paYment all directly
attributed back to the irrigation class?
No, it is not attributed specifically to
CSB REPORTING
Wilder , Idaho
BRILZ (Com)
Idaho Power Company
930
83676
the customer class.
So if they re not directly attributed to
the irrigation class, does this mean that they
effectively keep the overall rates down and expenses down
from growing rather than just the irrigation base rates
and expenses?
Well, all customers who have line
extensions or relocations, and who make a contribution
have those monies put into the process where it reduces
the amount of plant on our books.It gets allocated to
all customer classes.
But wouldn't it -- I guess to me as I hear
the irrlgators testify at a public hearing,they feel
that they'not properly credited for the cost
service that they pay for.And so to me,guess,if you
could explain if they re making a paYment, full paYment
to have their electricity relocated and it isn 1 t going
back into the irrigation class, all that money isn'
going back, they are actually contributing to the other
classes of service of keeping those expenses down.
guess I'm having a hard time seeing that it wouldn't be
there - - it wouldn t be actually a flaw in the
methodology of cost of service for the irrigation
Could you explain why it wouldn't be?customer.
Well, those paYments that they make do go
CSB REPORTING
Wilder, Idaho
931 BRILZ (Com)
Idaho Power Company83676
back to offset their costs for the class.What I am
saying is that I can t say that a $10,000 paYffient made by
one irrigation customer specifically goes back to that
But those paYffients are used to offset thecustomer.
costs that are allocated to irrigation customer classes,
as are the paYffients made by other customer classes, used
to offset the costs that ultimately get attributed to
those customer classes.
Okay.So that I completely understand.
You re telling me that all the paYffients made by the
irrigation customer are directly attributed to the
irrigation class; is that correct then?And if we were
to audit that we could verify that as true?
m not saying that.Those costs areNo.
attributed back to the plant investment.Those plant
investments get allocated across the board to all'
customer classes and indirectly those paYffients do come
back to customers.But, no, I cannot say that there is a
dollar-per-dollar match per any customer class,
irrigation, residential, commercial, any customer class.
So it does benefit all rate payers to some
degree?
Any paYffient made by any customer for
relocation or line extension could benefit all customer
classes.
CSB REPORTING
Wilder , Idaho
932 BRILZ (Com)
Idaho Power Company83676
Let me ask you, maybe it just seems like
it's jumping out at me this year , but why is the
cost-of-service gap widening for the irrigation customer?
Is it a change in the allocators , is it the accounting?
I know Mr. Budge went over a lot of the alloca tors wi
you, but what in your mind is causing such a drastic
change in this gap of cost of service to the irrigation
customer?
Well , we re seeing an increase in the cost
of providing service during the summer months.And
irrigation customers utilize the great majority of their
consumption during those summer months.So as you look
at the loads imposed on the Company system, and the cost
of servicing those loads , the irrigation customer class
has a fair share of those costs.And that is what
would attribute one of the main factors to.
Could the increased growth in residential
customers also be attributed to that?Because in my mind
you re taking energy or generation that existed that
maybe could be allocated to the irrigation customer , and
now it's being used for the residential person.And so
it does put more pressure at peak times to go out and
find energy for the irrigation customer.So could
actually the residential customer be causing some of this
widening of the gap for the irrigation?
CSB REPORTING
Wilder , Idaho
933 BRILZ (Com)
Idaho Power Company83676
Well , I would say it's the total load that
we have on your system during any particular month that
really is the determinant of the cost.And customers who
have loads during those higher-cost months, have
proportionate costs allocated to them relative to their
loads during those higher-cost months.
So I would say the residential customers
are getting more costs for the summer months allocated to
them relative to their loads in the summer months, as are
commercial or any other customer class that happens to
have loads during the higher-cost months.
And so I understand, you re saying you
don t think that affects the irrigation customer?
No, I do not.
Has there been a time when Idaho Power
Company recruited or they were seeking to add irrigation
customers to their system?
Not in the time frame that I have been at
the Company.
m probably going to go back when you
were probably still in high school, but I was around and
out in the real world.But back in the ' 70s I know Utah
Power and Light promoted Gold Medallion homes and total
electric homes.And I understand that Idaho Power did
also.And my question would be, back in the ' 70s when
CSB REPORTING
Wilder , Idaho
BRILZ (Com)
Idaho Power Company
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83676
the companies promoted the total electric home, did those
total electric homes pay for the full cost of service?
I could not tell you, Commissioner Hansen,
what the situation was in the ' 70s.I do not know what
the Company did at that point in time.
Are you aware at that time that they
offered reduced rates for total electric home?
No, I I m not.
Do you think that the game plan has
changed for the irrigation customer in that when they
were brought on the system there wasn't really that big a
concern about whether they were paying the full cost of
service or not.And now all of a sudden it's a
tremendously big issue.Has it changed?Is that true?
Well , I would say that over time things
change.I can't speak to exactly what may have been
represented to customers years and years ago.But to the
extent that there may have been something represented
back in the ' 70s or '60s, or whatever you may be
referring to, times do change.And I believe that it is
appropriate to allocate cost to customers based on what
they are imposing on the system at the time that you
reviewing what their rates should be.
You know, I'm going to take just a moment
and give you an experience.But back in the '70s I built
CSB REPORTING
Wilder, Idaho
BRILZ (Com)
Idaho Power Company
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a total electric home in 1977.And I debated whether to
use gas or whether to go total electric.And it was wi
Utah Power & Light.And the rates were very attractive
to go total electric because the more electricity you
used the cheaper it was.And I lived out of the city a
little ways I would have had to go propane and use that,
or go the total electric.And I went the total electric
because it was much more economical.
One year later I attended a public hearing
where, before the Commission , it was to change it to
inverted rates.And now , all of a sudden, my total
electric bill in the winter would be $300 more than what
I was currently paying for electricity when I came on the
And I didn't think that was fair and I testifiedsystem.
before Mr. ward and Mr. Swisher.They were in Soda
Springs and I remember a question Mr. Ward asked me.
that time he said how come you used so much electricity
in April?And I said , because I had a bunch of chickens
and it got cold, the little baby chickens - - and I don't
know if he remembers that, but it was at the Cedar View
that we had that hearing.But I testified I didn't think
that was fair.
And I guess my question to you is, if an
irrigation customer has come on 20 years ago and cost of
service the Company just disregarded.I mean , said yeah
CSB REPORTING
Wilder , Idaho
BRILZ (Com)
Idaho Power Company
936
83676
it's fine.We know you're not paying cost of service but
that I s okay.And now all of aThis is a fair rate.
sudden you're saying to that customer hey, the game
plan's changed.Do youThis is very important to you.
think - - I guess I'm saying do you think that's fair to
the customer if you're brought on under one particular
circumstance and then it completely changes?It could
cost them thousands and thousands of dollars.
I think what you see from the Company
proposal is that we have proposed to cap the irrigation
customer rate at 25 percent for that class.To me that
is mitigating some of the issues that you re raising in
that if we were to try to bring them up to total cost of
service, it would be a significantly higher cost to them
than what we have proposed.So I believe that our
capping at 25 percent mitigates some of the issues that
you ve just raised.
Thank you very much.
That's all I have.COMMISSION HANSEN:
COMMISSIONER SMITH:Commissioner
Kj ellander.
CSB REPORTING
Wilder, Idaho
937 BRILZ (Com)
Idaho Power Company83676
EXAMINATION
BY COMMI S S IONER KJELLANDER:
Good morning.
Good morning.
I guess I just want to try to get a better
understanding of the issues surrounding rate shock.Mr.
Budge hit on that, I think, very diligently with regards
to irrigators, but we kept talking about percentages and
percentages to me sometimes don't mean much.They can be
a little misleading.If I could try to stay away from
them I'd try to get to what the cash value is of that
percentage to get a better perspective.So I was hoping
that maybe you could help me with this.
I know you ve presented exhibits that show
how irrigators fall into some of various percentage
categories.Do you have any material, or can you at
least tell me here today, what the average increase this
might be for irrigators in dollars and cents on a monthly
basis?I think that will give me a better understanding.
And also in that, if you could also, if you know , help me
understand a little bit more about irrigators and the
fact that I believe many of them testified recently they
have four and five different pumping sites, some more
specific facility.So I'm trying to get a better picture
CSB REPORTING
Wilder, Idaho
BRILZ (Com)
Idaho Power Company
938
83676
of what the real dollars and cents impact is as I try to
get my hands around the issue of rate shock.
Okay.A good place to look to try to get
a sense of the dollars is my Exhibit 44 , and page 6 of
that exhibit.Mr. Budge and I talked a bit about the
percentage impact but there's also on that exhibit a
column that identifies the average annual increase per
And so , for example, if you look at thecustomer.
customers that fall into the last percentage range I'
indicated there would be a greater than 50 percent
increase, the average annual increase per customer is
$102.
Now, let's go back to the meter.Every
meter means another customer; correct?
Each metered service point receives a
bill. And, yes , we generally count each metered service
point as a customer.
So when we're talking about, let's say, a
single irrigator then, they may see an annual increase,
if they're at this $3,000 annual increase level on page
6, they may have four or five bills that are at that
level.
That is correct.
Okay.Thank you.
CSB REPORTING
Wilder , Idaho
BRILZ (Com)
Idaho Power Company
939
83676
EXAMINATION
BY COMMISSIONER SMITH:
Okay.I just have one clarification that
was generated by your responses to Commissioner Hanson'
questions and that was on the discussion you had about
the contributions and how they ultimately, if they're not
refunded, reduce your plant accounts.And what I
understood you to say is that all customer classes are
treated the same.
All customer classes follow our Rule H
provisions for what they need to contribute and the
allowances that we provide.
All right.Do you have any idea , or who
could have an idea of the relative size of the
contributions made by the irrigation class as opposed to
other classes?
I mean, are the irrigation class the only
ones that makes this, or do other classes, and if so do
you have any idea of the relative size?
Well, all customers could potentially make
a contribution.The way that the line extension
provisions work is depending on the specific request of
the customer that the cost is identified.We do have
allowances that we give the customer to offset what is
CSB REPORTING
Wilder, Idaho
BRILZ (Com)
Idaho Power Company
940
83676
required from that customer.
Right.
I do not have with me any information that
would identify the average contribution per customer in a
customer class.
I mean, you could make the assumption, one
assumption is that irrigators are subsidizing or
providing a benefit to all of the customers of the Idaho
Power system because if they don't get the money back it
reduces plant.
And I guess my question is , is the same
kind of benefit being provided by other customer classes
and, you know, does it equal out or is there some kind of
imbalance in that system?And you I re not the right
person to ask , are you?
Well , I don't have the specifics.
sense is that it generally evens out because the
allowances are designed to provide a sense of equity
amongst the customers.And because of that it's my sense
that it overall evens out.
Well, if irrigators move and change and
install more frequently and therefore pay more charges,
you know , they might feel like they re subsidizing
everyone, but if there's kind of an equal churn amongst
all the classes maybe it's different.So, I don t know.
CSB REPORTING
Wilder, Idaho
BRILZ (Com)
Idaho Power Company
941
83676
Who s the right person?I s there anybody here who
Commissioner Smith?MR. KLINE:
Mr. Kline.COMMISSIONER SMITH:
m not the right person.MR. KLINE:
There's no question about that.But what we might offer
to do, I don't think there's anybody here that could give
you - - we have haven't done that analysis, I don
believe.But we could make an effort to do that kind of
analysis and get it to you before the close of the
proceeding.
I think that would beCOMMISSIONER SMITH:
beneficial.Thank you.
Do you have redirect?
I do have a few redirectMR. KLINE:
questions.
REDIRECT EXAMINATION
BY MR. KLINE:
Yesterday, Ms. Brilz, in an answer to a
question posed to you by Mr. Eddie, you stated that Idaho
Power did not directly consider low income in setting the
monthly service charge.Could you elaborate a little bit
on that question after having thought about it overnight?
In determining the proposed serviceYes.
CSB REPORTING
Wilder , Idaho
BRILZ (Di)
Idaho Power Company
942
83676
charge for residential customers , we looked at the cost
of providing the service and did not see any relationship
in the cost versus the income level of the customer.And
so the proposal was based strictly on what we identified
as the cost to provide the service.
All right.Turning to some questions
posed to you by Mr. Richardson.First of all, he asked
you about a time-of -use proposal for special contracts
and the fact the Company hadn't done that.
Wouldn't, with special contracts, I mean,
they are what they say.They have contracts.Wouldn
you have to address any kind of a time-of-use issue with
those customers at the time you renegotiate their
contracts?
That is correct.The pricing structure
included in the contract is determined at the time the
contract is signed.And in order to make a change in
those pricing structures you would need to negotiate a
contract.
Okay.Mr. Richardson also mentioned that
the Schedule 9 class had asked for a voluntary
time-of -use schedule.In fact, that's just one customer,
Kroger, isn t that correct, that raised that issue in
this case?
That is correct.
CSB REPORTING
Wilder , Idaho
BRILZ (Di)
Idaho Power Company
943
83676
And there s no - - but there s been no
ground swell from Schedule 9 asking for time-of-use
rights; is that right?
That is correct.
You had a series of questionsLet's see.
and answers with Mr. Budge regarding the size of
deficiencies in the IRP versus monthly weighting factors
for allocations.And isn't it true that the weighting
factors are really the marginal costs of providing the
service as compared to the size of deficiencies?
That is correct.
In response to a question from
Commissioner Hansen about the changing, things change as
they go along, and rate shock , and those kinds of things.
That was kind of a colloquy you had.
I s the Company s current proposal to set
irrigation rates materially different than what it has
done in the past few rate cases, to your knowledge?
I know in the last few rate cases our
cost-of-service analysis has indicated an increase the
irrigation customer class greater than what the Company
has recommended that class receive.
And you're generally - - but you
consistently applied cost of service as the initial basis
for making recommendations for rate increases for the
CSB REPORTING
Wilder, Idaho
BRILZ (Di)
Idaho Power Company
944
83676
irrigation class, has the Company not done that?
That is correct.
Both Mr. Richardson and Mr. Budge asked
you questions about whether the Company had done a study
to assess the cost benefits for , in the case of Mr.
Richardson for time of use rates, and in the case of Mr.
Budge for rate shock.The effect of the Company
proposal.How long have you, Maggie, been involved in
utility rate making, and cost of service, and utility
rate design?
For about 18 years.
And do you know how long Mr. Gale has been
doing those same kinds of functions for Idaho Power?
About 20 years.
I guess my question is, in your opinion do
you always need to do a study in order for you to apply
your judgment and your experience in rate design to a
rate issue?
I don't believe an extensive study is
necessarily always something that needs to be done.
Certainly you look at the goals and obj ecti ves you
trying to achieve and attempt to propose a pricing
structure that meets those obj ecti ves .But an extensive
study is not always needed for that.
Ms. Brilz , yesterday there was a lot of
CSB REPORTING
Wilder, Idaho
BRILZ (Di)
Idaho Power Company
945
83676
questions from Mr. Richardson regarding the problems and
concerns that the schedule 19 customers had with the
Company s time-of -use implementation, the schedule for
doing that.
Overnight have you had an opportunity to
think about the possibility of having a grace period for
time-of -use implementation for the schedule 19 customers?
Yes, I have.Mr. Richardson had suggested
that there be a grace period to help customers become
more familiar and be able to adapt to time-of-use pricing
and after reconsidering his suggestion I could support
such a grace period.
What I would suggest is that the Company
continue to provide the information we currently have
been providing our industrial customers that would show
them the impact of the pricing on their particular
facility.We currently have provided that information to
a large number of customers who have requested it.
would recommend that it be information that we provide to
all customers whether they ask to have it or not.
That would include, perhaps, even meeting
face-to-face with customers, explaining it to them
providing the phantom bills, those kinds of things?
Certainly.That is the type of
communication we ve had with our customers since we filed
CSB REPORTING
Wilder, Idaho
BRILZ (Di)
Idaho Power Company
946
83676
the rate case to explain the proposal.I would recommend
that same type of process continue.
That's all I have.MR. KLINE:
COMMISSIONER SMITH:Thank you, Mr. Kl ine .
And thank you, Ms. Brilz.
At this time Idaho Power IMR. KLINE:
next witness is William Avera.And Madame Chairman , we
will be spreading Mr. Avera's direct and rebuttal at this
time so if people need two books in front of them they
need to get them.
WILLIAM AVERA
produced as a witness at the instance of Idaho Power
Company, having been first duly sworn , was examined and
testified as follows:
DIRECT EXAMINATION
BY MR. KLINE:
Are you ready?
Yes.
Would you please state your name for the
record, please?
William E. Avera.
Mr. Avera, have you previously filed,
CSB REPORTING
Wilder , Idaho
AVERA (Di)
Idaho Power Company
947
83676
prefiled in this case, 86 pages of direct testimony and
Exhibits 5 through 11 in support of that direct
testimony?
Yes , sir.
All right.And do you have any additions
or corrections that you need to make to your direct
testimony?
No, sir , I do not.
All right.And with that, if I were to
ask you the questions that were contained in your direct
testimony today, would your answers be the same?
Yes , sir.
Madame Chairman , I would requestMR. KLINE:
that Mr. Avera's direct testimony be spread on the record
as if it had been read in its entirety, and Exhibits 5
through 11 be marked for identification.
I f there s no obj ection COMMISSIONER SMITH:
is so ordered.
(The following prefiled direct testimony of
Mr. William Avera is spread upon the record.
CSB REPORTING
Wilder , Idaho
AVERA (Di)
Idaho Power Company
948
83676
INTRODUCTION
Please state your name and business address.
William E. Avera, 3907 Red River , Austin,
Texas, 78751.
What is your present occupation?
I am a financial , economic, and policy
consul tant to business and government.
A. Qualifications
What are your qualifications?
I received a B. A. degree with a maj or in
economics from Emory Uni versi ty.After serving in the
Uni ted States Navy, I entered the doctoral program in
economics at the University of North Carolina at Chapel
Hill.Upon receiving my Ph.D., I joined the faculty at
the University of North Carolina and taught finance in
the Graduate School of Business.I subsequently accepted
a position at the University of Texas at Austin where
taught courses in financial management and investment
analysis.I then went to work for International Paper
Company in New York City as Manager of Financial
Education, a position in which I had responsibility for
all corporate education programs in finance, accounting,
and economics.
In 1977 , I joined the staff of the Public Utility
Commission of Texas ("PUCT") as Director of the Economic
949 AVERA, DI
Idaho Power Company
Research Division.During my tenure at the PUCT , I
managed a division responsible for financial analysis,
cost allocation and rate design , economic and financial
research, and data processing systems, and I testified in
cases on a variety of financial and economic issues.
Since leaving the PUCT in 1979, I have been engaged as a
consul tant. I have participated in a wide range of
assignments involving utility-related matters on behalf
of utilities, industrial customers , municipalities, and
regulatory commissions.I have previously testified
before the Federal Energy Regulatory Commission ("FERC"
as well as the Federal Communications Commission (" FCC"
) ,
the Surface Transportation Board (and its predecessor
the Interstate Commerce Commission), the Canadian
Radio-Television and Telecommunications Commission, and
regulatory agencies, courts , and legislative committees
in 30 states , including the Idaho Public Utilities
Commission (" the Commission" or "IPUC").
with the approval of then-Governor George W. Bush, I
was appointed by the PUCT to the Synchronous
Interconnection Committee to advise the Texas legislature
on the costs and benefits of connecting Texas to the
national electric transmission grid.Currently, I serve
as an outside director of Georgia System Operations
Corporation, the system operator for electric
950 AVERA , DI
Idaho Power Company
cooperatives in Georgia.
I have served as Lecturer in the Finance Department
at the University of Texas at Austin and taught in the
evening graduate program at St. Edward's University for
In addition , I have lectured on economictwenty years.
and regulatory topics in programs sponsored by
universities and industry groups.I have taught in
hundreds of educational programs for financial analysts
in programs sponsored by the Association for Investment
Management and Research, the Financial Analysts Review,
and local financial analysts societies.These programs
have been presented in Asia , Europe, and North America,
including the Financial Analysts Seminar at Northwestern
Uni versi ty.I hold the Chartered Financial Analyst
(CFA~) designation and have served as Vice President for
Membership of the Financial Management Association. I
have also served on the Board of Directors of the North
Carolina Society of Financial Analysts.I was elected
Vice Chairman of the National Association of Regulatory
Commissioners ("NARUC") Subcommittee on Economics and
appointed to NARUC' s Technical Subcommittee on the
National Energy Act.I have also served as an officer of
various other professional organizations and societies.
A resume containing the details of my experience and
qualifications is attached as Exhibit No. 11.
951 AVERA, DI
Idaho Power Company
B. Overview
What is the purpose of your testimony in this
case?
The purpose of my testimony is to present to
the Commission my independent evaluation of a fair rate
of return on equity ("ROE") range for Idaho Power
Company's Idaho jurisdictional electric util i ty
operations.
Please summarize the basis of your knowledge
and conclusions concerning the issues to which you are
testifying in this case.
To prepare my testimony, I used information
from a variety of sources that would customarily be
relied on by a person in my area of expertise.I am
familiar with the organization and operations of Idaho
Power from my prior participation before the Commission
on behalf of the Company in Case No. IPC-94-
connection with the present filing, I considered
information relevant to Idaho Power obtained through
discussions with corporate management and from my review
of numerous documents relating to the Company and its
( " IDACORP") .These includedparent, IDACORP, Inc.
financial reports and filings , prior regulatory
proceedings and orders, as well as bond rating agency
I also reviewed information relating generallyreport s
952 AVERA, DI
Idaho Power Company
to current capital market conditions and specifically to
investor perceptions, requirements, and
953 AVERA, DI
Idaho Power Company
expectations for vertically integrated electric utilities
like Idaho Power.These sources, coupled with my
experience in the fields of finance and utility
regulation , have given me a working knowledge of
investors' ROE requirements confronting Idaho Power as it
competes to attract capital, and form the basis of my
analyses and conclusions.
What is the role of ROE in setting a utility
rates?
The rate of return on common equity serves to
compensate investors for the use of their capital to
finance the plant and equipment necessary to provide
utility service.Investors only commit money in
anticipation of earning a return on their investment
commensurate with that available from other investment
alternatives having comparable risks.Consistent with
both sound regulatory economics and the standards
specified in the Bluefield (Bluefield Water Works
Improvement Co. v. Pub. Servo Comm'262 S. 679
(1923)) and Hope (Fed. Power Comm'n v. Hope Natural Gas
Co., 320 U.S. 591 (1944) J cases, the return on investment
allowed a utility should be sufficient to: 1) fairly
compensate capital invested in the utility, 2) enable the
utility to offer a return adequate to attract new capital
on reasonable terms , and 3) maintain the utility'financial integrity.
954 AVERA , DI
Idaho Power Company
How did you go about developing your
conclusions regarding a fair rate of return on equity
range for Idaho Power?
I first reviewed the operations and finances of
Idaho Power and the general conditions in the electric
utili ty industry and the economy.With this as a
background, I developed the principles underlying the
cost of equity concept and then conducted various
generally accepted quantitative analyses to estimate the
Company s current cost of equity.These included
discounted cash flow ("DCF") analyses and risk premium
methods applied to a reference group of electric
utilities , as well as reference to earned rates of return
expected for utilities and industrial firms.Based on
the cost of equity estimates indicated by my analyses,
the Company I s ROE was evaluated taking into account the
relative strengths and weaknesses of the al ternati ve
methods , as well as other factors (e.g., flotation costs)
that are properly considered in setting the ROE for Idaho
Power I S electric utility operations in Idaho.
C. Summary of Conclusions
Please summarize your findings regarding the
fair rate of return on equity for Idaho Power.
My quantitative analyses of the cost of equity
included applications of the DCF model and risk premium
955 AVERA, DI
Idaho Power Company
methods to a benchmark group of eight electric utilities
operating in the western U. s.Based on the results of
these approaches, I concluded that the fair rate of
return on common equity for Idaho Power is presently in
the range of 10.6 to 11.9 percent.
In evaluating the ROE for Idaho Power , it is
important to consider investors' continued focus on the
unsettled conditions in western power markets and the
unique risks imposed by the Company's much greater
reliance on hydroelectric generation to meet its energy
needs. Regulatory uncertainties, along with unfavorable
capital market conditions, compound the investment risks
associated with the jurisdictional utility operations of
Idaho Power.Coupled with investors' expectations for
higher utility bond yields going forward, these greater
risks support the reasonableness of my 10.6 to 11.
percent ROE range.
The cost of fully funding the Company's return on
common equity is small relative to the potential benefits
that a financially sound utility can have in providing
reliable service at reasonable rates and supporting
economic growth.Considering the importance of ensuring
investor confidence and maintaining Idaho Power'
financial flexibility and the ability to attract needed
capital , an ROE in the 10.6 to 11.9 percent range is both
956 AVERA, DI
Idaho Power Company
necessary and reasonable at this critical juncture.
II.FUNDAMENTAL ANALYSES
What is the purpose of this section?
This section examines the risks and prospects
for the electric utility industry as a whole and
condi tions in the capital markets and the general
An understanding of these fundamental factorseconomy.
that drive the risks and prospects of electric utilities
is essential to developing an informed opinion about
current investor expectations and requirements that form
the basis of a fair rate of return on equity.
addition, as a predicate to my economic and capital
market analyses , this section briefly describes Idaho
Power and reviews its operations and finances.
Idaho Power Company
Briefly describe Idaho Power.
Headquart ered Boise,Idaho Power
wholly-owned subsidiary of IDACORP and is principally
engaged in providing integrated retail electric utility
service in a 20,000 square mile area in southern Idaho
and eastern Oregon.During the most recent fiscal year,
Idaho Power I s energy deliveries totaled 15.0 million
megawatt hours ("mWh"Sales to residential customers
comprised 34 percent of retail sales, with 27 percent to
commercial , 25 percent to industrial end-users, and
957 AVERA, DI
Idaho Power Company
percent attributable to irrigation pumping.Idaho Power
also
958 AVERA, DI
Idaho Power Company
supplies firm wholesale power service to various
utilities and municipalities, as well as three large
customers under sales contracts.Idaho Power's service
area has experienced strong population growth, expanding
over 10 percent in the last decade compared with the
national average of 3.8 percent.
At year-end 2002, Idaho Power had total assets of
$2.7 billion and during the most recent fiscal year total
electric revenues amounted to approximately $867 million.
Principal industries in the area include food processing,
lumber , electronics and general manufacturing, fertilizer
production, and year-round recreational facilities, such
as those in the Sun Valley resort area.Idaho Power
anticipates total capital expenditures of approximately
$675 million over the next three years.The Company
recently approved a development contract, subj ect
Commission approval , for construction of a 160 megawatt
("MW") gas-fired generating plant near Mountain Home,
Idaho.Total cost of the proj ect, which includes plant
construction and necessary transmission system upgrades,
is $61 million, with Idaho Power taking ownership once
the facility has been fully tested and operational.
order to provide additional support for its capital
expendi ture program , Idaho Power's Board of Directors
Board") voted to cut its common stock dividends for the
next quarter by
959 AVERA, DI
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more than $6 million, prompting IDACORP to announced that
it was reducing annual common dividends some 35 percent
from $1.86 to $1.20 per share.
With a combined capacity of approximately 3,117 MW,
Idaho Power I s existing generating units include 17
hydroelectric generating plants located in southern Idaho
and interests in three coal-fired plants located in
Oregon , Nevada , and Wyoming.During 2002 , company-owned
generation accounted for 82.1 percent of the electric
energy provided by Idaho Power , with the balance being
obtained through power purchases.The electrical output
of its hydroelectric plants is dependent on streamflows,
which have fallen below normal levels for the last three
As a result, approximately 45 percent of Idahoyears.
Power's total system generation in 2002 was provided by
hydroelectric generation , as compared with 57 percent
under normal conditions.Snowpack and upstream reservoir
storage for 2003 have fallen below measurements for the
previous year and Idaho Power is experiencing its fourth
consecutive year of below-normal water conditions.
Idaho Power's transmission system interconnects the
Company with other western electric utilities.Coupled
wi th Idaho Power I s membership in the Western Electricity
Coordinating Council, the Western Systems Power Pool , the
Northwest Power Pool and the Northwest Regional
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Idaho Power Company
Transmission Association, these transmission
interconnections permit the interchange, purchase, and
sale of power among all maj or electric systems in the
west.
Idaho Power is subj ect to state retail regulation in
Idaho and Oregon and at the federal level by FERC.
Additionally, Idaho Power's hydroelectric facilities are
subj ect to licensing under the Federal Power Act, which
is administered by FERC, as well as the Oregon
Hydroelectric Act.Currently, the permanent licenses for
five of Idaho Power's hydroelectric facilities have
expired.Idaho Power is actively seeking relicensing
under a process that could continue for up to 15 years.
Relicensing is not automatic under federal law , and Idaho
Power must demonstrate that it has operated its
facili ties in the public interest, which includes
adequately addressing environmental concerns.The most
significant of Idaho Power's relicensing efforts concerns
its Hells Canyon Complex , which represent 68 percent of
the Company's hydro capacity and 40 percent of its total
generating capability.After a prolonged period of
planning and consultation with interested parties, Idaho
Power has developed a draft license application that
includes various protection, mitigation , and enhancement
measures in order to address environmental concerns while
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Idaho Power Company
preserving the peak and load following operations of the
facilities.The estimated cost of these measures is $78
962 AVERA , DI 11a
Idaho Power Company
million in the first five years of the license.
How are fluctuations in Idaho Power's operating
expenses caused by varying hydro and power market
conditions accommodated in its rates?
Beginning in May 1993 , Idaho Power implemented
a power cost adjustment mechanism ("PCA"), under which
rates are adjusted annually to reflect changes in
variable power production and supply costs.When
hydroelectric generation is reduced and power supply
costs rise above those included in base rates, the PCA
allows Idaho Power to increase rates to recover a portion
of its additional costs.Conversely, if increased
hydroelectric generation were to lead to lower power
supply costs, rates would be reduced.Although the PCA
provides for rates to be adj usted annually, it applies to
90 percent of the deviation between actual power supply
costs and normalized rates.As a resul t, the net amount
of power supply costs not recovered through the PCA
mechanism totaled approximately $55.2 million over the
past three years.
What credit ratings have been assigned to Idaho
Power and its parent,IDACORP?
Idaho Power and its parent,IDACORP are both
currently assigned a corporate credit rating of "A-" by
Standard & Poor I s Corporation (" S&P") .Meanwhile,
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Idaho Power Company
Moody s Investors Service ("Moody s) has assigned issuer
credit
964 AVERA, DI 12a
Idaho Power Company
ratings of "A3" and "Baal" to Idaho Power and IDACORP
respectively.S&P recently revised its outlook on both
companies downward from "posi ti ve" to "stable", primarily
due to expected weakness attributable to Idaho Power
ongoing recovery of deferred power costs, poor water
condi tions, and lower than expected sales.
B. Electric Power Industry
What are the general conditions in the electric
power industry?
For almost twenty years, electric utili ties and
their consumers have enj oyed a respite from the
volatility characteristic of the late 1970s and early
More recently, however , these general economic1980s.
factors have been overshadowed by structural changes in
the electric utility industry resulting from market
forces, decontrol ini tiati ves, and judicial decisions.
Please describe these structural changes.
At the federal level, FERC has been an
aggressive proponent of regulatory driven reforms
designed to foster greater competition in markets for
wholesale power supply.The National Energy Policy Act
of 1992 , which reformed the Public Utility Holding
Company Act of 1935, and to a limited extent, the Federal
Power Act, greatly increased prospective competition for
the production and sale of power at the wholesale level.
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Idaho Power Company
In April 1996, FERC adopted Order No. 888, mandating
open access " to the transmission facilities of
jurisdictional electric utilities.FERC al so has pushed
for the regionalization of transmission system control by
establishing frameworks for creation of Regional
Transmission Organizations ("RTOs") in its Order No.
and through subsequent policy statements. "Open20003
access" has, in the view of most market observers,
resulted in more competition and competitors in wholesale
power markets, but not without the introduction of
substantial risks.
Policies affecting competition in the electric power
industry vary widely at the state level , but over 25
jurisdictions have enacted some form of industry
restructuring.This process of industry transition has
led to the disaggregation of many formerly integrated
electric utilities into three primary components
generation , transmission, and distribution.Presently,
however , Idaho Power is, and is expected to remain, a
fully integrated public utility.
What impact has the western power crisis had on
investors ' risk perceptions for firms involved in the
electric power industry?
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Idaho Power Company
During the course of the last several years,
investors have dramatically altered their assessment of
the relative risks associated with the electric power
industry.A well-publicized energy crisis throughout the
west, which originated in California, has wreaked havoc
on the region's customers, utilities, and policYffiakers.
It also has had dramatic repercussions for western
wholesale power markets and investors and utilities
nationwide.Beyond causing state regulators and
legislators to re-evaluate their restructuring
ini tiati ves for the retail sector of the electric
industry, the financial implications of the California
experience demonstrated the risks facing all segments of
the electric power industry.
The massive debts owed by California's retail
utilities to banks, power producers and other creditors
shattered their financial integrity and the subsequent
bankruptcy filing of Pacific Gas and Electric Company
("PG&E") brought the uncertainties associated with
today s power markets into sharp focus for the investment
communi ty.Enron I S, and now Mirant Corporation
bankruptcies only served to magnify the risks associated
with the power sector and increased investors' reluctance
to commit capital in the energy industry, as FERC
Commissioner Massey succinctly recognized:
Sadly, the tsunami of the western energy crisis,
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Idaho Power Company
coupled with the collapse of Enron, have left a
devastating wake within the industry. Investor
confidence has been shaken by these events, by adeclining national economy, indictments of energy
traders, accounting irregularities, downgrades by
rating agencies, and continuing investigations by
the FERC, CFTC , the SEC, and the Justice Department.
...
The flight of capital from the industry has been
severe since the collapse of Enron.
While the case of California and PG&E represents an
extreme example, there is every indication that
investors' risk perceptions for electric utilities have
shifted sharply upward as events in the western U. s.
continued to unfold.The resolution is far from over , as
even today, FERC, federal and state courts, and other
agencies continue their investigations to determine the
underlying causes of the volatility, high prices and
erratic supply patterns characteristic of western
wholesale power markets in 2000 and 2001.
Have these events affected electric utilities
credi t standing?
The last several years have witnessed aYes.
steady erosion in credit quality throughout the electric
utility industry, both as a result of revised perceptions
of the risks in the industry and the weakened finances of
the utilities themselves.For example, during 2002 , S&P
recorded 182 downgrades in the electric power industry,
versus only 15 upgrades, while Moody's downgraded 109
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Idaho Power Company
utili ty issuers and upgraded one; an acceleration of the
trend in bond rating changes during the previous two
The fourth quarter of 2002 alone witnessed 48years.
downgrades as the negative pressure on utility
credi tworthiness continued unabated.
What is the impact of these capital and credit
market conditions on the ability of electric utilities to
raise funds?
Combined with a stagnant economy and global
uncertainties, the dramatic upward shift in investors
risk perceptions and the weakened financial picture of
most industry participants, have combined to produce a
severe liquidity crunch in the electric power industry.
S&P cited the debilitating impact of these developments
on investors' willingness to provide capital:
The last 24 months have witnessed extraordinary
turmoil for power and energy debt,unprecedented since samuel Insull's utility
empire collapsed during the 1930s. Events
ranging from the credit collapse of the
California utilities , through the Enron
bankruptcy and subsequent market disruptions
for U. S. energy merchant companies have
destroyed billions of dollars of value forinvestors. Wall Street has virtually shut down
new investment in this sector.
Increasingly constrained capital market access
as a result of investor skepticism over
accounting practices and disclosure, more and
more federal and state investigations and
subpoenas, audits, and failing confidence in
future financial performance has created a
iquidi ty crisis.
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Idaho Power Company
In light of the challenges faced by electric
utilities , financing activity actually declined some 14
percent in 2002, with many utilities being forced to rely
increasingly on bank debt.Access to the commercial
paper markets, long the low-cost staple of high-grade
utility credits for meeting working capital needs,
virtually disappeared for certain companies.S&P noted
that the falloff in financing activity was partly
attributable to "capital market jitters, especially for
those firms that are most in need of capital market
As a result, at the same time that industryaccess.
uncertainty and market volatility has increased the
importance of financial flexibility, electric utilities
are facing limited access and higher costs for the
capi tal required to maintain sufficient liquidity.
Moreover, credit quality has continued to decline.S&P
reported an unprecedented 88 ratings downgrades during
the first half of 2003 alone, an acceleration of the
downward trend witnessed during the previous year. 9
Similarly, Moody I s downgraded 51 utili ties between
January and J~ne 2003, while upgrading only one firm.
S&P also noted that constrained access to capital markets
and investor skepticism was contributing to the bleak
credi t picture.
Q. How has Idaho Power been impacted by the
turmoil in the electric power industry?
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Idaho Power Company
Like others, Idaho Power was swept up in the
maelstrom of the western energy crisis in 2000 and 2001.
Because of Idaho Power's dependence on hydroelectric
generation , it has always faced the uncertainties
associated with year-to-year fluctuations in water
condi t ions.Nevertheless, the degree of price volatility
that participants in the western power markets were
forced to assume was unprecedented and variability in
short-term market prices bore no resemblance to
fluctuations encountered in the past.
Increased wholesale prices and rate structures that
did not capture full costs of acquiring fuel and
purchased power led to depressed earnings.As of
December 31, 2001 , for example, Idaho Power had recorded
a regulatory asset of $290 million related primarily to
power cost deferrals resulting from low hydroelectric
generation and higher purchased power prices.
varying degrees, utilities throughout the western U. s.
were confronted with the difficult task of maintaining
reliable service and financial integrity in a power
market characteri zed by short supply and unprecedented
price volatil i ty.Municipal utilities in the Northwest
were also forced to approve or propose significant rate
increases to recover rising fuel and purchased power
costS.
Even for electric utilities such as Idaho Power that
971 AVERA, DI
Idaho Power Company
have permanent fuel and purchased power adj ustment
mechanisms in place, there can be a significant lag
between the time the utility actually incurs the
expendi ture and when it is recovered from ratepayers.
One example of this regulatory lag was noted by The Value
Line Investment Survey (Value Line) :
A lag in the recovery of sharply higher power
costs is hurting Sierra Pacific Resources.
Power prices in the West have soared since the
second quarter of 2000, and until recently,
SPR's two utilities lacked a mechanism for
recovering these increases. The Nevada
Commission has granted one, but it won't solve
the utilities' problem right away. That'
because the mechanism tracks power costs over a
trailing 12 -month period and because the amount
by which the utilities can raise rates each
month is capped .
Because Idaho Power was dependent on wholesale power
markets in the west to meet the gap in its resource needs
created by reduced hydro generation , the chaotic market
condi tions were felt directly.The cont inuing prospect
of further turmoil in western power markets cannot be
discounted.From the standpoint of the capital markets,
the west is risky - and Idaho Power's exposure to
wholesale markets in meeting shortfalls in hydroelectric
generation compounds these uncertainties.
Investors recognize that volatile markets,
unpredictable stream flows, and Idaho Power's dependence
on wholesale purchases to meet the needs of its customers
972 AVERA, DI
Idaho Power Company
can create a "perfect storm", exposing the Company to the
risk of reduced cash flows and unrecovered power supply
In response to the risks inherent in substantialcosts.
reliance on wholesale power markets for electricity
supply, and recognizing the continuing uncertainty
concerning the availability of hydroelectric generation,
Idaho Power has proposed a plan to expand its electric
utility system , including the construction of additional
generating resources at Mountain Home.Accordingly,
maintaining Idaho Power s financial integrity and
flexibility will be instrumental in attracting the
capi tal necessary to fund these proj ects in an effective
manner.
What are the implications of the recent power
outages recently experienced in the upper Midwest and
Northeast?
These events underscore the continuing risks
inherent in the industry and the uncertain state of
affairs with respect to the industry's structure.The
massive blackout, which stretched from New York to
Detroi t and from Ohio into Canada, was the largest power
outage in U. S. history.This single event has galvanized
the attention of all industry stakeholders - utilities,
consumers, regulators, and investors - on the urgent need
to improve the nation's electricity infrastructure,
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Idaho Power Company
especially in light of the additional stress that
deregulated wholesale
974 AVERA, DI 21a
Idaho Power Company
markets have placed on the network.The importance of
rapidly stimulating investment in electric power
infrastructure has been almost universally cited as the
key to ensuring that further outages are avoided.
FERC Chairman Wood noted:
If we draw any conclusions from this blackout,
it is the urgent need for more investment in
the nation s transmission grid to serve broad
regional needs .
Indeed, as noted earlier, Idaho Power is committed to
expanding the scope and reliability of its utility system
in order to provide customers with reliable service while
attempting to insulate them from the potential impact of
power market anomalies.
Are investors likely to consider the impact
industry uncertainty in assessing their required rate of
return for Idaho Power?
Absolutely.While electric utility
restructuring has not been actively pursued in Idaho, the
Company continues to face the prospect of FERC-driven
changes in the transmission sector of their business, as
well as fundamental reforms in the operation of wholesale
markets.Idaho Power is an active participant in the
formation of a proposed RTO ("RTO West"), an independent
entity that will operate the transmission grid in seven
While RTO West received Stage western states.
975 AVERA, DI
Idaho Power Company
approval from FERC, substantial additional filings will
be necessary before federal and state approval are
received.
Indeed, the pace of policy evolution in the
transmission area has been brisk.Investors' focus on
regulatory change in their assessment of risks and
prospects was exemplified by S&P:
The FERC is in the process of changing every
aspect of the electric utility landscape, with
industry sages anticipating further
transmission and wholesale market development
guidance, which could affect the segment'
credit prospects and quality. ...Significant
uncertainty still exists for transmission
companies that may operate under an RTO or ISO
structure, which will significantly impact the
full scope of capital expenditures necessary to
ensure reliability and increase capacity in thefuture. Uncertainty will exist until operating
rules are in place and have stabilized.
Virtually all industry stakeholders have recognized that
regulatory uncertainty increases the risks associated
wi th the electric industry.FERC Commissioner Massey
says that regulatory uncertainty is "part of the problem"
explaining under-investment in electric utility
infrastructure.The Department of Energy ("DOE")
identified "reducing regulatory uncertainty " as critical
in stimulating increased investment in the power industry
and has noted that lack of clarity in the regulatory
structure was inhibiting planning and investment .The
DOE also recognized the impact that this regulatory
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Idaho Power Company
uncertainty has on investors ' required rates of return
for electric utilities:
Because transmission assets are long lived,
regulatory uncertainty increases the risks to
investors and , therefore, increases the returns
they need to justify transmission systeminvestments.
In remarks before NARUC, a representative of MBIA
Insurance Corporation, the world's largest financial
guaranty insurance company, noted the increased risks
posed by inconsistent regulatory decision-making "have
made access to the capital markets very difficult and
very expensive. "21 Similarly, while the Consumer Energy
Council of America recognized that improvements in
electric utility infrastructure are necessary to ensure
reliability and support the economy, they concluded that
regulatory uncertainty "has contributed to a fear of
instability for the entire system". 22
The recent blackout has only served to reinforce the
importance of regulatory risks for investors.The Wall
Street Journal cited the debilitating impact of an
unsteady regulatory environment" and the chaotic
combination of regulated and deregulated markets " in
explaining inhibitions to increased investment in the
electric utility system.Similarly, FERC Chairman Wood
concluded in his initial comments on the power outages
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Idaho Power Company
that:
Clearly, we need regulatory certainty and other
incentives for investment.
Nevertheless, S&P recently warned investors that the
partial reforms presently characterizing wholesale power
markets invites dysfunction and that elevated risks will
discourage new capital,or at least make it more
expensive. "25 S&P observed:
Investors should not expect that such risk will
dissipate any time soon. Instead, credit risk
could actually intensify if the politically
charged debate over reform continues for years,
as it might very well do. And even if policy
makers succeed in crafting a comprehensive
solution to the problems of the nation I s energy
grid, the regulatory treatment of the costs
needed to upgrade the infrastructure remainsuncertain.
Because of potential dependence on wholesale markets, the
risks of transmission uncertainties and potential market
volatility are intensified for utilities that must meet
shortfalls in resource needs through power purchases.
Thus, Idaho Power's greater dependence on hydroelectric
generation , which fluctuates with changes in streamflows,
exposes the Company and its investors to the ongoing
regulatory uncertainties and other risks imposed by
federal restructuring of wholesale power markets and
magnifies the importance of . maintaining financial
flexibility.Q. Are these uncertainties the only risks being
978 AVERA, DI
Idaho Power Company
faced by electric utilities?
Apart from these factors, the industryNo.
continues to face the normal risks inherent in operating
electric utility systems, including the potential adverse
effects of inflation, interest rate changes, growth, and
regulatory uncertainty and lag.Electric utilities are
confronting increased environmental pressures that leave
them exposed to uncertainties regarding emissions and
potential contamination.S&P recognized the potential
financial challenges posed by such uncertainties:
Pension obligations, environmental liabilities,
and serious legal problems restrictflexibili ty, apart from the obligations' direct
financial implications.
C. Capi tal Markets and Economy
What has been the pattern of interest rates
over the last decade?
Average long-term public utility bond rates,
the monthly average prime rate, and inflation as measured
by the consumer price index since 1990 are plotted in the
graph below.After rising to approximately 10 percent in
mid-1990, the average yield on long-term public utility
bonds generally fell as economic conditions weakened in
the aftermath of the 1991 Gulf war, with rates dipping
below 7 percent in late 1993.Yields subsequently rose
again in 1994 , before beginning a general decline, with
979 AVERA, DI
Idaho Power Company
investors requiring approximately 6.8 percent from
average public utility bonds in August 2003:
8 6iJ c.. ,:,
,-----'----'
flat
--",
-VO
".. -...,~ ~, -. ....-"" ' ..'-..-......-' -;--~ ~
Are investors likely to anticipate any
substantial decline in interest rates going forward?
Since early 2001 , a great deal ofNo.
attention has been focused on the actions of the Federal
Reserve as they have moved successively to lower
short-term interest rates in response to weakness in the
Uni ted States economy.But while interest rates are
currently at relatively low levels, investors are
unlikely to expect any further significant declines going
forward.The general expectation is that , as economic
growth strengthens, interest rates will begin to rise.
For example, the Energy Information Administration
EIA"), a statistical agency of the DOE , routinely
publ ishes a 25 -year forecast for energy markets and the
nation's economy.The most recent forecast, released
November 20 , 2002, anticipates that the double-A public
utility bond yield will increase from 6.
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Idaho Power Company
percent in 2002 to 8.10 percent by 2005 , with the average
being 7.49 percent over the next 10 years. Similarly,
the most recent long-term proj ections from GlobalInsight
(formerly DRI/WEFA) anticipate that public ut ility bond
yields will increase to 8.19 percent by 2007 and average
approximately 7.8 percent over the intervening years.
How has the market for common equity capital
performed?
Between 1990 and early 2000 stock prices pushed
steadily higher as the longest bull market in United
States history continued unabated.While the S&P 500 had
increased over four times in value by August 2000,
mounting concerns regarding prospects for future growth
particularly for firms in the high technology and
telecommunications sectors, pushed equity prices lower,
in some cases precipitously.While equity prices have
recovered from recent lows, the market has become
increasingly volatile, with share values repeatedly
changing in full percentage points during a single day
trading.The graph below plots the performances of the
Dow-Jones Industrial Average, the S&P 500 , and the New
York Stock Exchange Utility Index since 1990 (the latter
two indices were scaled for comparability)
981 AVERA, DI
Idaho Power Company
16,500
500 -
-'--------,-----,..,-----------,-,--- ,- -
500 --,,'
10,500
--.._------------,--,---,-
"t:I 500 --------_n,-
500
4,500
500
_n_'
""""""""'--::;;;"
':N YSE UliIiIL0J_QC~~
~ -
500
J..
What is the outlook for the United States
economy?
During the decade through the first quarter of
2001 , the United States economy enjoyed the longest
peacetime expansion in history.Monetary and fiscal
policies resulted in modest inflation during this period,
with unemployment rates falling to their lowest levels
since the 1960s.A revolution in information technology,
rising productivity, and vibrant international trade all
contributed to strong ~conomic growth.However , even
before the events of September 11, 2001 , there were
increasing signs that the economic expansion would not be
sustainable.Concerns regarding the slowing pace of
economic activity have been exemplified by the Federal
Reserve's sequential lowering of interest rates.The
economy continues to chart an uneven course , corporate
profits remain under pressure, capital spending continues
to be weak, and businesses have been reluctant to expand
982 AVERA , DI
Idaho Power Company
hiring. More recently, uncertainties over the fragility
of the economy have been magnified by the aftermath of
war in Iraq and ongoing instability in the Middle East,
which undermines consumer confidence and contributes to
global economic uncertainty.These factors cause the
outlook to remain tenuous, with persistent stock and bond
price volatility providing tangible evidence of the
uncertainties faced by the United States economy.
How do these economic uncertainties affect
electric utilities?
The weakened state of the economy and the
uncertainty of recovery have combined to heighten the
risks faced by electric utilities.Stagnant economic
growth would undoubtedly mean flat electric sales, while
the potential for higher inflation and interest rates
that would likely accompany an economic recovery would
place additional pressure on the adequacy of existing
service rates.While the economy may ultimately return
to a path of steady growth and the volatility in the
capi tal and energy markets may abate, the underlying
weaknesses now present cause considerable uncertainties
to persist, which increase the risks faced by the
electric utility industry.
III. CAPITAL MARKET ESTIMATES
What is the purpose of this section?
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Idaho Power Company
In this section , capital market estimates of
the cost of equity are developed for a benchmark group of
electric utilities.First, I examine the concept of the
cost of equity, along with the risk-return tradeoff
principle fundamental to capital markets. Next, DCF and
risk premium analyses are conducted to estimate the cost
of equity for a reference group of electric utilities.
A. Economic Standards
What role does the rate of return on common
equity play in a utility s rates?
The return on common equity is the cost of
inducing and retaining investment in common shares.This
investment is necessary to finance the asset base needed
to provide utility service.Competition for investor
funds is intense and investors are free to invest their
funds wherever they choose.They will commit money to a
particular investment only if they expect it to produce a
return commensurate with those from other investments
with comparable risks.Moreover, the return on common
equi ty is integral in achieving the sound regulatory
objectives of rates that are sufficient to: fairly
compensate capital investment in the utility, 2) enable
the utility to offer a return adequate to attract new
capi tal on reasonable terms, and 3) maintain the
utility s financial integrity.
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Idaho Power Company
What fundamental economic principle underlies
this cost of equity concept?
Unlike debt capital, there is no contractually
guaranteed return on common equity capital since
shareholders are the residual owners of the utility.
Nonetheless, common equity investors still require a
return on their investment, with the cost of equity being
the minimum rent" that must be paid for the use of their
This cost of equity typically serves as themoney.
starting point for determining a fair rate of return on
common equity.
The cost of equity concept is predicated on the
notion that investors are risk averse and willingly bear
additional risk only if paid for doing so.In capital
markets where relatively risk-free assets are available
(e.g., U.S. Treasury securities) investors can be induced
to hold more risky assets only if they are offered a
premium , or additional return, above the rate of return
on a risk- free asset.Since all assets - including debt
and equity - compete with each other for scarce
investors' funds, more risky assets must yield a higher
expected rate of return than less risky assets in order
for investors to be willing to hold them.
Given this risk-return tradeoff, the required rate
of return (k) from an asset (i) can be generally
expressed as:
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Idaho Power Company
ki = Rf + RPi
where:Rf = Risk-free rate of return; and
RPi = Risk premium required to holdrisky asset i.
Thus, the required rate of return for a particular asset
at any point in time is a function of: 1) the yield on
risk-free assets, and 2) its relative risk , with
investors demanding correspondingly larger risk premiums
for assets bearing greater risk.
Does the risk-return tradeoff principle
actually operate in the capital markets?
The risk-return tradeoff is observable inYes.
certain segments of the capital markets where required
rates of return can be directly inferred from market data
and generally accepted measures of risk exist.Bond
yields , for example, reflect investors' expected rates of
return, and bond ratings measure the risk of individual
bond issues.The observed yields on government
securi ties, which are considered free of default risk,
and bonds of various rating categories demonstrate that
the risk-return tradeoff does, in fact, exist in the
capital markets.
Does the risk-return tradeoff observed with
fixed income securities extend to common stocks and other
assets?
A. It is generally accepted that the risk-return
tradeoff evidenced with long-term debt extends to all
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Idaho Power Company
Documenting the risk-return tradeoff for assetsassets.
other than fixed income securities, however, is
complicated by two factors.First, there is no standard
measure of risk applicable to all assets.Second, for
most assets - including common stock - required rates of
return cannot be directly observed.Nevertheless, it is
a fundamental tenet that investors exhibit risk aversion
in deciding whether or not to hold common stocks and
other assets , just as when choosing among fixed income
securities.This has been supported and demonstrated by
considerable empirical research in the field of finance
and is confirmed by reference to historical earned rates
of return , with realized rates of return on common stocks
exceeding those on government and corporate bonds over
the long-term.
Is this risk-return tradeoff limited to
differences between firms?
The risk-return tradeoff principle appliesNo.
not only to investments in different firms, but also to
different securities issued by the same firm.Debt,
preferred stock , and common equity vary considerably in
risk because they have different characteristics and
priorities.
When investors loan money to a utility in the form
of long-term debt (or bonds), they enter into a contract
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under which the utility agrees to pay a specified amount
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interest and to repay the principal of the loan in full
at the maturity date.The bondholders have a senior
claim on a utility's available cash flow for these
payments! and if the utility fails to make them, they may
force it into bankruptcy. Following first mortgage bonds
are other debt instruments also holding contractual
claims on the utili ties cash flow , such as debentures and
Similarly, when a utility sells investorsnotes.
preferred stock, the utility promises to pay specified
dividends and, typically, to retire the preferred stock
on a predetermined schedule.The rights of preferred
stockholders to available cash flow for these payments
are junior to creditors, and preferred stockholders
cannot compel bankruptcy, their claims are senior to
those of common shareholders.
The last investors in line are common shareholders.
They receive only the cash flow , if any, that remains
after all other claimants - employees , suppliers,
governments, lenders, have been paid.Because cash flows
to common shareholders are not contractually defined,
di vidend payments may be eliminated altogether or
substantially reduced, as illustrated by the recent
actions of Idaho Power's Board and IDACORP.As a result,
the rate of return that investors require from a
utility s common stock , the most junior and riskiest of
its securities, is considerably
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higher than the yield on the utility s long-term debt.
What does the above discussion imply with
respect to estimating the cost of equity?
Al though the cost of equity cannot be observed
directly, it is a function of the prospective returns
available from other investment alternatives and the
risks to which the equity capital is exposed.Because it
is unobservable, the cost of equity for a particular
utility must be estimated by analyzing information about
capi tal market conditions generally, assessing the
relative risks of the company specifically, and employing
various quanti tati ve methods that focus on investors
current required rates of return.These various
quantitative methods typically attempt to infer
investors' required rates of return from stock prices,
interest rates,other capi tal market data.
Have you reI ied single method to estimate
the cost equity for Idaho Power?
No. In my opinion, no single method or model
should be relied upon to determine a utility's cost of
equi ty because no single approach can be regarded as
wholly reliable.As the Federal Communications
Commission recognized:
Equity prices are established in highly
volatile and uncertain capital markets...
Different forecasting methodologies compete
wi th each other
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for eminence, only to be superceded by other
methodologies as conditions change... In these
circumstances, we should not restrict ourselves
to one methodology, or even a series of
methodologies, that would be appliedmechanically. Instead, we conclude that we
should adopt a more accommodating and flexible
posi tion.
Therefore, in addition to the DCF model , I applied the
risk premium method based on data for electric utilities
and using forward-looking estimates of required rates of
In addition, I also evaluated my results using areturn.
comparable earnings approach based on investors' current
expectations in the capital markets.In my opinion,
comparing estimates produced by one method with those
produced by other approaches ensures that the estimates
of the cost of equity pass fundamental tests of
reasonableness and economic logic.
B. Discounted Cash Flow Analyses
How are DCF models used to estimate the cost of
equity?
The use of DCF models is essentially an attempt
to replicate the market valuation process that sets the
price investors are willing to pay for a share of a
company s stock.The model rests on the assumption that
investors evaluate the risks and expected rates of return
from all securities in the capital markets.Gi ven these
expected rates of return , the price of each stock is
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adj usted by the market until investors are adequately
compensated for the risks they bear.Therefore, we can
look to the market to determine what investors believe a
share of common stock is worth.By estimating the cash
flows investors expect to receive from the stock in the
way of future dividends and capital gains , we can
calculate their required rate of return.In other words,
the cash flows that investors expect from a stock are
estimated, and given its current market price, we can
"back-into" the discount rate, or cost of equity, that
investors presumptively used in bidding the stock to that
price.
What market valuation process underlies DCF
models?
DCF models are derived from a theory of
valuation which assumes that the price of a share of
common stock is equal to the present value of the
expected cash flows (i. e., future dividends and stock
price) that will be received while holding the stock,
discounted at investors ' required rate of return, or the
cost of equity.Notationally, the general form of the
DCF model is as follows:
Po =
+. . .
(1+(1+k 2 (l+k )t (l+K::f
where:Po = Current price per share;
Pt = Expected future price per share inperiod t;
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t = Expected dividend per share in period
e = Cost of equity.
That is, the cost of equity is the discount rate that
will equate the current price of a share of stock with
the present value of all expected cash flows from the
stock.
Has this general form of the DCF model
customarily been used to estimate the cost of equity in
rate cases?
In an effort to reduce the number ofNo.
required estimates and computational difficulties, the
general form of the DCF model has been simplified to a
constant growthll form.But converting the general form
of the DCF model to the constant growth DCF model
requires a number of strict assumptions.These include:
A constant growth rate for both dividends and
earnings;
A stable dividend payout ratio;
The discount rate exceeds the growth rate;
A constant growth rate for book value and price;
A constant earned rate of return on book value;
No sales of stock at a price above or below book
val ue ;
A constant price-earnings ratio;
A constant discount rate (i. e., no changes in
risk or interest rate levels and a flat yield
curve); and
All of the above extend to infinity.
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Given these assumptions, the general form of the DCF
model can be reduced to the more manageable formula of:
Po= -.!2~
Where:g = Investors' long-term growth
expectations.
The cost of equity (Ke) can be isolated by rearranging
terms:
-.J2~ +g
This constant growth form of the DCF model recognizes
that the rate of return to stockholders consists of two
parts: 1) dividend yield (D1 /PO ), and 2) growth (g).
other words, investors expect to receive a portion of
their total return in the form of current dividends and
the remainder through price appreciation.
Are the assumptions underlying the constant
growth form of the DCF model always fully met?
In practice, none of the assumptions required
to convert the general form of the DCF model to the
constant growth form are ever strictly met.
Nevertheless, where earnings are derived from stable
activities, and earnings, dividends, and book value track
fairly closely, the constant growth form of the DCF model
may be a reasonable working approximation of stock
valuation that
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can provide useful insight as to investors' required rate
of return.
How did you implement the DCF model to estimate
the cost of equity for Idaho Power?
Application of the DCF model directly to Idaho
Power is hindered because, as a wholly-owned subsidiary,
the Company does not have publicly traded common stock.
Meanwhile, as discussed earlier, Idaho Power and, in
turn, IDACORP recently elected to cut common dividend
paYments significantly in order to improve cash flow and
help maintain the strong credit ratings necessary to
support the Company's capital expansion plan.Under the
DCF approach , observable stock prices are a function of
the cash flows that investors' expected to receive,
discounted at their required rate of return.Because
dividend payments are a key parameter required to apply
DCF methods, this approach is not well-suited for firms
that do not pay common dividends or have recently cut
their payout.
As an al ternati ve , the cost of equity is often
estimated by applying the DCF model to publicly traded
companies engaged in the same business acti vi ty.
order to reflect the risks and prospects associated with
Idaho Power I s jurisdictional utility operations, my DCF
analyses focused on a reference group of other electric
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utilities composed of those companies included by Value
Line in their
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Electric Utilities (West) Industry group.Exc 1 uded from
my analyses were four firms that do not pay common
dividends and two that were rated below investment grade
by S&P.Given that these eight utilities are all
engaged in electric utility operations in the western
region of the U. S., investors are likely to regard this
group as facing similar market conditions and having
comparable risks and prospects.There are important
factors distinguishing western utilities from those
located in other regions, as the Electric Consumers
Resource Council recently reported:
The West is different than the East in terms ofelectrici ty grid operations, according to
Marsha Smith , a Commissioner with the Idaho
Public Utilities Commission and Chair of
(NARUC). . .. The vast geographic areas served
by western utilities mean electricity is being
transmitted over much longer distances that in
other regions , particularly the East, and there
are fewer customers per mile of transmission
line, resulting in greater line loss, Ms. Smithsaid.
She also said the West's reliance on
hydroelectric energy makes planning more
difficult than in the East. Hydropower cannot
be forecast, and the amount of winter snow
determines how much may be shipped each spring
and summer to power-dependent areas such asCalifornia. Reliance on hydropower makes
long-term planning difficult and plays havoc
with the day-ahead market , envisioned in FERC' s
proposed standard market design (SMD) rule.
Indeed , as noted earlier , the uncertainties associated
wi th relying on hydroelectric generation is an important
consideration in evaluating investors' required rate of
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return for Idaho Power.
What other considerations support the use of a
proxy group in estimating the cost of equity for Idaho
Power?
Apart from recognizing the inherent risks and
prospects for an electric utility operating in the west,
reference to a proxy group of electric utilities is
essential to insulate against vagaries that can result
when the stochastic process involved in estimating the
cost of equity is applied to a single company.The
cost of equity is inherently unobservable and can
only be inferred indirectly by reference to available
capital market data.To the extent that the data
used to apply the DCF model does not capture the
expectations that investors have incorporated into
current stock prices, the resulting cost of equity
estimates will be biased.For example, the potential
for mergers or acquisitions or the announced sale of a
major business segment would undoubtedly influence the
price investors would be willing to pay for a utility
common stock.But because such factors are not typically
reflected in the growth rates used to apply the DCF
model, cost of equity estimates for any single company
may fail to reflect investors I required rate of return.
Indeed, using even a limited group of companies increases
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the potential for error , as the FERC noted in its July
2003 Order on
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Initial Decision in Docket No. RPOO-107-000:
Both Staff and Williston agreed that a proxy
group of only three companies presented
problems because " a single company will have amagnified influence on the group results.
was with those changing market dynamics in mind
that witnesses of both Staff and Williston
proposed to expand the group of proxy companies
to determine a zone of reasonableness.
group composed of western electric utilities isA proxy
consistent not only with the shared circumstances of
electric power markets in the west, but also with the
need to ensure against the potential that a single cost
of equity estimate may not reflect investors' required
rate of return.
What form of the DCF model did you use?
I applied the constant growth DCF model to
estimate the cost of equity for Idaho Power, which is the
form of the model most commonly relied on to establish
the cost of equity for traditional regulated utilities
and the method most often referenced by regulators.
Other forms of the general , or non-constant DCF
model , such as "two-stage" or "multi-stage" analyses can
be used to estimate the cost of equity; however , such
approaches increase the number of inputs that must be
estimated and add to the computational difficulties.
While such methods might be warranted when investors
expect a discontinuity in the operations of a particular
firm or
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industry, they generally require several very specific
assumptions regarding investors' expected cash flows that
must occur at given points in the future.This makes the
results of non-constant growth DCF applications sensitive
to changes in assumptions and, therefore, subject to
greater controversy in a rate case setting.
Moreover , to the that extent each of these
time-specific suppositions about future cash flows do not
reflect what real-world investors actually anticipate,
the resulting cost of equity estimate will be biased.
Indeed, the benchmark for growth in a DCF model is what
investors expect when they purchase stock.Unless we
replicate investors' thinking, we cannot uncover their
required returns and thus the market cost of equity. In
practice, applying a non-constant DCF model would lead to
error if it ignores the requirements of real-world
investors.
Are there circumstances where a multi-stage DCF
model might be preferable to the constant growth form?
The greater complexity of theYes.
non-constant growth DCF model is sometimes warranted when
it is evident that investors anticipate a well-defined
shift in growth rates over the horizon of their
expectations.For example, in response to structural
reforms introduced in the early 1990s , it was widely
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anticipated that certain segments of the electric power
industry would transition
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from fully regulated to competitive businesses.Because
of the difficulty associated with capturing these
expectations in the single growth measure of the constant
growth DCF model, many witnesses, including myself, chose
to apply a multi-stage approach.A number of regulatory
commissions also departed from the simplicity of the
constant growth DCF model that they had traditionally
favored in order to recognize the transition to
competition that was anticipated by investors.
But acceptance of the multi-stage DCF model was
predicated on very specific assumptions tailored to
investors' actual expectations at the time.As discussed
earlier, however, investors are no longer anticipating
that such a transition will take place going forward.
Broad-reaching structural changes once anticipated by
investors at the state and federal levels have been
largely effectuated to the extent investors expect them
In the minds of investors, any new initiativesto occur.
focused on deregulation of the electric utility industry
at the retail level have been indefinitely postponed or
abandoned al together.This is certainly true in Idaho,
where retail deregulation is not being actively pursued.
While the complexity of non-constant DCF models
may impart an aura of accuracy, there is no evidence that
investors' current view of electric utilities anticipates
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a series of discrete, clearly defined stages.As a
resul t, despite the considerable uncertainties now
confronting the electric utility industry, there is no
discernable transition that would support use of the
multi-stage DCF approach.
How is the constant growth form of the DCF
model typically used to estimate the cost of equity?
The first step in implementing the constant
growth DCF model is to determine the expected dividend
yield (D for the firm in question.This is usually
calculated based on an estimate of dividends to be paid
in the coming year divided by the current price of the
stock.The second , and more controversial, step is to
estimate investors' long-term growth expectations (g) for
the firm.Since book value, dividends, earnings, and
price are all assumed to move in lock-step in the
constant growth DCF model , estimates of expected growth
are sometimes derived from historical rates of growth in
these variables under the presumption that investors
expect these rates of growth to continue into the future.
Al ternati vely, a firm's internal growth can be estimated
based on the product of its earnings retention ratio and
earned rate of return on equity.This growth estimate
may rely on either historical or proj ected data , or both.
A third approach is to rely on security analysts
projections of growth as proxies for
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investors' expectations.The final step is to sum the
firm's dividend yield and estimated growth rate to arrive
at an estimate of its cost of equity.
How was the dividend yield for the reference
group of electric utilities determined?
Estimates of dividends to be paid by each of
these electric utili ties over the next twelve months,
obtained from Value Line, served as D This annual
dividend was then divided by the corresponding stock
price for each utility to arrive at the expected dividend
yield.The expected dividends , stock price, and
resulting dividend yields for the firms in the reference
group of electric utilities are presented on Exhibit No.
As shown there, dividend yields for the eight firms
in the electric utility proxy group ranged from 3.
percent to 6.0 percent, with the average being 4.
percent.
What are investors most likely to consider in
developing their long-term growth expectations?
In constant growth DCF theory, earnings,
dividends, book value, and market price are all assumed
to grow in lockstep and the growth horizon of the DCF
model is infinite.But implementation of the DCF model
is more than just a theoretical exercise; it is an
attempt to replicate the mechanism investors used to
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arri ve at observable stock prices.Thus, the only "
that matters in applying the
1006 AVERA, DI 48a
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DCF model is that which investors expect and have
embodied in current market prices.While the
uncertainties inherent with common stock make estimating
investors ' growth expectations a difficult task for any
company, in the case of electric utilities, the problem
is exacerbated due to the ongoing turmoil in the power
industry.
Are dividend growth rates likely to provide a
meaningful guide to investors ' growth expectations for
electric utilities?
While the dividend yield is an importantNo.
component of DCF applications and investors look to
dividends as one indicator of a firm's financial health,
trends in dividends are unlikely to reflect the long-term
g" presumed by the DCF model.As illustrated by the
recent decision of the Board and IDACORP to significantly
reduce their payout, dividend policies for electric
utilities have become increasingly conservative as
business risks in the industry have become more
accentuated.Thus, while earnings may be expected to
grow significantly, dividends have remained largely
stagnant as utilities conserve financial resources to
provide a hedge against heightened uncertainties.
Investors ' focus has increasingly shifted from dividends
to earnings as a measure of long-term growth as payout
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ratios for firms in the electric utility industry have
been trending downward
1008 AVERA, DI 49a
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from approximately 80 percent historically to on the
order of 65 percent. As a result, growth in earnings,
which ultimately support future dividends and share
prices, is likely to provide a more meaningful guide to
investors' long-term growth expectations.
What other evidence suggests that investors are
more apt to consider trends in earnings in developing
growth expectations?
The importance of earnings in evaluating
investors' expectations and requirements is well accepted
in the investment community.As noted in Finding Reali
in Reported Earnings published by the Association for
Investment Management and Research:
(E) arnings, presumably, are the basis for the
investment benefits that we all seek. "Healthy
earnings equal healthy investment benefits
seems a logical equation , but earnings are also
a scorecard by which we compare companies, a
filter through which we assess management, and
a crystal ball in which we try to foretell thefuture.
Value Line s near-term projections and its Timeliness
Rank, which is the principal investment rating assigned
to each individual stock, are also based primarily on
various quantitative analyses of earnings.As Value Line
explained:
The future earnings rank accounts for 65% in
the determination of relative price change in
the future the other two variables (current
earnings
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rank and current price rank) explain 35%.
The fact that investment advisory services , such as Value
Line and I/B/E/S International , Inc.("IBES"), focus on
growth in earnings indicates that the investment
communi ty regards this as a superior indicator of future
long-term growth.Indeed , Financial Analysts Journal
reported the results of a survey conducted to determine
what analytical techniques investment analysts actually
Respondents were asked to rank the relativeuse.
importance of earnings, dividends, cash flow , and book
value in analyzing securities.Of the 297 analysts that
responded , only 3 ranked dividends first while 276 ranked
it last.The article concluded:
Earnings and cash flow are considered far moreimportant than book value and dividends.
What are security analysts currently proj ecting
in the way of earnings growth for the firms in the
electric utility proxy group?
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The consensus earnings growth proj ections for
each of the firms in the reference group of electric
utilities reported by IBES and published in S&P' s
Earnings Guide are shown on Exhibit No.Also
presented are the earnings growth proj ections reported by
Value Line, First Call Corporation ("First Call"), and
Mul tex Investor ("Mul tex ), which is a service of
As shown there, wi th the except ion of ValueReuters.
Line I S estimates, these security analysts I proj ections
suggested growth the order of 5.0 to 5.5 percent for the
reference group of electric utilities:
Electric Utility Proxy Group
Service Growth Rate
IBES
Val LineFirstCall
Mul tex
What other earnings growth rates might
relevant in assessing investors ' current expectations for
electric utilities?
Short -term proj ected growth rates may be
colored by current uncertainties regarding the near-term
direction of the economy in general and the spate of
challenges faced in the electric power industry
specifically.Consider the example of Value Line, which
recently noted that the electric utility industry " is
still
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in a state of flux"39 and that:
this industry still faces problems. The
after-effects of the turbulence in the power
markets still exist , some companies are
stressed financially, and even for traditionalutili ties, regulatory risk is often a potential
problem.
Value Line also reduced its Timeliness ranking, a
relative measure of year-ahead stock price performance
for the 98 industries it covers, for the electric utility
industry from 70 to 89.While this cautious outlook may
explain the fact that Value Line's near-term growth
estimates are out of line with other analysts'
proj ections, it is not necessarily indicative of
investors' long-term expectations for the industry.
Given the unsettled conditions in the economy and
electric utility industry over the near-term, historical
growth in earnings might also provide a meaningful guide
to investors' future expectations.Accordingly, earnings
growth rates for the past 10- and 5-year periods reported
by Value Line for the firms in the electric utility group
are also presented on Exhibit No.As shown there,
10-year historical earnings growth rates for the group of
eight electric utili ties averaged 7.3 percent, or 8.
percent over the most recent 5 year period.
How else are investors' expectations of future
long-term growth prospects often estimated for use in the
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constant growth DCF model?
In constant growth theory, growth in book
equity will be equal to the product of the earnings
retention ratio (one minus the dividend payout ratio) and
the earned rate of return on book equity.Furthermore,
if the earned rate of return and payout ratio are
constant over time, growth in earnings and dividends will
be equal to growth in book value.Al though these
conditions are seldom, if ever , met in practice, this
approach may provide investors with a rough guide for
evaluating a firm's growth prospects.Accordingly,
conventional applications of the constant growth DCF
model often examine the relationships between retained
earnings and earned rates of return as an indication of
the growth investors might expect from the reinvestment
of earnings wi thin a firm.
What growth rate does the earnings retention
method suggest for the reference group of electric
utilities?
The sustainable,"b x r " growth rates for each
firm in the reference group is shown on Exhibit No.
For each firm , the expected retention ratio (b) was
calculated based on Value Line's proj ected dividends and
earnings per share.Likewise , each firm's expected
earned rate of return (r) was computed by dividing
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proj ected earnings per share by proj ected net book value.
As shown there, this
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method resulted in an average expected growth rate for
the group of electric utilities of 4.7 percent.
What did you conclude with respect to
investors I growth expectations for the reference group of
electric utilities?
I concluded that investors currently expect
growth on the order of 5. 0 to 7. 0 percent for the average
firm in the electric utility proxy group.This
determination was based on the growth proj ections
discussed above , but giving little weight to Value Line'
proj ections , which deviated significantly from the more
broadly-based consensus growth rate proj ections reported
by IBES , First Call, and Multex , as well as past
experience.
What cost of equity was implied for the
reference group of electric utilities using the DCF
model?
Combining the 4.4 percent average dividend
yield with the 6.0 percent midpoint of my representative
growth rate range implied a DCF cost of equity for this
group of electric utilities of 10.4 percent.
C. Risk Premium Analyses
What other analyses did you conduct to estimate
the cost of equity?
As I have mentioned previously, because the
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cost of equity is inherently unobservable, no single
method should be considered a solely reliable guide to
investors'
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required rate of return.Accordingly, I also evaluated
the cost of equity for Idaho Power using risk premium
methods.My applications of the risk premium method
provide alternative approaches to measure equity risk
premiums that focused specifically on data for electric
utilities and forward-looking estimates of investors'
required rates of return.
Briefly describe the risk premium method.
The risk premium method of estimating
investors' required rate of return extends to common
stocks the risk-return tradeoff observed with bonds.The
cost of equity is estimated by first determining the
additional return investors require to forgo the relative
safety of bonds and to bear the greater risks associated
with common stock , and then adding this equity risk
premi um to the current yield on bonds.Like the DCF
model, the risk premium method is capital market
oriented.However , unlike DCF models, which indirectly
impute the cost of equity, risk premium methods directly
estimate investors' required rate of return by adding an
equity risk premium to observable bond yields.
How did you implement the risk premium method?
The actual measurement of equity risk premiums
is complicated by the inherently unobservable nature of
the cost of equity.equity In other words, 1 ike the cost of
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itself and the growth component of the DCF model, equity
risk premiums cannot be calculated precisely.Therefore
equity risk premiums must be estimated, with adjustments
being required to reflect present capital market
conditions and the relative risks of the groups being
evaluated.
I based my estimates of equity risk premiums for
electric utilities on (1) surveys of previously
authori zed rates of return on common equity for electric
utilities (2) realized rates of return on electric
utility common stocks; and (3) forward-looking
applications of the Capital Asset Pricing Model ("CAPM"
Authorized returns presumably reflect regulatory
commissions' best estimates of the cost of equity,
however determined , at the time they issued their final
order , and the returns provide a logical basis for
estimating equity risk premiums.Under the
realized-rate-of-return approach, equity risk premiums
are calculated by measuring the rate of return (including
di vidends, interest , and capital gains and losses)
actually realized on an investment in common stocks and
bonds over historical periods.The realized rate of
return on bonds is then subtracted from the return earned
on electric utility common stocks to measure equity risk
premiums.The CAPM approach measures the market-expected
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return for a sec~rity as the sum of a risk-free rate and
a risk premium based on the portion of a security I s risk
that cannot be
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eliminated by holding a well-diversified portfolio.
Under the CAPM , risk is represented by the beta
coefficient (g), which measures the volatility of a
securi ty ' s price relative to the market at a whole.Even
before the widely cited study by Eugene F. Fama and
Kenneth R. French 41 considerable controversy surrounded
the validity of beta as a relevant measure of a utility
investment risk.Nevertheless , the CAPM is routinely
referenced in the financial literature and in regulatory
proceedings.
While these methods are premised on different
assumptions, each having their own strengths and
weaknesses, they are widely accepted approaches that have
been routinely referenced in estimating the cost of
equity for regulated utilities.
How did you implement the risk premium approach
using surveys of allowed rates of return?
While the purest form of the survey approach
would involve querying investors directly, surveys of
previously authorized rates of return on common equity
are frequently referenced as the basis for estimating
equity risk premiums.The rates of return on common
equity authorized electric utilities by regulatory
commissions across the U. S. are compiled by Regulatory
Research Associates ("RRA") and published in its
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Regulatory Focus report.In Exhibi t No.8, the average
yield on public
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utility bonds is subtracted from the average allowed rate
of return on common equity for electric utilities to
calculate equity risk premiums for each year between 1974
and 2002.Over this 29-year period , these equity risk
premiums for electric utilities averaged 3.08 percent,
and the yield on public utility bonds averaged 9.
percent.
Is there any risk premium behavior that needs
to be considered when implementing the risk premium
method?
There is considerable evidence that theYes.
magnitude of equity risk premiums is not constant and
that equity risk premiums tend to move inversely with
interest rates.In other words , when interest rate
levels are relatively high, equity risk premiums narrow
and when interest rates are relatively low , equity risk
premiums widen.To illustrate, the graph below plots the
yields on public utility bonds (shaded bars) and equity
risk premiums (solid bars) shown on Exhibit No.
15%
_---,--,-,----'--
10%f--
,---,,---,
II I I ~ I III
"Ot "Ot "Ot00 ' 00
rll'Bond Yield . Equity Ris~_Premium I
1022 AVERA, DI
Idaho Power Company
The graph clearly illustrates that the higher the level
of interest rates, the lower the equity risk premium , and
vice versa.The implication of this inverse relationship
is that the cost of equity does not move as much as, or
in lockstep with , interest rates.Accordingly, for a
percent increase or decrease in interest rates, the cost
of equity may only rise or fall , say, 50 basis points.
Therefore, when implementing the risk premium method,
adjustments may be required to incorporate this inverse
relationship if current interest rate levels have changed
since the equity risk premiums were estimated.
What cost of equity is implied by surveys of
allowed rates of return on equity?
As illustrated above, the inverse relationship
between interest rates and equity risk premiums is
evident.Based on the regression output between the
interest rates and equity risk premiums displayed at the
bottom of Exhibit No.8, the equity risk premium for
electric utilities increased approximately 43 basis
points for each percentage point drop in the yield on
average public utility bonds.As shown there, wi th the
yield on public utility bonds in August 2003 being 302
basis points lower than the average for the study period,
this implied a current equity risk premium of 4.
percent for electric utilities. Adding this equity risk
premium to the August 2003 yield on
1023 AVERA , DI
Idaho Power Company
single-A public utility bonds of 6.79 percent implies a
current cost of equity for Idaho Power of approximately
11.2 percent.
How did you apply the realized-rate-of-return
approach?
Widely used in academia, the
realized-rate-of-return approach is based on the
assumption that , given a sufficiently large number of
observations over long historical periods, average
realized market rates of return will converge to
investors' required rates of return.From a more
practical perspective, investors may base their
expectations for the future on , or may have come to
expect that they will earn , rates of return corresponding
to those real i zed in the past. By focusing on data for
electric utilities specifically, my realized rate of
return approach avoided the need to make assumptions
regarding relative risk (e. g., beta) that are often
embodied in applications of this method.
Stock price and dividend data for the electric
utilities included in the S&P 500 Composite Index ("S&P
500") are available since 1946.Exhibi t No.9 presents
annual realized rates of return for these electric
utilities in each year between 1946 and 2002.As shown
there, over this 57-year period realized rates of return
1024 AVERA, DI
Idaho Power Company
for these utilities have exceeded those on single-
public
1025 AVERA , DI 61a
Idaho Power Company
utility bonds by an average of 4.01 percent.The
realized-rate-of-return method ignores the inverse
relationship between equity risk premiums and interest
rates and assumes that equity risk premiums are
stationary over time; therefore, no adjustment for
differences between historical and current interest rate
levels was made.Adding this 4. 01-percent equity risk
premium to the August 2003 yield of 6.79 percent on
single-A public utility bonds suggests a current cost of
equity for Idaho Power of approximately 10.8 percent.
Please describe your application of the CAPM.
The CAPM is a theory of market equilibrium that
measures risk using the beta coefficient.Under the
CAPM , investors are assumed to be fully diversified, so
the relevant risk of an individual asset (e.g., common
stock) is its volatility relative to the market as a
whole.Beta reflects the tendency of a stocks price to
follow changes in the market.A stock that tends to
respond less to market movements has a beta less than
00, while stocks that tend to move more than the market
have betas greater than 1.00.The CAPM is mathematically
expressed as:
j = Rf + iSj (Rm - Rf
j = required rate of return forstock j;Rf = risk- free rate;
Rm = expected return on the marketportfolio; and,
Where:
1026 AVERA, DI
Idaho Power Company
j = beta , or systematic risk, forstock j.
Exhibi t No. 10 presents an application of the CAPM
to the eleven companies in the electric utility proxy
group based on a forward-looking estimate for investors'
required rates of return from common stocks.Rather than
using historical data, the expected market rate of return
was estimated by conducting a DCF analysis on the firms
in the S&P 500.The dividend yield was obtained from
S&P, with the growth rate equal to the average of the
composite earnings growth proj ections published by IBES
for each firm.As shown there , subtracting a 5.
percent risk-free rate based on the August 2003 average
yield on 20 -year government bonds from the 14.24 percent
forward-looking rate of return produced a market equity
risk premium of 8.85 percent.Multiplying this risk
premium by the average Value Line beta of 0.71 for the
firms in the electric utility group, and then adding the
resulting risk premium to the long-term Treasury bond
yield , resulted in a current cost of equity of
approximately 11.7 percent.
D. Proxy Group Return on Equity
What did you conclude with respect to the cost
of equity for the benchmark group of electric utilities?
Consistent with the results of my quantitative
1027 AVERA , DI
Idaho Power Company
analyses, I concluded that the cost of equity for the
proxy
1028 AVERA, DI 63a
Idaho Power Company
group is presently in the 10.4 to 11.7 percent range.
What other considerations are relevant in
setting the return on equity for a utility?
The common equity used to finance the
investment in utility assets is provided from either the
sale of stock in the capital markets or from retained
earnings not paid out as dividends.When equity is
raised through the sale of common stock , there are costs
associated with floating" the new equity securities.
These flotation costs include services such as legal
accounting, and printing, as well as the fees and
discounts paid to compensate brokers for selling the
stock to the public.Also, some argue that the "market
pressure" from the additional supply of common stock and
other market factors may further reduce the amount of
funds a utility nets when it issues common equity.
Is there an established mechanism for a utility
to recognize equity issuance costs?
No.While debt flotation costs are recorded on
the books of the utility, amortized over the life of the
issue , and thus increase the effective cost of debt
capital, there is no similar accounting treatment to
ensure that equity flotation costs are recorded and
ul timately recogni zed.Alternatively, no rate of return
is authorized on flotation costs necessarily incurred to
1029 AVERA, DI
Idaho Power Company
obtain a portion of the equity capital used to finance
plant.In other words, equity flotation costs are not
included in a utility s rate base because neither that
portion of the gross proceeds from the sale of common
stock used to pay flotation costs is available to invest
in plant and equipment, nor are flotation costs
capitalized as an intangible asset.Unless some
provision is made to recognize these issuance costs, a
utility's revenue requirements will not fully reflect all
of the costs incurred for the use of investors' funds.
Because there is no accounting convention to accumulate
the flotation costs associated with equity issues, they
must be accounted for indirectly, with an upward
adj ustment to the cost of equity being the most logical
mechanism.
What is the magnitude of the adjustment to the
"bare bones" cost of equity to account for issuance
costs?
There are any number of ways in which a
flotation cost adjustment can be calculated , and the
adjustment can range from just a few basis points to more
than a full percent.One of the most common methods used
to account for flotation costs in regulatory proceedings
is to apply an average flotation-cost percentage to a
utility's dividend yield.Based on a review of the
1030 AVERA, DI
Idaho Power Company
finance literature, Roger A. Morin concluded:
The flotation cost allowance requires an
1031 AVERA , DI 65a
Idaho Power Company
estimated adjustment to the return on equity of
approximately 5% to 10%, depending on the size and riskof the issue.
Applying these expense percentages to a representative
dividend yield for an electric utility of 4.4 percent
implies a flotation cost adjustment on the order of 20 to
40 basis points.
What then is your conclusion regarding a fair
rate of return on equity for the companies in your
benchmark group?
After incorporating a minimum adjustment for
flotation costs of 20 basis points to my "bare bones
cost of equity range, I concluded that a fair rate of
return on equity for the proxy group of electric
utilities is currently in the 10.6 to 11.9 percent range.
IV. RETURN ON EQUITY FOR IDAHO POWER COMPANY
What is the purpose of this section?
This section addresses the economic
requirements for Idaho Power's return on equity.
examines other factors properly considered in determining
a fair rate of return , such as market perceptions of
Idaho Power's relative investment risks and comparable
earnings for utilities and industrial firms.This
section also discusses the relationship between ROE and
preservation of a utility s financial integrity and the
ability to attract
1032 AVERA , DI
Idaho Power Company
capi tal.
A. Capital Structure
Is an evaluation of the capital structure
maintained by a utility relevant in assessing its return
on equity?
Yes.Other things equal, a higher debt ratio,
or lower common equity ratio , translates into increased
financial risk for all investors.A greater amount of
debt means more investors have a senior claim on
available cash flow , thereby reducing the certainty that
each will receive his contractual paYments.This
increases the risks to which lenders are exposed, and
they require correspondingly higher rates of interest.
From common shareholders' standpoint, a higher debt ratio
means that there are proportionately more investors ahead
of them, thereby increasing the uncertainty as to the
amount of cash flow , if any, that will remain.
What common equity ratio is implicit in Idaho
Power's requested capital structure?
Idaho Power's capital structure is presented in
the testimony of Dennis C. Gribble.As summarized in his
testimony, the common equity ratio used to compute Idaho
Power's overall rate of return was approximately 44.
percent.
How does Idaho Power's common equity ratio
1033 AVERA , DI
Idaho Power Company
compare with those maintained by the reference group of
utilities?
For the eight firms in the Electric Utility
(West) group, common equity ratios at year-end 2002
ranged from 37.4 percent to 60.6 percent and averaged
45.8 percent.
How does Idaho Power's capital structure
compare with other widely cited financial benchmarks for
electric utilities?
The financial ratio guidelines published by S&P
specify a range for a utility s total debt ratio that
corresponds to each specific bond rating.Widely cited
in the investment community, these ratios are viewed in
conj unction with a utility'business profile ranking,
which ranges from 1 (strong) to 10 (weak) depending on a
utility's relative business risks.Thus, S&P' s guideline
financial ratios for a given rating category (e.
g.,
triple-B) vary with the business or operating risk of the
utili ty.In other words , a firm with a business profile
of "2" (i. e., relatively lower business risk) could
presumably employ more financial leverage than a utility
with a business profile assessment of "9" while
maintaining the same credit rating.
Consistent with S&P' s current guidelines and Idaho
Power s S&P business profile ranking of ", a utility
1034 AVERA, DI
Idaho Power Company
would be required to maintain a ratio of total debt to
total capital of 46.0 percent to qualify for a single-
bond rating. This benchmark equates to total equity
ratio of 54.0 percent.
What implication does the increasing risk of
the electric power industry have for the capital
structures maintained by utilities like Idaho Power?
The challenges imposed by evolving structural
changes in the industry imply that utilities will be
required to incorporate relatively greater amounts of
equity in their capital structures.Moody s noted early
on that utili ties must adopt a more conservative
financial posture if credit ratings are to be maintained:
'The key issue," says the analysts in a recent
special comment, "is that the competi ti ve
industries have much lower operating and
financial leverage and that utilities must
streamline both in order to be effectivecompetitors.Analysts say the utilities must
do this in order to post stronger financial
indicators and maintain their current ratingslevel.
More recently, Value Line reported that the average
common equity ratio for all firms in the electric utility
industry is expected to increase from 43 percent in 2003
to 50 percent over the next three to five years.
Indeed, continued pressure on credit quality in the
electric industry is indicative of the need for utili ties
1035 AVERA , DI
Idaho Power Company
strengthen financial profiles to deal with an
increasingly uncertain market.S&P cited the inadequacy
of current balance sheets in the electric industry as one
of the key factors explaining this deterioration:
The downward slope in the power industry
credi t picture can be traced to higher debt
leverage and overall deterioration in financialprofiles, constrained access to capital markets
as a result of investor skepticism over
accounting practices and disclosure, liquidity
problems, financial insolvency, and investments
outside the traditional regulated utility
business, principally merchant generation
facilities and related energy marketing andtrading activities.
A more conservative financial profile is consistent with
the increasing uncertainties associated with
restructuring in wholesale power markets and the
imperative of maintaining continuous access to capital
even during times of adverse capital market and industry
conditions.
What other indications confirm the
reasonableness of Idaho Power's capital structure
policies?
In the wake of Enron' s collapse, bond rating
agencies and investors are closely scrutinizing debt
levels.For those firms with higher leverage, this
intense focus has led not only to ratings downgrades, but
to reduced access to capital and increased borrowing
The Wall Street Journal reported that even firmscosts.
1036 AVERA, DI
Idaho Power Company
with stock prices at recent lows have been forced to
issue new common equity and quoted a credit analyst with
Fitch, Inc.
1037 AVERA, DI 70a
Idaho Power Company
" (B) anks are fearful to put more money into thesector" and it is making credit analysts
nervous as well. The smart companies, he says,
are the ones that voluntarily "get their
balance sheets in line" and the "let the marketknow they're in charge of their destiny...sincethe market clearly has the heebie-jeebies. "48
The article went on to note the crucial role that
financial flexibility plays in ensuring that the utility
has the wherewi thaI to meet the needs of customers:
All the belt tightening spells bad news for the
continued development of the nation's energyinfrastructure. Companies that can borrow more
money and stretch their dollars, quite simply,can build more plants and equipment. Companies
that are increasingly dependent on equity
financing - particularly in a bear market - cando less.
What did you conclude with respect to Idaho
Power's requested capitalization?
Idaho Power s proposed capital structure is
in-line with the ranges maintained by the comparable
group of electric utilities, although its equity ratio
falls somewhat below the guideline specified by S&P for a
single-A rated utility.The reasonableness of Idaho
Power's requested capital structure is reinforced by the
ongoing uncertainties associated with the electric power
industry, the need to support system expansion, and the
imperative of maintaining continuous access to capital
even during times of adverse industry and market
conditions.
1038 AVERA, DI
Idaho Power Company
B. Other Factors
How does Idaho Power's credit rating compare to
those of the reference groups?
Corporate credit ratings for the eight firms in
the Electric Utility (West) group used to estimate the
cost of equity range from "BBB-" to "As noted
earlier , Idaho Power's senior debt is also currently
rated "A-, comparable to the firms in the benchmark
group.
What else should be considered in evaluating
the relative risks of Idaho Power?
Because approximately one-half of Idaho Power'
total energy requirements are provided by hydroelectric
facilities, the Company is exposed to a level of
uncertainty not faced by other utili ties, which are less
dependent on hydro generation.While hydropower confers
advantages in terms of fuel cost savings and di versi ty,
investors also associated hydro facilities with risks
that are not encountered with other sources of
generation.Reduced hydroelectric generation due to
below-average water conditions forces Idaho Power to rely
on less efficient thermal generating capacity and
purchased power to meet its resource needs.As noted
earlier, in the minds of investors , this dependence on
wholesale markets entails significant risk , especially
1039 AVERA, DI
Idaho Power Company
for a utility located in the west.Indeed, the ongoing
risks associated with
1040 AVERA , DI 72a
Idaho Power Company
uncertainty in western power markets has been recognized
by the Commission.In declining to spread recovery of
power cost deferrals over multiple years, the Commission
recognized that:
...
the Commission is very concerned about the
unknown water and market conditions that lieahead. ...A one-year recovery will take care of
nearly all the deferred costs remaining from a
sustained period of extraordinarily high
wholesale prices at the same time that
hydro-dependent Idaho Power customers were
experiencing the second worst drought in years. ...However, as we have learned over the
past two years , there are no guarantees aboutfuture stream flows or market prices.
Apart from exposure to market uncertainties , Idaho Power
also confronts the complexities associated with obtaining
the necessary licenses to operate its hydroelectric
stations.The process of relicensing is prolonged and
involved and often includes the implementation of various
measures to address environmental and stakeholder
concerns.These measures can impose significant
additional costs and/or lead to reduced generating
capacity and flexibility.Moody s recently noted that
"(Idaho Power'sJ rating outlook is negative as the
utility continues to cope with difficult power supply
markets in its region "51 and concluded the Company s bond
ratings could be reduced based on the following factors:
Continued delay in return to more normal hydro
1041 AVERA, DI
Idaho Power Company
and weather conditions in combination with
unexpected harsh treatment from Idaho
regulators in the upcoming general rateproceedings. Significant increases in
relicensing costs and/or stringent operational
constraints impose as part of the licenserenewal process.
Similarly, S&P recently observed that:
Utilities in the Pacific Northwest continue toface a host of challenges. If the western
power crisis left a large number of them
investor-owned as well as publicly-owned , indire financial straits , weak economic
conditions and the uncertain hydro situation
have hampered recovery prospects.
S&P went on to note the significant potential costs and
risks imposed by uncertainty over fish-conservation
measures that might be requ~red to meet federal law and
continued volatility in wholesale power markets,
concluding that "managing hydro risk has assumed a
critical importance to credit quality. "54
What other factors would investors likely
consider in evaluating their required rate of return for
Idaho Power?
Investors have clearly recognized that
structural change and market evolution in the electric
power industry have led to a significant increase in the
risks faced by industry participants. For a firm caught
between expanding wholesale competition in the industry
and the constraints of regulation , as are electric
utilities , these risks are further magnified.recognized:As S&P
1042 AVERA, DI
Idaho Power Company
Al though the move to competition from
regulation is obviously negative for credit
quality in general , the transition period can
often be worse for bondholders than would be a
fully competi ti ve industry. In the interimcompanies can be saddled with .many of the
disadvantages of being regulated (e.
g.,
limits
on return on capital and higher costs to comply
wi th regulatory mandates) while simultaneouslybeing gradually exposed to marketplace risks.
Similarly, the Wall Street Journal recently highlighted
the risks that investors associate with the interface
between competition and regulation in the power industry:
Now , with the power industry hovering uneasily
between regulation and deregulation, it faces
the prospect of a market that combines the
worst features of both: a return to governmentrestrictions, mixed with volatility and price
spikes as companies struggle to meet thenation's energy needs.
Moreover, investors recognize that regulation has
its own risks.In some circumstances regulatory
uncertainty can eclipse all of the other risk factors
facing particular utilities.Considering the magnitude
of the events that have transpired since the third
quarter of 2000, investors ' sensitivity to market and
regulatory uncertainties has increased dramatically.The
sharpened focus on the risks associated with
unrecoverable wholesale power costs , for example, was
noted by RRA:
The potential for volatility in wholesale power
electricity markets, as highlighted by the
temporary price spikes experienced in the
Midwest in June 1999 and, more recently, by the
1043 AVERA , DI
Idaho Power Company
ongoing severe capacity shortage/pricing crisis
in California , has raised investors' level of
awareness and concern with regard to the
ability of electric utilities to recover
increased wholesale power costs and fuel
expenses from customers.
Investors' required rates of return for utilities are
premised on the regulatory compact that allows the
utility an opportunity to recover reasonable and
necessary costs. By sheltering utilities from exposure to
extraordinary power cost volatility, ratepayers benefit
from lower capital costs than they would otherwise bear.
Of course , the corollary implies that , if investors
believe that the utility might face continued exposure to
potentially extreme fluctuations in power supply costs
while remaining obligated to provide service at regulated
rates, their required return would be considerably
increased.As S&P noted , the August 14th blackout is
unlikely to ease investors' concerns:
Clearly, the blackout has
complexi ty of the system
many stakeholders and the
industry to political and
highl ighted thethe diversity of its
susceptibility of theregulatory risk.
C. Implications for Financial Integrity
Why is it important to allow Idaho Power an
adequate rate of return on equity?
Given the social and economic importance of the
electric utility industry, it is essential to maintain
1044 AVERA , DI
Idaho Power Company
reliable and economical service to all consumers.While
Idaho Power remains committed to deliver reliable
electric service at the lowest possible price, a
utility s ability to fulfill its mandate can be
compromised if it lacks the necessary financial
wherewi thaI.
What lessons can be learned from recent events
in the energy industry?
Events in the western U. s. provide a dramatic
illustration of the high costs that all stakeholders must
bear when a utility's financial integrity is compromised.
California's failed market structure led to unprecedented
volatility in the region's wholesale power costs.For
many utilities, recovery of purchased energy costs that
they were forced to buy to serve their customers was
ei ther prevented and/or postponed.As a resul t, they
were denied the opportunity to earn risk-equivalent rates
of return and access to capital was cut off.Regional
economies have been jolted and consumers have suffered
the results of higher cost power and reduced reliability.
Moreover, while the impact of the utilities'
deteriorating financial condition was felt swiftly,
stakeholders have discovered first hand how difficult and
complex it can be to remedy the situation after the fact.
Do you have any personal experience regarding
1045 AVERA , DI
Idaho Power Company
the damage to customers that can result when a utility
financial integrity deteriorates?
Yes.I was a staff member of the PUCT when the
financial condition of El Paso Electric Company ("EPE"
began to suffer in the late 1970s.I later observed
first-hand the difficulties in reversing this slide as a
consul tant to Asarco Mining, EPE' s largest single
EPE's ultimate bankruptcy imposed enormouscustomer.
costs on customers and absorbed an undue amount of the
PUCT' s resources, as well as those of the Attorneys
General and other state agencies.Now I am serving as a
consultant to the utility as it continues its struggle to
fully recover its financial health.There is no question
that customers and other stakeholders would have been far
better off had EPE avoided bankruptcy by maintaining its
financial resilience.
What danger does an inadequate rate of return
pose to Idaho Power?
1046 AVERA, DI
Idaho Power Company
While Idaho Power has been successful in
maintaining its financial flexibility, it is important to
remember that, once lost , investor confidence is
difficult to recover and the damage is not easily
reversible.Consider the example of bond ratings.
restore a company's rating to a previous, higher level
rating agencies generally require the company to maintain
its financial indicators above the minimum levels
required for the higher rating over a period of time.
Considering investors' sharp focus on the risks
associated with the west and the uncertainties imposed by
the Company's relative reliance on hydroelectric
generation, the perception of a lack of regulatory
support would almost certainly lead to a decline in Idaho
Power s credit quality and financial flexibility.
At the same time , Idaho Power plans to add
significant plant investment, such as the Mountain Home
generating facility, to ensure that the energy needs of
its service territory are met.While providing the
infrastructure necessary to support economic growth is
certainly desirable, it imposes significant
responsibili ties on Idaho Power.To meet these
challenges successfully and economically, it is crucial
that the Company receive adequate support for its credit
standing.Finally, maintaining Idaho Power's access to
1047 AVERA, DI
Idaho Power Company
capital on reasonable terms has the added benefit of
preserving the Company's independence and ability to
maintain quality service based on the interests of Idaho
ratepayers.
D. Conclusions
What is your conclusion regarding a fair rate
of return on equity range for Idaho Power?
Based on the capi tal market research presented
earlier and the economic requirements discussed above, it
is my conclusion that a return on equity in the range of
10.6 to 11.9 percent represents a conservative estimate
of investors' required rate of return for Idaho Power in
today s capital markets.
In evaluating the rate of return for Idaho Power, it
is important to consider investors' continued focus on
the unsettled conditions in western power markets.These
uncertainties are compounded by the Company s continued
reliance on hydroelectric power for a relatively greater
portion of its energy supply, as well as other risks
associated with the power industry, such as heightened
exposure to regulatory uncertainties.
How does your recommended fair rate of return
on equity range for Idaho Power compare with other
benchmarks that investors would consider?
Reference to rates of return available from
1048 AVERA, DI
Idaho Power Company
al ternati ve investments can also provide a useful
guidel ine
1049 AVERA, DI 80a
Idaho Power Company
in assessing the return necessary to assure confidence in
the financial integrity of a firm and its ability to
attract capital.This comparable earnings approach
avoids the complexities and limitations of capital market
methods and instead focuses on the returns earned on book
equity, which are readily available to investors.
Indeed, the most recent edition of Value Line
reports that its analysts expect average rates of return
on common equity for the electric utility industry of
11.3 percent and 11.8 percent for 2003 and 2004
respectively, with their three to five year projections
anticipating a return on equity of 12.0 percent.
Similarly, expected rates of return for gas distribution
utilities are expected to average 11.5 percent over Value
Line's forecast horizon , 60 while the 696 industrial
retail , and transportation companies included in Value
Line's Composite Index are expected to earn 16.0 percent
on book equity during the 2006-2008 time frame.
Accordingly, these expected earned rates of return
confirm the reasonableness of my recommended rate of
return on equity range for Idaho Power.
My recommended ROE range is further supported by the
fact that investors are likely to anticipate increases in
utility bond yields going forward.Moreover , an ROE in
the 10.6 percent to 11.9 percent range is reasonable at
1050 AVERA , DI
Idaho Power Company
this critical juncture , given the importance of
supporting the financial capability of Idaho Power as it
invests the capital that is needed to develop and enhance
utili ty infrastructure.As the recent power failures
amply demonstrated , the cost of providing Idaho Power an
adequate return is small relative to the potential
benefits that a strong utility can have in providing
reliable service and fostering growth.Considering
investors' heightened awareness of the risks associated
with the electric power industry and the damage that
results when a utility's financial flexibility is
compromised , supportive regulation is perhaps more
crucial now than at any time in the past.
Does this conclude your direct testimony in
this case?
Yes , it does.
1051 AVERA , DI
Idaho Power Company
ENDNOTES
1 IDACORP , Inc., "IDACORP Reduces Dividend To Strengthen
Balance Sheet News Scans (Sep. 18 , 2003).
2 Standard & Poor's Corporation, "IDACORP and Unit Ratings
Affirmed; Outlook Revised to Stable
RatingsDirect (Oct. 3,2003).
Regional Transmission Organizations Order No. 2000 (Dec.20, 1999), 89 FERC ~ 61 , 285 .
4 Remedying Undue Discrimination through Open Access
Transmission Service and Standard Electricity Market
Design , Notice of Proposed Rulemaking, IV FERC Stats. &Regs. ~ 32 563 (2002) ("SMD NOPR"); FERC White PaperWholesale Power Market Platform , April 28 , 2003 , availableat http: / /www. ferc. 9ov/Electric/RTO/Mrkt-Strct-comments/White paper.pdf.
Remarks by William L. Massey, Center for Public UtilitiesAdvisory Council, "The Santa Fe Conference" (March 1 7 , 2003)
6 Standard & Poor's Corporation , 2002 Power Energy Credi
Conference: Beyond the Crisis (Jun. 12 , 2002).
7 Standard & Poor's Corporation
, "
U. S. Power IndustryExperiences Precipitous Credit Decline in 2002; NegativeSlope Likely to Continue"RatingsDirect (Jan. 15 , 2003).
Id.
9 Standard & Poor's Corporation
, "
Credit Quality For U. S.Utilities Continues Negative Trend
RatingsDirect (Jul., 2003)
10 Moody's Investors Service Moody's Credi Perspecti ves(Jul. 14 , 2003) at 33-34.
11 Standard & Poor's Corporation
, "
Credit Quality For U. S.Utilities Continues Negative Trend
RatingsDirect (Jul. 242003)
12 I daho Power Company, Form 10 - K Report (2001).
13 Standard Poor's Corporation Public Power Companies inNorthwest Increase Rates Due to Low Water , SkyrocketingPrices", Infrastructure Finance , p. 1 (January 18 , 2001)
1052 AVERA , DI
Idaho Power Company
14 The Value Line Investment Survey, p. 1758 (November 172000)
15 Statement of Pat Wood, III , Chairman , Federal EnergyRegulatory Commission , On the Power Failure in the U.S. andCanadaPress Release (Aug. 15, 2003)
16 See, g., Remedying Undue Discrimination through OpenAccess Transmission Service and Standard Electrici
ty MarketDesign67 Fed. Reg. 55 451 , FERC Stats. & Regs. ~ 32,563(2002)
( "
SMD NOPR") and FERC White Paper Whol esal PowerMarket Platform April 28, 2003, available http: / /www. ferc. gov/Electric/RTO/Mrkt-Strct-comments/White paper .pdf.
17 Standard & Poor's Corporation
, "
Electric Transmission atthe Starting Gate"RatingsDirect (May 10 , 2002).
18 Massey, William L., "Restoring Confidence in EnergyMarkets", Remarks at the 9 Annual Spring Conference for
the New England Energy Industry (May 21 , 2002).
19 U.S. Department of Energy, National Transmission Grid
Study (May 2002), at 24 and 31.
20 Id. at 31.
21 Draft Remarks of Kara M. Silva , Vice President, MBIAInsurance Corporation NARUC Joint Committee on
Electricity, Gas , and Finance and Technology (Feb. 26,2003)
22 Consumer Energy Council of America
, "
Positioning theConsumer for the Future: A Roadmap to an Optimal Electric
Power System" (Apr. 2003) at XVII.
23 Smith , Rebecca, Overloaded Circuits Blackout SignalsMajor Weakness in U. S. Power Grid " The Wall Street Journal(Aug. 18 , 2003)
24 Statement of Pat Wood , III, Chairman , Federal EnergyRegulatory Commission , On the Power Failure in the U. S. andCanadaPress Release (Aug. 15, 2003)
25 Standard & Poor's Corporation, "Electric UtilityBlackouts Put Spotlight on Political and Regulatory Credit
Risk"RatingsDirect (Aug. 21 , 2003)
26 Id.
1053 AVERA , DI
Idaho Power Company
27 Standard & Poor's Corporation Corporate Ratings Cri teriaat 29 , available at www. standardandpoors. com/ratings.
28 Energy Information Administration Annual Energy Outlook2003, at Table 20, Nov. 20 , 2002 , available athttp: / /www.eia.doe.gov/oiaf/aeo/pdf/aeo base.Pdf.
29 Global Insight The U.S. Economy, The 25-Year Focus(Winter 2003) at Table 33.
30 Federal Communications Commission , Report and Order 42-43, CC Docket No. 92-133 (1995)
31 The financial stress and lack of stability thataccompanies below investment grade bond ratings greatly
complicates any determination of investors' long-term
expectations that form the basis for DCF applications to
estimate the cost of equity.
32 Idaho Commissioner Meets wi th ELCON, ELCON Report (No.2003) at
33 Williston Basin Interstate Pipeline Co.104 FERC ~61,036, at 14-15 (Jul. 3 , 2003).
34 See , e. The Value Line Investment Survey (Sep. 151995 at 161 , Sep. 5 , 2003 at 154)
35 Association for Investment Management and Research
Finding Reality in Reported Earnings: An Overview , p. 1(Dec. 4 , 1996).
36 The Value Line Investment
Survey, Subscriber s Guide53.
37 Block, Stanley B.
, "
A Study of Financial Analysts:
Practice and Theory Financial Analysts Journal
(July/August 1999).
38 Id. at 88.
39 The Value Line Investment Survey (July 4 , 2003) at 695.
40 The Value Line Investment Survey (Aug. 15, 2003) at 1776.
41 Fama , Eugene F. and French , Kenneth R., "The Cross-Section of Expected Stock Returns The Journal of Finance(June 1992)
1054 AVERA , DI I daho Power Company
42 Indeed , average realized rates of return for historical
periods are widely reported to investors in the financialpress and by investment advisory services as a guide to
future performance.
43 Roger A. Morin, Regula tory Finance: Utili ties' Cost Capital 1994 , at 166.
44 Standard & Poor
s, Corporate Ratings Criteria at 58,available at www. standaredandpoors. com/ratings.
45 Moody s Investors Service Credit Risk Commentary, p. 3(July 29 , 1996).
46 The Value Line Investment Survey, p. 1776 (Aug. 152003)
47 Standard & Poor's Corporation Credi Quali ty For U. S.Utilities Continues Negative Trend RatingsDirect, Jul. 242003.
48 Smith, Rebecca, URating Agencies Crack Down onUtilities, The Wall Street Journal, p. Cl (December 19,2001)
49 Id.
50 Idaho Power granted $256 million deferral , but bond plandeniedIdaho Public Utilities Commission (May 13, 2002)
51 Moody s Investors Service, Opinion Update: Idaho PowerCompany (Jun. 20 , 2003).
52 Id.
53 Standard & Poor s Corporation , ULegal Developments Add toUtilities' Disquiet in U.S. Northwest,Utilities
Perspectives (July 21 , 2003) at 2-
54 Id.
55 Standard & Poor s, CreditWeek , Nov. 1, 2000, at 31.
56 Rebecca Smith Shock Waves The Wall Street Journal , Nov.30, 2001 , at AI.
57 Regulatory Research Associates , u Recovery of WholesalePower Costs: Who is at Risk and Who is Not?"Regula toryFocusp. 1 (February 28, 2001).
1055 AVERA , DI
Idaho Power Company
58 Standard & Poor's Corporation
, "
Electric Utility BlackoutPuts Spotlight on Political and Regulatory Credit Risk
RatingsDirect (Aug. 21 , 2003).
59 The Value Line Investment Survey (Aug. 15 , 2003) at 1776.
60 The Value Line Investment Survey (June 20 2003) at 458.
61 The Value Line Investment Survey, Selection & Opinion
(July 18 , 2003) at 2857.
1056 AVERA , DI 86a
Idaho Power Company
hearing.
(The following proceedings were had in open
DIRECT EXAMINATION
(Continued)
Mr. Avera , did you also file rebuttal
BY MR. KLINE:
testimony in this case?
CSB REPORTING
Wilder, Idaho
Yes , sir , I did.
correct?
And it consisted of 21 pages, is that
That's correct.
And were there any additions or
corrections that you need make to your prefiled rebuttal
testimony?
Yes , there's one clarification.Some
quotations marks were left off.
14.
Could you direct us to where those are?
Page 6 of the rebuttal, beginning at line
That is , I think it's clear from the context this is
a direct quote from Ms. Carlock's testimony.
COMMISSIONER KJELLANDER:Is your red
light on, on your microphone?
THE WITNESS:, it is not.A touch.
that working?
COMMI S S IONER KJELLANDER:That works.
1057 AVERA (Di)
Idaho Power Company83676
Thank you.
THE WITNESS:Okay.We're on page 6 line
14 of the rebuttal testimony.And that paragraph is a
direct quote from Ms. Carlock's testimony so there
should be quotations marks at the beginning, at line 14
and quotation marks at the end at line 7 - - 17 , I mean.
Excuse me.
BY MR. KLINE:
Thank you.Wi th those - - wi th that very
minor change , Mr. Avera , if I were to ask you the same
questions that are set out in your prefiled rebuttal
testimony today would your answers be the same?
That would be, yes , sir.I must say that
people have problems with my name.It's a Hispanic name
that didn't survive the trip through Georgia.
Thank you very much.
MR. KLINE:I would request , Madame
Chairman that the prefiled rebuttal testimony of Mr.
Avera be spread on the record as if read in its entirety.
COMMISSIONER SMITH:If there's no
obj ection the prefiled rebuttal of Mr. Avera will be
spread upon the record as if read.
If you just draw that straight line across
the " a "
MR. KLINE:My Spanish is really bad.
CSB REPORTING
Wilder , Idaho
1058 AVERA (Di)I daho Power Company83676
COMMISSIONER SMITH:- - then you'd know
how to pronounce it.
MR. KLINE:I apologize.
(The following prefiled rebuttal testimony of
Mr. William Avera is spread upon the record.
CSB REPORTING
Wilder , Idaho
1059 AVERA (Di)
Idaho Power Company83676
INTRODUCTION
Please state your name and business address.
William E. Avera , 3907 Red River , Austin
Texas , 78751.
Are you the same William E. Avera that
previously submitted direct testimony in this case?
Yes, I am.
What is the purpose of your rebuttal
testimony?
The purpose of my testimony is to respond to
the direct testimony of Ms. Terri Carlock, submitted on
behalf of the staff of the Idaho Public Utilities
Commission ("IPUC"In addition , I will also rebut the
recommendations contained in the direct testimony of Mr.
Dennis E. Peseau testimony, on behalf of Micron
Technology, Inc., concerning the cost of equity for Idaho
Power Company (" Idaho Power" or "the Company"
) .
Please summarize the conclusions of your
rebuttal testimony.
With respect to the testimony of Ms. Carlock,
I concluded that her discounted cash flow ("DCF") results
were biased because of her exclusive reliance on IDACORP
Inc.(" IDACORP"), whose recent dividend cut violates the
assumptions of this method.Additionally, Ms. Carlock'
approach ignored other accepted methods of estimating the
1060 AVERA , Di -Reb
Idaho Power Company
cost of equity, as well as the flotation costs necessary
to raise equity capital.Finally, Ms. Carlock'
assessment of Idaho Power's relative risks focused
exclusively on the Company's low rates, while ignoring
the substantial uncertainties that investors must bear in
order to provide the benefits of lower electricity costs
to Idaho Power's customers.After excluding Ms.
Carlock's flawed DCF results and considering investors'
risk perceptions and an adj ustment for flotation costs
the results of Ms. Carlock's comparable earnings approach
support Idaho Power's requested fair rate of return on
equity in this case.
Meanwhile , Mr. Peseau did not conduct any independent
analyses of the cost of equity to Idaho Power.Instead,
his recommendations were based entirely on "updates" and
revisions" to my analyses.Much like the Holy Roman
Empire , however , neither of these two terms accurately
describes Mr. Peseau' s selective - and baseless
al teration of my original analyses, which must be
rej ected in their entirety.
II.TERRI CARLOCK
How did Ms. Carlock arrive at her 10.0 percent
cost of equity recommendation for Idaho Power?
Ms. Carlock estimated the cost of equity by
applying the constant growth DCF model directly to Idaho
1061 AVERA , Di -Reb
Idaho Power Company
Power's parent , IDACORP.She concluded that the results
1062 AVERA , Di -Reb
Idaho Power Company
this single DCF application indicated a cost of equity in
the 7.4 to 8. 8 percent range.Ms. Carlock also applied
the comparable earnings approach , which resulted in an
indicated cost of equity in the 10.0 percent to 11.
percent range.Based on these two analyses , Ms. Carlock
concluded that the cost of equity was in the 9.5 to 10.
percent range, selecting the 10.0 percent midpoint as her
recommendations for Idaho Power.
Do the results of Ms. Carlock's DCF analysis
represent a reliable basis on which to establish Idaho
Power's rate of return on equity?
No.Because she restricted her DCF analysis to
a single company - IDACORP - Ms. Carlock's results are
extremely susceptible to measurement error and bias.
I discussed at length in my direct testimony, estimating
the cost of equity is a stochastic process.In other
words , because the cost of equity is unobservable, it can
only be inferred by indirect reference to other available
data in the capital markets.But for any single cost of
equity estimate, there is always the potential that the
data used to apply the DCF model will not reflect the
expectations and required returns that investors
considered in arriving at the stock prices we can observe
in the capital markets.As a result , it is essential to
insulate against this bias by referencing a proxy group
1063 AVERA , Di-Reb
Idaho Power Company
or electric utilities with comparable risks.
Why is this particularly critical in the case
of IDACORP?
As discussed in my direct testimony, Idaho
Power and , in turn , IDACORP recently elected to cut
common dividend payments significantly in order to
improve cash flow and help maintain the strong credit
ratings necessary to support the Company's capital
expansion plan.Under the DCF approach , observable stock
prices are a function of the cash flows that investors'
expected to receive, discounted at their required rate of
return.Because dividend payments are a key parameter
required to apply DCF methods , this approach is not
well-suited for firms that do not pay common dividends or
have recently cut their payout.Indeed , Ms. Carlock
recognized in her testimony that "changes in the markets
and the dividend cut for IDACORP" complicated any
assessment of representative data for the DCF model.
Indeed, IDACORP' s decision to reduce annual common
dividends by some 35 percent severely violates the
assumptions underlying the constant growth DCF model that
Ms. Carlock used to estimate the cost of equity.
explained in my direct testimony, this approach is based
on the presumption of stable conditions , with earnings
di vidends, and book value all growing at a constant rate.
1064 AVERA , Di-Reb
Idaho Power Company
Such is hardly the case for IDACORP in light of its
decision
1065 AVERA Di -Reb
Idaho Power Company
to substantially alter its dividend payout.
Ms. Carlock recognized the importance of matching
the growth rate with a consistent dividend yield " so that
investor expectations are accurately reflects. But by
choosing to focus only on IDACORP in implementing the DCF
model , Ms. Carlock needlessly introduced significant
additional complexity into an already challenging
process.Indeed, the fact that the 8.1 percent midpoint
of Ms. Carlock's DCF range falls almost 200 basis points
below the lower bound of her comparable earnings analysis
illustrates the problems of bias associated with her
limited DCF analysis.The proxy group of western
electric utilities referenced in my analyses is
consistent not only with the shared circumstances of
electric power markets in the west , but also with the
need to ensure against the potential that a single cost
of equity estimate may not reflect investors' required
rate of return.
Did Ms. Carlock apply the risk premium approach
to estimate the cost of equity for Idaho Power?
No.While Ms. Carlock stated that "much of the
theoretical approach" that she used was consistent with
my testimony, Ms. Carlock did not use the risk premium
approach to estimate the cost of equity.The risk
premium method is widely recognized as a meaningful
1066 AVERA , Di -Reb
Idaho Power Company
approach to estimate the cost of equity.No single
method or model
1067 AVERA , Di-Reb
Idaho Power Company
should be relied upon to determine a utility I s cost of
equi ty because no single approach can be regarded as
wholly reliable.This is especially the case in light of
the fact that Ms. Carlock I S DCF range was based on the
resul ts of a single company.Indeed, as documented in my
direct testimony, applications of the risk premium
approach provide further evidence of the downward bias
inherent in Ms. Carlock's DCF results.
Did Ms. Carlock recognize that the investment
risks associated with electric utilities have increased?
Yes.Ms. Carlock noted that a plethora of
changes have impacted investors' risk perceptions
observing that:
The competitive risks for electric utilities have
changed with increasing non-utility generation,
deregulation in some states , open transmission access,
and changes in electricity markets." 3
Ms. Carlock concluded that, because of these greater
uncertainties , the difference in risk between industrial
firms operating in a competitive market and electric
utilities "is not as great as it used to be.
Did Ms. Carlock consider this increase in risk
in her analysis of the cost of equity for Idaho Power?
No.Ms. Carlock ignored this trend in
investment risks for electric utilities, asserting
1068 AVERA , Di-Reb
Idaho Power Company
instead that Idaho Power's "competitive risks" are lower
because of its "low-cost source of power and the low
retail rates. Ms. Carlock also asserted that the
Power Cost Adjustment mechanism ("PCA") reduces Idaho
Power's risks relative to other electric utili ties. 6
Does this represent an accurate assessment of
the investment risks investors' associate with Idaho
Power?
No.While I agree with Ms. Carlock that Idaho
Power's relatively low rates provide benefits to
customers and may improve the Company's competi ti
position , this one-sided view ignores the substantial
uncertainties that Idaho Power assumes to realize these
benefits.As explained in detail in my direct testimony,
because approximately one-half of Idaho Power's total
energy requirements are provided by hydroelectric
facili ties, the Company is exposed to a level of
uncertainty not faced by other utilities , which are less
dependent on hydro generation.While hydropower confers
advantages in terms of fuel cost savings and di versi ty,
investors also associated hydro facilities with risks
that are not encountered with other sources of
generation.
Reduced hydroelectric generation due to
below-average water conditions forces Idaho Power to rely
1069 AVERA, Di-Reb
Idaho Power Company
on less efficient thermal generating capacity and
purchased power to meet its resource needs.As the
Commission has noted,
1070 AVERA Di-Reb
Idaho Power Company
there are no guarantees about future stream flows or
market prices , "7 and in light of the recent past, this
dependence on wholesale markets entails significant risk
in the minds of investors, especially for a utility
located in the west.Investors recognize that volatile
markets, unpredictable stream flows , and Idaho Power'
dependence on wholesale purchases to meet the needs of
its customers exposes the Company to the risk of reduced
cash flows and unrecovered power supply costs.
Apart from exposure to market uncertainties, Idaho
Power also confronts the complexities associated with
obtaining the necessary licenses to operate its
hydroelectric stations.The process of relicensing is
prolonged and involved and often includes the
implementation of various measures to address
environmental and stakeholder concerns.These measures
can impose significant additional costs and/or lead to
reduced generating capacity and flexibility.
Does the fact that Idaho Power has a PCA
absol ve investors from risks of volatility in wholesale
power markets, as Ms. Carlock seems to imply?
No.The fact that Idaho Power has been granted
a PCA does not translate into lower risk vis-vis other
electric utilities.First , adj ustment mechanisms to
account for changes in power supply costs are the rule,
1071 AVERA , Di-Reb
Idaho Power Company
rather than the exception , so that Idaho Power's PCA
merely moves its risks closer to those of other
utilities.Second , the PCA does not prevent the lag
between the time Idaho Power actually incurs power supply
expenses and when it is actually recovered from
ratepayers.Investors are well aware that the
significant reduction in cash flows associated with
mounting deferrals can have a debilitating impact on a
utility's financial position.
Moreover , the PCA does not apply to 100 percent of
the difference between the actual cost of purchased power
and the amount collected through rates , with Idaho
Power's shareholders remaining at risk for 10 percent of
any discrepancy.Indeed , Idaho Power and its investors
has already experienced the impact that chaotic market
condi tions can have when the Company is forced to rely on
wholesale purchases to meet the gap in its resource needs
created by reduced hydro generation.Investors cannot
afford to discount the continuing prospect of further
turmoil in western power markets.Ms. Carlock's focus on
"low retail rates" entirely ignores market realities and
the substantial risks that investors must assume to
provide customers with the resulting benefits.
Did Ms. Carlock adj ust the results of her
quantitative methods to reflect flotation costs?
1072 AVERA , Di-Reb
Idaho Power Company
No.Ms. Carlock entirely failed to address the
issue of flotation costs , which, as discussed in my
direct testimony are a necessary cost incurred in
connection with raising common equity capital.When
equity is raised through the sale of common stock , there
are costs associated with "floating" the new equity
securities.Unlike debt flotation costs, which are
recorded on the books of the utility, amortized over the
life of the issue , there is no established mechanism for
a utility to recognize equity issuance costs. Unless some
provision is made to recognize these issuance costs, a
utility's revenue requirements will not fully reflect all
of the costs incurred for the use of investors' funds and
investors will not have the opportunity to earn their
required rate of return.Because there is no accounting
convention to accumulate the flotation costs associated
wi th equity issues, I recommended a minimum upward
adj ustment to the cost of equity of 20 basis points.
In light of the shortfalls in Ms. Carlock's DCF
approach and her failure to meaningfully address Idaho
Power's relative investment risks or the issue of
flotation costs , what is your conclusion regarding her
recommendations in this case?
In my opinion , Ms. Carlock's recommended 10.
percent cost of equity significantly understates the rate
1073 AVERA , Di-Reb
Idaho Power Company
of return that investors require from Idaho Power.Idaho
Power plans to add significant plant investment, such as
the
1074 AVERA , Di-Reb lOa
Idaho Power Company
Mountain Home generating facility, to ensure that the
energy needs of its service territory are met.To meet
these challenges successfully and economically, it is
crucial that the Company receive adequate support for its
credi t standing.Because of the shortfalls in her
analyses , Ms. Carlock's recommended cost of equity is
inadequate to meet this goal.
At the very least , the Commission should rej ect the
resul t of Ms. Carlock's DCF analyses, which is unreliable
and downward biased because of its focus on a single
company - IDACORP - that has significantly cut its common
di vidends .Meanwhile, Ms. Carlock I s comparable earnings
approach resulted in a cost equi t y range 10.
11. 0 percent,with Ms.Carlock not ing that selecting
a point estimate from within a range any point wi thin
(the) range is reasonable." 8 Considering the ongoing
risks associated with Idaho Power's continued exposure to
wholesale power markets , a rate of return at the upper
end of this range is warranted.Combining the 11. 0
percent upper end of Ms. Carlock's comparable earnings
range with a 20 basis point minimum allowance for
flotation costs results in a rate of return on equity of
11.2 percent , which is equal to what Idaho Power has
requested in this case.
III. DENNIS E. PESEAU
How did Dr. Peseau evaluate the cost of
1075 AVERA , Di-Reb
I daho Power Company
equi ty for Idaho Power?
It is important to note that Dr. Peseau'
opinions were not based on any independent analyses of
the cost of equity to Idaho Power.Rather , he arrived at
his recommendations based on a purported "update" of my
analyses by making revisions" to my methods.
What "updates" and "modifications" did Dr.
Peseau make to your cost of equity analyses?
Apart from conducting no analyses of his own
Dr. Peseau did not actually update my analyses.Ra ther ,
he "simply plugs in an updated figure for dividend
yield"lO to my DCF model.Thus , Dr. Peseau's "update"
completely ignored the other half of the constant growth
DCF equation; namely, the growth rate.To the extent
that investors' expectations for growth increase, this
would serve to offset any decline in dividend yields.
Apart from this incomplete "update", Dr. Peseau'
remaining modifications consisted of ignoring historical
trends in earnings growth in applying the DCF model
using alternative bond yields to apply my risk premium
approaches, and substituting a lower market return in the
CAPM.Finally, Dr. Peseau completely ignored the
flotation cost adjustment supported in my direct
testimony.
Q. What was the basis for Dr. Peseau' s "revision"to exclude historical growth rates from his
1076 AVERA , Di -Reb
Idaho Power Company
update" of your DCF analyses?
While Dr. Peseau granted that my "methodology
is not unreasonable he asserted that historical growth
rates should be discarded because I excluded firms rated
below investment grade from my comparable group.
Does your decision to exclude utilities with
junk bond ratings from your proxy group represent an
"implementation flaw " as Dr. Peseau asserts (p. 15)?
Absolutely not.The purpose of employing a
proxy group to estimate the cost of equity is to avoid
potential bias by focusing on firms facing comparable
risks and prospects.As I noted in my direct testimony,
the financial stress and lack of stability that
accompanies below investment grade bond ratings greatly
complicates any determination of investors' long-term
expectations required to implement the DCF model.
Moreover , the move from investment grade to junk bond
ratings implies a quantum increase in investment risks.
It is hypocritical for Dr. Peseau to assert that my proxy
group is "not representative" of electric utili ties in
the west , while simultaneously arguing that firms with
junk bond ratings should be considered comparable to
Idaho Power.
What about Dr. Peseau' s contention that the
companies in your group " are not really a sample ofelectric utilities" (p. 16)?
1077 AVERA , Di-Reb
Idaho Power Company
The fact that these firms may be engaged in
other lines of business is hardly remarkable , as the same
can be said about virtually every electric utility
operating in the U. s.Nevertheless, the fact that
investors regard these firms as electric utilities is
evidenced by the fact that The Value Line Investment
Survey ("Value Line") classifies them in its Electric
Utility (West) industry group.Moreover , the statistics
cited by Dr. Peseau do not convey an accurate portrayal
of the importance of utility operations to the firms in
my proxy group.Consider Black Hills , for example.
While Dr. Peseau reports that electricity sales accounted
for 38 percent of total revenues , he failed to report
that Black Hills' electric power generation and utility
operations accounted for approximately 84 percent and 65
percent of operating earnings and total assets,
respectively, for 2003.Contrary to Dr. Peseau ' s
assertions , the firms included in my proxy group provide
a reasonable basis on which to estimate the cost of
equity for an electric utility in the western region.
Does Dr. Peseau' s reference to earnings growth
trends for PNM Resources ("PNM") provide any basis to
exclude historical growth rates from your DCF analysis?
No.Dr. Peseau simply notes that PNM' s
earnings per share in 1987 of $2.00 are equal to what
1078 AVERA , Di-Reb
Idaho Power Company
21
Value Line is projecting for 2004.But this observation
says nothing about what investors might reasonably expect
for future growth based on more recent historical trends.
In fact, Dr. Peseau' s observation implies that investors
would anticipate zero growth , which would produce a cost
of equity for PNM equal to its dividend yield, or 3.
percent.Of course, this is clearly a nonsensical result
that is unrelated to a determination of investors' future
expectations.In fact, variability in historical
earnings serves to illustrate the increasing risks
associated with an investment in electric utility common
stocks.But given the unsettled conditions over the
near-term direction of the economy and the spate of
challenges faced in the electric power industry, the
historical growth trends reported by Value Line provide a
meaningful benchmark in implementing the DCF model.As a
resul t, when assessing investors' expectations of future
growth it is entirely appropriate to consider historical
trends in earnings, along with securities analysts'
proj ect ions, as I have done.
Is there any basis for Dr. Peseau' s statement
that Idaho Power's requested 11.2 percent cost of equity
is "unreasonable on its face"(p. 18)?
No.Based on changes in bond yields , Dr.
Peseau implies that the cost of equity for Idaho Power
1079 AVERA , Di -Reb
Idaho Power Company
has dropped "by 200 basis points or more. "12 But Dr.
Peseau' s
1080 AVERA , Di-Reb 15a
Idaho Power Company
observation is meaningless.First, he ignores the
dramatic increase in the level of risks that investors
now associate with electric utilities.As discussed in
my direct testimony, these uncertainties are heightened
for a utility operating in the western U. S., especially
given Idaho Power's ongoing exposure to potential
volatility in wholesale power markets.Moreover , as I
also explained in my direct testimony, there is
considerable evidence that when interest rates are
relatively low , equity risk premiums widen. Accordingly,
the cost of equity does not move in lockstep with
interest rates.In fact , the only way to assess the
relative impact of changes in risks and capital market
condi tions since the Commission's last decision in 1995
is to conduct an independent analysis of the cost of
equity - something Dr. Peseau did not even attempt.
Is there any merit to Dr. Peseau's suggestion
that there are inconsistencies in your risk premium
approaches that lead to an upward bias in your results
(pp . 13 - 14) ?
No.The bond yields used in my applications of
the risk premium method were consistent with the
underlying data sources used to compute the equity risk
premiums , as well as with the investment risks
corresponding to Idaho Power's single-A grade credit
1081 AVERA , Di-Reb
Idaho Power Company
rating.In developing risk premiums based on authorized
rates of return on equity
1082 AVERA Di-Reb 16a
Idaho Power Company
on Exhibit WEA- 8, I matched the average allowed rates of
return in each year with the average yield on public
utili ty bonds reported by Moody's Investors Service
( "
Moody'
) .
This composite interest rate reflects the
average risk profile of the electric utility industry,
and there is simply no basis for Dr. Peseau' s insinuation
that this somehow results in upward bias.Similarly, my
analysis of realized rates of return reported on Exhibit
WEA-9 was based on a consistent set of data, as reported
by Standard & Poor's Corporation ("S&P"Because S&P
does not publish an average public utility bond yield , my
analyses relied on the yield on single-A rated issues as
a proxy for the average risk of the industry.Moreover
the interest rates that Dr. Peseau cites in his "update"
to not correspond to other published sources.For
example , Moody's reported that the average yield on
single-A public utility bonds for February 2004 was 6.
percent,13 considerably higher than the 5.7 percent rate
ci ted by Dr. Peseau.
How did Dr. Peseau "update" your application of
the Capital Asset Pricing Model ("CAPM"
Dr. Peseau did not update or otherwise address
my CAPM approach.Rather, he ignored it entirely and
instead substituted a market risk premium into my
analysis that was based on an entirely different method.
1083 AVERA , Di -Reb
Idaho Power Company
As explained in my direct testimony, I applied the CAPM
based
1084 AVERA, Di -Reb 17aI daho Power Company
on a forward-looking estimate of the market risk premium
that relied on investors' current expectations in the
capital markets.Meanwhile, Dr. Peseau simply asserted
that " (t) he correct market risk premium to use at this
time" is 7.00 percent.In fact, however , this 7.
percent risk premium is based on historical realized
returns , not on the forward-looking expectations that
drive investors' required rate of return in today' s
capi tal markets.The end result of Dr. Peseau' s thinly
veiled shell game is not an update or revision to my
analysis , but instead a CAPM cost of equity that fails to
reflect investors' current required rate of return.
Did Dr. Peseau consider the need to account for
past flotation costs?
No.Dr. Peseau does not take issue with my
testimony that an adjustment for flotation costs is
reasonable in establishing a fair rate of return for
Idaho Power.Like Ms. Carlock , however , Dr. Peseau
entirely ignored the issue of flotation costs in
conducting his "revisions" and "updates" to my analyses.
As discussed earlier and in my direct testimony,
flotation costs are legitimate and necessary, and unless
an adjustment is made to the cost of equity, investors
will not have the opportunity to earn their fair rate of
return.
Is there any merit to Dr. Peseau' s contention
1085 AVERA , Di-Reb
Idaho Power Company
that your characterization of conditions within the
electric utility industry is "too bleak"(p. II)?
No.It is curious that Dr. Peseau takes issue
with my description of the challenges that investors have
confronted in the electric power industry, while
simultaneously granting that "all of these observations
are accurate enough. "16 Moreover , the simple fact that
the maj ority of utilities have "weathered the recent
disasters" 17 says nothing about the risks that investors
now associate with the industry.As I documented in my
direct testimony, observable measures such as bond
ratings clearly illustrate the revised perceptions of the
risks in the industry and the weakened finances of the
utili ties themselves.Moreover, while Dr. Peseau
suggests that this assessment just reflects a pessimistic
bias on my part , my personal opinions are irrelevant and
were not the basis of my analyses.What matters are the
opinions of investors , who, demonstrated in my direct
testimony, recognize that the risks inherent in the
electric utility industry have increased significantly.
Indeed, as noted earlier , Ms. Carlock also granted that
electric utilities now face greater uncertainties than in
the past.
Does Dr. Peseau' s reference to a single earned
rate of return (p. 11) provide any meaningful basis to
evaluate investors risk perceptions or their required
1086 AVERA, Di-Reb
Idaho Power Company
rate of return?
No.The fact that Idaho Power's shareholders
may have earned posi ti ve returns in a single , historical
period says nothing about their forward-looking
assessment of investment risks or their return
requirements.In fact, as Dr. Peseau grants the
previous few years produced some negative returns. "18
Dr. Peseau' s observations regarding the seemingly high
variabili ty of returns to Idaho Power's shareholders are
more supportive of my contention that the investment
risks associated with electric utilities , including Idaho
Power , have increased.Indeed, Dr. Peseau grants that
the recent "boom and bust" has "produced wildly erratic
year to year results ... for most of the utili ties in the
western United States. "19 For investors,wildly erratic"
is synonYmOus with a level of investment risk far in
excess of what Dr. Peseau presumes.
Does this conclude your direct rebuttal
testimony in this case?
Yes, it does.
1087 AVERA, Di-Reb
Idaho Power Company
ENDNOTES
Carlock Direct 11.
Id.
3 Carlock Direct
Id.
Id.
Carlock Direct
7Idaho Power granted $256 million deferral , but bond plan
denied, Idaho Public Utilities Commission (May 13 , 2002)
8 Carlock Direct at 13.
9 Peseau Direct at 13.
10 Id.
11 Peseau Direct at 15.
12 Peseau Direct at 18.
13 Moody's Investors Service, Credit Perspectives (Mar.2004)
14 Peseau Direct at 14.
15 Id.
16 Peseau Direct at 11.
17 Id.
18 Peseau Direct at 11.
19 Peseau Direct at 16.
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open hearing.
(The following proceedings were had in
MR. KLINE:You didn't have any exhibits
wi th your --
THE WITNESS:, Mr. Kline, I did
not.
MR. KLINE:With that, Mr. Avera will be
available for cross -examination.
Eddie?
COMMISSIONER SMITH:Thank you, Mr. Kl ine .
BY MR.GOLLOMP:
Do you have any questions , Mr.
MR. EDDIE:No questions.
COMMISSIONER SMITH:Mr. Gollomp.
MR . GOLLOMP:Yes, I do.
CROSS-EXAMINATION
Dr. Avera, can you hear me?
Yes, Mr. Gollomp, I can.
Good morning.
Good morning.
Dr. Avera, your 10.4 percent BCF analysis
is based upon a 4.4 percent dividend yield pI us a 6
percent growth rate; is that correct?
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through 19.
Yes, sir.
And that's summarized on page 55 , lines 16
right?
Excuse me for a moment.You have that;
Page 55 of the direct?
Yes, I'm sorry.
I don't think that's correct.
Well , that's --
I think the numbers are correct but not
the page reference.
CSB REPORTING
Wilder , Idaho
Is that page 55?Combining the 4.9 DCM,
just using that particular part of your testimony as a
summary of the position , when you say combined 4.
percent average dividend yield with 6 percent midpoint of
my representative growth rate range implied a DCF cost
equi ty for this group of electric utili ties of 10.
percent.
I find that on page 51.Now , it may be
sometimes we submitted this electronically so maybe the
pagination changed.
page 55.
COMMISSIONER SMITH:We'll now be at ease.
(Discussion off the record.
THE WITNESS:Tha t is correct.It is on
COMMISSIONER SMITH:Well, go back on the
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record now.
MR . GOLLOMP:I believe we have a complete
response to my question.
COMMISSIONER SMITH:Well , were we on the
record when the witness responded?
THE REPORTER:Yes.
COMMISSIONER SMITH:All right.Thank
you.
BY MR. GOLLOMP:
Okay.So Dr. Avera, you cite three
sources of growth rates, analyst proj ections, historical
earnings growth , and earnings retention which you refer
to as the b x r; is that correct?
That is correct.
Would you agree - - well, let me direct
your attention to page 52.
Yes , sir.
And at the same time your Exhibit No.
WEA - 6 .
Do you have those references before you?
Yes , sir.
On lines 7 through lI on page 52 of your
direct testimony you stated , as shown there , with the
exception of Value Line's estimates these security
analysts' proj ections suggest growth rates - - excuse me,
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suggested growth the order of 5.0 to 5.5 percent for the
reference group of electric utilities.
Those figures appear also on your Exhibit
WEA-6, is that correct?
Tha t is correct.
And where you show the projections that
you refer to from IBES criticize Value Line , First Call
and Multex.And in addition on the right-hand side of
your Exhibit No. WEA-6 you show historical growth
proj ections of the past ten years of 7.3 percent and 8.
percent for ten years and five years respectively; is
that correct?
Yes, sir.
Now , I direct your attention to your
Exhibit No. WEA-And that document refers to your
discounted cash flow model which is your proj ected b x
growth and you show for the b x r growth 4.7 percent; is
that correct?
Yes, sir , that is correct.
Am I correct then , Dr. Avera , that in
reference to the proj ections you refer to from the
analyst and your b x r growth are a range of 4.7 to 5.
percent, that the only historical growth rate - - excuse
, the only growth rate in excess of those are the
historical growth rates which you show on your WEA-6 of
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3 and 8.1 percent; is that correct?
That's correct.
Would you agree that the DCF growth rate
should be a prospective expected growth rate?
Yes.What investors expect , and I believe
and I think Ms. Carlock in her testimony and Dr. Peseau
in his testimony, say that one of the things investors
look at is the historical record.So I think the
historical record informs investors in developing their
prospective growth expectations.
Thank you.Now , the various growth
proj ections that you show in your Exhibit WEA- 6 for IBES,
First Call , and Multex , are based on a survey of a number
of analysts; is that correct?
That is correct.
Would these analysts preparing these
growth rate proj ections have access to historical growth
rate data?
Yes.
And to the extent they deem such
historical data relevant to the outlook for these
companies , the companies you listed in your proxy group,
would it be reflected in some manner in their own growth
rate proj ections?
It could be.To the extent that they
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considered those it might have been one of the inputs.
But we're not trying to guess what the analysts believe,
we know that.We're trying to infer what investors in
general bel ieve
I understand.But I'm focusing right now
on your reference to the analysts and I'm asking you as
you haven't indicated to me , that would it be reasonable
to assume that they had before them the historical data
that you refer to in your exhibits for this five and ten
year respective periods?
I do not disagree, Mr. Gollomp, that that
may have been some of the information that they used.
Okay.Would you agree that most rate of
return analysts using the DCF model favor the use of
analyst earning proj ections over the historical earning
growth rates?
I don't know if I could say most.In my
experience analysts use both.Now , whether most analysts
favor or not the proj ections versus historical , I can'
say.My assessment would be most analysts consider both.
You try to prioritize , based on your own
testimony in which you indicated repeatedly, that DCF is
a prospective expected approach.
It is a prospective approach , but we'
trying to model what investors require when they pay the
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money they pay for stocks.And investors consider
historical as well as prospective.That's why on the
Value Line sheets that all the witnesses use, both
historical and prospective data is presented.
I believe they we're in agreement that the
analysts to which you have utilized in your exhibit, the
IBES , Mul tex , the First Call , presumptively would have
used the historical growth rates in arriving at their
proj ections.
Is your question do the other two rate of
return witnesses agree that analysts use perspective data
or use historical data?I don't know.I think my
reading of their testimony is that investors use
historical as well as prospective data.
m just referring to your use and
reference to the proj ections put forth by the analysts as
utilized in your testimony.And all I was asking you is
presumptively those analysts who came up with the results
that you have utilized in your exhibits, would have
utilized as relevant for their purposes , would have
utilized historic data which you have indicated and
included in your exhibits?
Yes.And do not disagree that those
analysts in coming up with their five-year growth
proj ections had available and probably incorporated
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information from history.
Fine.We're in agreement.Thank you very
much.
I'd like to discuss with you your risk
premium analysis on WEA-8.Do you have that exhibit
before you?
I will shortly.Yes , sir.
Dr. Avers, is it fair to say that this
analysis seeks to measure the risk premium for the
average electric utility company?
Yes , based on the experience of the
estimates of regulatory commissions.
Have you adjusted the results on your
Exhibit WEA-8 for Idaho Power's risk profile?
I did.When I applied the risk premium
used the yield on Idaho Power's bonds of their risks.
But in terms of determining the relationship between the
authorized return and the risk premium, the appropriate
interest rate to use is the average utility because these
authorized returns reflect returns allowed for utilities
with bond ratings across the board.
So I think the average utility bond yield
is the appropriate benchmark.
This analysis that you have in WEA-
indicates that the historic risk premium is 3.8 percent.
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That's on - - that's set forth in the right-hand column of
your exhibit; is that correct?
08, that is correct , before making the
adjustment for the inverse relationship between the
interest rates and the risk premium.
That was going to be the next question.
Thank you.
Have bond yields , utility bond yields
firmed further since your August 2003 value of 6.
percent?
Yes , they've dropped somewhat.
What is a more realistic value today,
Dr. Avera?
Well , as of today, I don't know.Checking
CNBC before I left the hotel room I think bonds were
going down today as they did yesterday in terms of
prices , therefore the yields were going up.So the bond
yield has been particularly volatile in recent weeks as
the stock market has been particularly volatile.
I think if we look back at February
averages we find a bond yield in the low 6' s .So there'
been a drop of perhaps 20 or 30 basis points.
Now , keeping that in mind, what would be
the risk premium figure associated with that bond yield
would you know?
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Well , again , this is an approximate, but
the risk premium adjustment would increase as the bond
rate - - as the bond yields decrease because of the
inverse relationship.So the risk premium would go up
approximately 43 percent of what the bonds went - - the
change in yields.So, you know, if the bond yield
change , let's say was 30 basis points , the risk premium
would increase something over 20 basis points.
So talking a range of maybe 4.39 to 4.
percent, for the risk factor?
Yes.It would be higher.It would be
higher than 4.39 if in fact
Right.
- - bond yields have continued or have
decreased over the period of time since the original
analysis.
Looking at your regression data base on
your Exhibi t Is bond yield the independent variable
in your regression?
Yes.
And does this variable range from the low
of 7 percent to 15.6 - - point 2 percent.
Yes, sir.
And as indicated on your exhibit the
average is 9.81 percent; is that correct?
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Tha t is correct.
Therefore , you're using a regression model
estimate using a range for your independent variable of
0 to 15.6 percent and an average of 9.8 as you
indicated.Am I correct that you're now extrapolating
that historical model to interest rate conditions that
never existed in your historic data base; is that
correct?
That is true.As all the witnesses have
pointed out we're in a period of extraordinarily low bond
yields relative to the historical record, 40-year lows.
And I think that's reflected in the comment you make.
Would it be appropriate to say that it'
outside the range of experience?
It's outside the range of recent
experience.
Now , you and I were talking before the
hearing, 40 years is not so long to us.
No.
But in terms of recent experience, it is
out of the range.
Thank you.I would like to address your
attention to your risk premium number two, which appears
on WEA-
Yes , sir.
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Idaho Power Company83676
Dr. Avera , does this analysis estimate the
risk premium by comparing historical returns for electric
utilities versus returns on bonds during the period of
1946 to 2002?
Yes.Historical returns on utility
equities versus what was realized on bonds during the
same year.
And if you look at the bottom center of
your document, WEA- 9 , you indicate an equity risk premium
of 4.That's where you subtracted your annual realized
return of 4.2 - - excuse me , 6.27 from the S&P electric
companies to arrive at your 4.01; is that correct?
That is correct.And you will notice on
this exhibit if you go back to those years in the ' 60s
see bond yields even lower than we're experiencing today.
Right.As you indicated , in your column
annualized realized -- excuse me, realized return of 6.
on the average for that period.
27.
Excuse me.I stand corrected.Dr. Avera,
this exhibit also shows a column listing the prevailing
bond yield for each year; is that correct?
That is correct.
And a calculation I made, or I asked
someone to make for me, to average the ' 57 bond yield for
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the '46 to 2002 period.And I obtained a 7.29 percent.
Would you accept that subj ect to check?
Yes, sir.
Thank you.Assuming this calculation is
accurate, does this mean that on average investors
experienced capital losses on bonds?
Yes , sir.Well , the prevailing experience
was capital losses because when yields go up investors in
fixed income instruments experience capital losses.And
since the prevailing interest rate , as you and I have
discussed the '40s,'50s and ' 60s was lower than it
subsequently became in the ' 70s,'80s and ' 90s,
bondholders lost as a result of those rising interest
rates.
And that's the difference with what you
came up with as an average of 7.29 and 6.27 that you show
as the annual realized?
That is correct.But what actually
happened to investors was they lost or they gained.
Considering capital losses their net return was the 6.27.
That was what was historical-wise for investors.
Now , Dr. Avera, in your opinion when
investors acquire utility bonds do they expect capital
losses or do they expect returns commensurate with yield
at the time of purchase?
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Well , I think investors consider the risk
and the return, and they know that one of the things that
can happen when you buy a bond is that interest rates
rise so the resale value of the bond goes down.Just
like interest rates may fall and the resale value of the
bond goes up.
So I think investors who invest in bonds
consider both the yield and the capital appreciation and
loss.You can't hold bondsTha t 's part and part.
wi thout being exposed to both parts of the return
equation.
Let me put this in example form.
Investors purchase bonds at a time - - excuse me, at a 7
percent yield.Is that what they expect to receive as a
return or do they expect a total return less than that
due to capital losses?
Well, if they hold the bond to maturity
they will , in fact , receive the 7 percent except for the
problem of reinvesting the earnings in the interim.But
I think an investor makes an assessment of risk which
considers the possibility of capital losses and gains
especially if you look on a year-by-year holding period.
Let me ask you, Doctor, would you agree
that if this analysis is conducted simply using bond
yields as the measure of bond return rather than
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factoring in the capital losses on average as you did
then the historical risk premium would be about 3 percent
rather than 4 percent; is that correct?
That would be the arithmetic but that
wouldn t be reality to investors.Because investors who
held bonds over this period of general realizing interest
rates, on balance suffered capital losses.So that's the
risk and the reality of what they received.
The hopeless sensation for the average
investor , without indulging the mind of the average
investor , would be that they would not be losing money
but not experiencing capital losses.
No.I would think a rational investor
realizes that when you buy a bond you only get your
coupon and the resale value may go up or down depending
on what happens to interest rates.So I think investors
are mindful of the fact that bonds are not risk-less
investments.
Thank you , Dr. Avera.
Dr. Avera, I'd like to direct you to your
CAPM , which is on Exhibit WEA-10.
Yes, sir.
Now , on Exhibit WEA-10 am I correct that
one of the inputs is the average CAPM five-year growth
rate of 12.5 percent; is that correct?
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That's correct.
Is this based upon what you call a
bottom-up compilation for earnings projections for each
of the 500 companies?
Yes , sir , it is.
Would you agree that certain vested
services such as one of the ones you refer to as IBES
offer publicly what is a top-down forecast of earnings
growth for the 500?
Yes , sir , they do.
Would you be kind enough to describe for
the record the difference between the bottom-up and the
top-down?
The bottom-up is basically you take each
company in the S&P 500 and you take the earnings
estimates for that company, let's say it's General
Electric , or General Motors, or General Foods.Each of
those has an estimate that those analysts that specialize
in that company make.So you take the 500 individual
estimates of future growth , you weight it by the same
weight as the S&P 500, so based on all of those
individual estimates from the analysts that follow those
customers, you start at the bottom and you come up to an
implied growth rate for the entire index.
So it's based on those analysts that
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follow the individual companies.
So there is a mixed approach to this?
Right.
Some analysts use the top-down, others use
the bot tom-up?
Right.The top-down is there are some
analysts, a few analysts that are bold enough to make
estimates for the entire index.So the top-down uses the
growth forecasts that those analysts who just look from
the top, and say this is what I think the growth rate of
the earnings of the index are going to be for the next
fi ve years.
Notwi thstanding, for example, that the
composition of the index changes over time.
I understand.And there are obvious
reasons why certain analysts use the top-down approach.
Well , there are analysts who do.Do you
mean certain rate of return analysts?
Those engaged in proj ections .
They are some analysts who do because
there are investors who invest in income, or invest in
index funds, or invest in index options.So there
obviously is a market for the top-down proj ections
they wouldn't be published and the analysts wouldn'
spend their time developing them.
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Dr. Avera, is one of the reasons why
certain analysts use the top-down opposed to the
bottom-up is to avoid what they believe is the
institutional bias in the bottom-up by those analysts who
engage in the bottom-up approach?
There are some analysts who may believe
there is a bias.In my opinion , and based on the
research that I've seen , the empirical research , for the
companies in the Standard and Poor 500 there is not a
systematic optimistic or pessimistic bias.So there are
those who believe there may be much a bias.I don't
believe it's there and I think the empirical evidence is
on my side.
Okay.I'll not walk down that street with
you, we could spend the morning.
Yes, sir.I had these articles with me.
Based on your knowledge , could you tell me
how the IBES top-down value compares with your 12.
percent bottom-up value, if you know?
I really don't know exactly.Sometimes
it's higher , sometimes it's lower.Recently it has been
lower in growth rate.But as it stands today, I couldn'
tell you.
Thank you, Dr. Avera,for indulging me.
I appreciate cross-examining you again.
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Wilder, Idaho
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Yes, sir , Mr. Gollomp.It's always a
MR . GOLLOMP:That completes my
pleasure.
cross-examination.
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Wilder , Idaho
COMMISSIONER SMITH:Thank you , Mr.
Gollomp.
Mr. Purdy, do you have questions?
MR. PURDY:I do not.
break.
COMMISSIONER SMITH:Mr. Ward.
MR. WARD:Just a few.
COMMISSIONER SMITH:How many?
MR. WARD:Enough we should take our
COMMISSIONER SMITH:, good.
We'll be on break for ten minutes.
on the record.
(Brief recess.
COMMISSIONER SMITH:We'll go back
Mr. Gollomp.
MR . GOLLOMP:Yes.I have one more
question to ask Dr. Avera , at your pleasure.
COMMISSIONER SMITH:Sure.Go ahead.
BY MR. GOLLOMP:
MR . GOLLOMP:Are we on the record?
testified in a Nevada power rate case?
Dr. Avera, am I correct that you recently
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Yes , sir.
Would you indicate for the record your
recommended ROE , return on equity?
I recommended a range very much as we did
here.The Company requested 12.4 in order to maintain
their financial integrity.
Can you recall what you came up with as
the DCF method, your result?
I believe the result was 11 or 11.
somewhere in that range.It might -- no , no, let me make
sure.
It might have been a little bit lower.
think more in the lOs, as I sit here.
Okay.think it'10.percent.
Right.That sounds approximately correct.
Do you know what the commisslon arrived at
as the final determination with respect to the return on
equity?
Yes, sir.
What was that?
10.25 percent.
MR. GOLLOMP:Thank you, Dr. Avera.That
completes my cross-examination.
COMMISSIONER SMITH:Thank you, Mr.
Gollomp.
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Next we'll go to Mr. Ward.
MR. WARD:Thank you.
CROSS-EXAMINATION
BY MR. WARD:
Dr. Avera , I'm going to ask you primarily
about your DCF approach.ve sworn off trying to deal
with the complicated risk premium.
Would it be fair to say that the DCF
analysis in the end when you get down to the constant
growth model , is relatively simple.That is , the
indicated return on equity is the sum of the dividend
yield plus a growth rate?
The arithmetic is relatively simple , Mr.
Ward.Coming up with the inputs, is not.
Yes.And it's true , is it not , that the
dividend yield is relatively simple.If we know a
dividend yield
- -
we can identify dividend yields at any
given time, can we not?
Well, with this exception , the DCF model
requires a dividend yield based on the coming dividend
for the year.So it is not entirely observable, but it
is nearly observable because there is an element of
forecast involved.
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All right.I'll accept that.
Now , in this case you used a proxy group
of utilities to calculate your DCF results, did you not?
Yes , sir.
And as you note in your testimony, once we
have the dividend yield the tricky part is identifying
the growth rate, correct?
Yes , sir.
And in fact, on page 43 of your testimony,
lines 13 through 16 , you say to the extent that the data
used to apply the DCF model does not capture the
expectations that the investors have incorporated into
current stock prices, the resulting cost of equity
estimates will be biased.
I take it that primarily that observation
primarily applies to the calculation of the growth rate.
Tha t is correct.There is a little bit of
expectation in the dividend yield , but the big swing is
what investors are expecting for this long-term future
growth that the DCF model requires.
All right.Now , in your calculation of
growth rate, you used several different approaches , did
you not?
Yes, sir.I looked at several different
indices , indicia of what the investors might expect.
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Okay.And those are summarized on Exhibit
6 and 7; is that correct?
Yes, sir.
Now , the
- -
of course, Exhibit 7 arrives
percent return and all the rest are
- -
excuse me,
growth rate.And all the rest your indicla appear
Exhibit that correct?
That's correct.
Now , in your testimony you identified the
growth rate as 5 to 7 percent; is that true?
Yes, sir.
And I take it from that testimony that
among other things , you threw out, or essentially
disregarded two outlying numbers.
I threw out or gave them less weight for
the reasons I expressed in my testimony.Tha t they are
driven by Value Line estimates.And at present Value
Line has a very negative view of the electric utility
industry and are advising their subscribers to steer
clear of it.So I think that's reflected in their growth
rates being at odds with other indicia.
Okay.So you threw out their 2.7 percent
proj ection as well as the highest of the historical
growth rates at 8.1 percent.
That is correct.
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Now , the thing that strikes me when I look
at these exhibits is that even if we disregard the Value
Line 2.7 percent approach , the historical numbers that
you calculate here are roughly 50 percent higher , on
average, than all the other proj ections; are they not?
50 percent , you mean you're comparing 5 to
7 and a half?I mean , how are you getting 50 percent?
That's how I'm getting it.
They are higher.And as I explained in my
testimony, the other growth rates are explicitly
five-year growth rates.They re analysts , and Value
Line , and various surveys of analysts as to what they
expect for the next five years.The G in the DCF model
is what investors expect in the infinite future.So I
believe that investors, much like Value Line, and for
reasons I explained in my testimony, are not looking at
the next five years as being completely indicative of the
long-term future.And I think investors are likely to
look at the history informing them toward the long-term
future.So they look at the five-year forecast but they
say, five years has a cloud over it.So my G for the
long-term future is somewhat more representative of
long-term experience.
All right.The rationale of
- -
let me see
if I can restate the rationale for using historical
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figures that you give on page 53.
If we are going to use historical figures
in this context , the implication must be that if
investors think the past is prolog, then these figures
that you use here represent their view of what their
growth - - their returns from growth would be if they
bought the basket of stocks that you had in your exhibit.
I think they view their past experience as
somewhat indicative of what they expect in the future
very much like Dr. Peseau and I use historical-realized
returns that investors experience as what they expect in
the future.I think it is reasonable to assume that
investors use their recent experience to inform them
about what may happen in the future.
Okay.But would it be true that what
we're trying to do here is find a proxy, of course, for
Idaho Power itself , but we're using this group of
utilities.So what I'd like to make sure I understand is
that, is the implication that the investors looking at
this group of utilities would on average assume there'
going to be a growth rate of , say, 7.3 percent for ten
years?
I think they believe that that may happen
based on the experience in the past when they re trying
to say when I buy this stock what's going happen in terms
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of growth.They look at the past and say, well , you
know, in the past over the long term there's been a 7 and
a hal f percent growth.So that's one of the things that
may happen.
I think they also look at these five-year
forecasts that are given to them by analysts that have
numbers like 5 percent and they say, well, you know , I
expect growth between 5 and 7.That's my understanding
of the way I think investors may be looking at the world
right now.
Okay.And it would be - - and it would be
the averages that they would be looking at, correct?
Yes.
Now , another thing that jumps out at me
when I look at Exhibit 6 is that the historical ten-year
growth rate for PNM is 19 percent.Do you see that
figure?
That is correct.
Do you really think that PNM can grow at
19 percent a year in the future?
I don't think that's unreasonable.PNM
has had - - went through a terrible period of time in the
80s.Had to cut their dividends, suffered a decline,
negative earnings and I think most investors believe that
those days are behind them that PNM has refocused on its
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utility business,and can experience strong growth
the future.don'think you can dismiss the
percent being out the picture.m not focusing on
any one number , I'm including all of these as in the
information set that investors look at.
Isn't it true that if we were to eliminate
PNM from this array that the average ten-year growth rate
would be approximately 5 percent?
I haven't done the arithmetic , but if you
eliminate a high one it goes down; if you eliminate a low
one it goes up.
Okay.
MR. WARD:May I approach , Madame Chair?
COMMISSIONER SMITH:Yes, you may.
MR. WARD:I believe our next exhibit
number is 111.
COMMISSIONER SMITH:No.It's 711.
MR. WARD:711 , I'm sorry.Let's make
puget 111 - - 711 , and Xcel will be 712.I should have
recruited some help for this but I will next time.
Now , Madame Chair , in case the record didn't
catch this, I distributed two one-page exhibits.The
Puget Energy Inc. Value Line synopsis I'd like marked as
711, and the Xcel Energy as 712.
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(Micron Exhibbit Nos. 711-712 were marked
for identification.
BY MR. WARD:
Now Dr. Avera , do you recognize these
document s ?
Yes , these are Value Line sheets.
And these two companies appear in your
array; do they not?
Yes, they do.
And would you show the Commission where
you can find the growth rate for these two companies?
The growth rate is what
- -
well, there'
two ways to find it.But the simple way is in the
left-hand column of each page there is a box , sort of a
little more than half way down, that has the caption
Annual Rates.
And then it has past ten years , past five
years, and then estimated ' 00-' 02 to '06-' 08.So in
that box there are growth rates and then they're for
various magnitudes for revenues, cash flows , earnings
di vidends, and book value.
MR. WARD:ve just handed out a one-page
document that I'd like marked as Exhibit 713.
(Micron Exhibit No. 713 was marked for
identification.
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BY MR. WARD:
Doctor , you just finished telling me that
we shouldn't eliminate the anomalous result of PNM from
the historical averages.
No, sir.I didn't agree that PNM was an
anomalous resul t .I think that for reasons that
expressed I believe in my answer , given the history of
the Company I think that was
- -
there would be no reason
to dismiss the possibility of a 19 percent growth rate.
Well , the record will show what we
actually said back and forth.What I've handed you, do
you recognize what the basis of Exhibit 713 is?That'
your Exhibit No.6; is it not?
Yes, sir.
What I've done is I've added the results
from your Exhibit No.7 in the right -hand column under
the b x r at 4.7 percent, that's correct, is it not?
Yes , sir.
Now , I've also added in the actual
historic figures for puget Energy and Xcel.And I shoul
perhaps explain to the Commission that the Pinnacle West
NMF under the ten-year return is actual - - it's actual.
That is, it does have a blank.There's no meaningful
data, apparently, from Value Line's point of view.And
ve calculated with those additions a new average.
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Would you like to check my math, Doctor?
No.I don't think we need to delay the
hearing for that.It looks - - theIt looks reasonable.
math looks reasonable.I disagree that this is a
meaningful exercise.
Well , Doctor , if I'm an investor looking
forward and I decide that I'm going to take the
historical view as part of my analysis or the basis for
my analysis, I'm going to look at all the stocks, am I
not?And all of the growth rates no matter what they
show.
No, I don t believe that.I believe
investors take a more informed view , Mr. Ward.I think
they evaluate whether the numbers are useful to them or
not.So I don't think investors merely do averaging.
think they do assessment because they're putting their
money on the line and I think they look behind the
numbers.
But if I thought that past is prolog and
that history teaches me what I can expect in the future,
there I S only two conclusions I can draw looking at the
historical data.One, is that I use all of the
historical data and arrive at a true average.Or two, I
assume that somehow I'm such a sensational stock-picker
that I won't buy the dogs that have negative growth
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rates.
Isn't that -- isn't that a fact?
No, sir , I don't think it's fact.I think
investors look at the past and they take from the past
what they think informs them about the future.I served
28 years in the Navy in the past.I don't think I'll
serve 28 years in the Navy in the future.But there are
other things that have happened in my past that I think
do inform me about the future.
All right.So the 19 percent growth rate
for PNM - - well , let me back up.
Are you aware of any utility that for a
considerable period of time has grown at 19 percent a
year?
As I sit here today I can't think of one.
That is not to say that there hasn't been one.Actually
there was a period of time when Houston Lighting and
Power, probably the period between 1970 and 1977, grew at
that kind of rate.Its earnings were at that rate.
Now , in effect you're telling me, are you
not, that we shouldn't disregard the 19 percent growth
rate for PNM , but we should disregard the negative growth
rates?
That is correct.Because these growth
rates would imply that an investor would get a one or
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zero percent return if they bought puget Energy and
received the dividend, which according to Exhibit 711 was
3 percent.And then if you suffered a negative growth
rate the effect would be that you would earn less on this
utility investment then you would earn on a certificate
of deposit.So I don't think an investor who actually
bought and paid $23 for Puget Energy felt that that I s
what they expect.Because what we're trying to do is
look at investors who are paying these dollars for these
stocks today and what they must have had in their head
when they did that.And no investor is going to buy a
stock where they expect a negative return, or a very low
return.
Now , maybe that's what will turn out
because the world is full of surprises.Bu t we'
dealing with investor expectations looking forward.
If there were an index for this group of
companies, and I bought - - an index fund, and I bought
the index fund, I would get all of those returns
historical - - if I bought it ten years ago I'd get all of
those historical returns would I not; losses and gains?
That, that - - well , we're talking about
evening growth.That is not what the investor actually
received because we would have to crank in the change in
stock prices and dividends.So what investors receive is
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the stock price change and dividends.We're us ing growth
in the DCF model to say, looking forward, investors think
that their growth will be driven by earnings , which I
think is a reasonable expectation.
Don't investors in fact , realizing that no
investor intends to buy, or I would assume no reasonable
investor intends to buy a stock that's going to have a
negative growth rate unless there's an incredible return
in some other fashion; wouldn't you agree?
Unless you have a very high dividend
yield.And there's some stocks out there that have very
high dividend yields and investors know, very much like
they would buy a bond selling at the premium , knowing
that it will only be worth $1000 at its maturity, the
yield is so high that they're willing to make that
investment.
But most investors look at the total
return - - not most, all rational investors, Mr. Ward,
look at the total return they expect to get, price change
plus income.
But unfortunately, we are sometimes
disappointed, are we not?Not every stock you or I have
ever bought has been a winner.
Well , I can't speak for you , Mr. Ward , but
I am among the great number of investors who have
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suffered losses and that's why stocks are risky.
All right.Let's leave this for a moment.
I want to just ask a couple of questions about your
rebuttal testimony.If you'd pick that up.
Yes, sir.
On page 12, lines 12 through 14, you say;
thus Dr. Peseau' s update completely ignored the other
half of the constant growth DCF equation; namely the
growth rate.
That is correct.
Now , are you implying there that if , in
fact, the yield goes down, as it has to 4 percent , that
the growth rate must necessarily rise?
No.But growth rates like yields change
over time.So if you're going to update an analysis you
must do a complete update of both growth rates and
yields.
I did not check out all of the various
indicators you used, Doctor, but I did look at Value Line
and it appears to me that the growth rate is unchanged
for that proxy group.Would that surprise you?
I don't know.I haven't looked at it in
that regard.I have the Value Lines with me.
By the way, I think we ought to clarify
the record.The Exhibits 711 and 712 are actually from
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the February Value Line , which is the one that Dr. Peseau
used.And my testimony is based on the August Value
Lines.So when you put those in the exhibit there's a
mismatch in time.
The August, the earlier August Value Line
is what you used; correct?
Yes.That was what was available at the
time I did my testimony.
Okay.And as near as I can determine the
IBES growth forecasts have actually gone down.Are you
aware of that , since August of 2003?
For these particular companies?
Yes.
I have not made that inquiry.But...
So you don't know , despite your statement,
whether there's been any change in the growth rate that
requires some sort of adjustment to modify the dividend
yield that's currently in effect?
, I don'But I think my statement is
still correct.That if you're going to update an
analysis you ought to update the D over P , plus the
because they're both parts of the DCF model.Dr. Peseau
did not purport to do that.He didn't present any
evidence that he had done that.So I think my
observation in the rebuttal is correct.
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Now , on the next page, on 13, you say at
lines 3 through 5 , he, meaning Dr. Peseau, asserted that
historical growth rates should be disregarded because
excluded firms rated below investment grade for my
comparable group.Do you see that testimony?
Yes.
Was that really the primary critique of
primary basis for Dr. Peseau' s critique?Didn't he
essentially argue that there are too few data points to
be reliable.
Well, he argued that generally.But of
course, Dr. Peseau kind of puts me in the middle between
Ms. Carlock and himself because Ms. Carlock used one data
point , I used eight.So I think eight is sufficient.
But Dr. Peseau thinks there ought to be more.
And wasn't his other criticism that some
of the these proxies are not truly electric utilities?
Yes.He made that criticism.And I think
I respond to it in my rebuttal.
MR. WARD:That's all I have.
COMMISSIONER SMITH:Thank you, Mr. Ward.
Mr. Richardson.
MR. RICHARDSON:Thank you, Madame
Chairman.
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CROSS-EXAMINATION
BY MR. RI CHARDSON :
Dr. Avera, at page 4 line 4 of your direct
testimony you state that it's the purpose of your
testimony to present an independent evaluation of the
fair return on equity.When and you use the word
"independent" you don't mean to infer your testimony is
not being paid for today by Idaho Power , do you?
, sir.I mean I looked at it
independently of Idaho Power.m not an employee of
Idaho Power.So I based my estimates on my own judgment.
On page 7 and 1 ine 11 of your direct
testimony you state that , regulatory uncertainties along
with unfavorable capital market conditions compound the
investment risks for Idaho Power.
Aren't interest rates and inflation at
near historic lows right now?
Yes, sir, they are.But as I document in
my testimony the electric utility industry has been
particularly buffeted by negative events and is in the
minds of many investment services, such as Value Line, in
an area of increasing risk.I cite that Moody's has had
109 downgrades versus one upgrade of investment utility
bonds , or utility bonds.So I think the unfavorable
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capital market conditions are directly related to the
utili ty sector.
At the bottom of page 7 you state that
your rate of return range is necessary at this, quote,
critical juncture.What is particularly critical about
the juncture we're at?
Well , I think it is a period of time when
investors are looking hard at the industry.They are
easily spooked.One of the things that I've documented
in my testimony is investors are very mindful and
watchful of regulatory risk.Thi s company has not had a
rate case in many years.I think this is a critical
juncture in terms of investment reading
- -
investor
reading of regulatory risk.
I think it's also a critical juncture as
understand the Company is in a posture of having to make
substantial new capital investments.And may have to
make even more depending on how the relicensing of their
hydro facilities turns out.So I think the Company is at
a critical juncture in having to go to the capital
markets in significant quantities.
I think the Company is at a critical
juncture as to its credit rating.It has recently cut
its dividend.It has faced inquiries from the rating
agencies, the bond rating agencies.So it needs investor
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confidence if it's going to accomplish the financing that
will be required to add plant and maybe react to
circumstances that develop in the future.
On page 16 - - excuse me on page 15, you
reference what you called a shattered financial integrity
of California's retail utili ties.Do you believe that
Idaho Power s financial integrity has likewise been
shattered?
No.I think Idaho Power has weathered a
terrible period for the industry fairly well.Not
completely untouched.But I think investors , as they
look at this entire sector are aware of the significant
losses that investors in California utility bonds and
California utility equities have suffered.And I think
that is one of the reasons that investors are increasing
their sensi ti vi ty to the risk of this sector.
So Idaho Power is not, fortunately, in the
position of those California names but I think that
colors investors' risk perceptions.
On page 16, at lines 11 and 12 , you point
to California in general and single out Pacific Gas and
Electric as an extreme example of investors' sharp
increase in risk perception of electric utilities.
you also think that Idaho Power is an extreme example of
tha t phenomenon?
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No.I do not think that Idaho Power is an
extreme example.But I think PG&E was at on point the
largest utility in the country.Billions and billions of
dollars of investor value was lost in PG&E bonds and
securities.So I think the effect of California is being
fel t by Idaho Power.Not because it's in the same
situation , but it's in the same industry, and is being
affected by some of the same dynamics.
Referencing Mr. Ward's Exhibit No. 713
looking at that line number 4 , the PNM Resources Group?
Yes.
Do you know whether or not that utility,
that entity, was very active in the wholesale energy
trading markets that were characterized by utilities
creating subsidiaries for the purpose of capturing the
incredibly high-priced wholesale prices of the energy
recent energy crisis?
They were active in the energy market.
They did a lot of other things.PNM was a utility that
was talking about di versi ty and changing the landscape of
the industry back in the early ' 80s when the California
deregulation was a dream in someone I s head.
So PNM , I don't think the story is purely
one of energy trading.I think that they ventured into
many things , most of which turned out poorly.
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You would agree that utilities that were
acti ve in the energy trading during the energy crisis
actually made a lot of money during that time?
I would be careful in my
- -
some made
money during some periods, some made money during other
periods.I don't think any made money during all
periods.
Thank you, Dr. Avera.
MR. RICHARDSON:Madame Chairman , that'
all I have.
COMMISSIONER SMITH:Thank you , Mr.
Richardson.
Mr. Budge, do you have questions?
MR. BUDGE:No questions.
COMMISSIONER SMITH:Ms. Nordstrom.
MS. NORDSTROM:Thank you.
CROSS -EXAMINATION
BY MS. NORDSTROM:
Good morning.
Good morning,Ms.Nordstrom.
Let'start wi th your direct testimony.
On page you state that approximately 55.million of
the power supply costs were not recovered through the PCA
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over the past three years.
Since this percentage is relatively small
in comparison to the 538 million dollars that was
recovered.One could argue that Idaho Power shareholders
were protected for the vast maj ori ty of the high market
prices.Isn't this significantly better and less risky
than if no PCA were in place?
It's better than no PCA but it's certainly
worse than most utilities who collected a hundred percent
of their power costs.So I think you have to measure it
against the other utilities.Thi s why I di sagree wi th
Ms. Carlock's characterization that this causes Idaho
Power to be less risky relative to other utilities.
think it causes Idaho Power to be less risky relative to
not having the PCA , but a PCA with a 90 percent return is
more risky than another mechanism that gives you 100
percent recovery of your power costs.55 million dollars
to me, is not shabby.It's a significant amount of
money.
I didn't mean to imply that it was.Are
you aware of any western electric utility with a large
percentage of hydro generation that has 100 percent PCA
recovery?
I think Avista , for example, has an
opportunity to recover 100 percent in Washington.They
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have to prove the prudency of their expenditures, but my
understanding of the recent actions by the Washington
Commission is that it at least gave Avista an opportunity
to prove that their expenditures were prudent and should
be collected.
Isn't it ture, though , that there's a band
where there isn t that recovery?
I think there is a dead band but my
understanding, and I hadn't reviewed - - I've been
invol ved in a number of Avista Washington cases including
the one about energy recovery - - but my understanding is
that Avista has the opportunity to petition the
commission for further recovery even beyond the band.
The primary mechanism itself, though, is
based on 90 percent recovery; isn't that true?
In Washington I think they have a similar
PCA in Idaho to what Idaho Power has.But I believe
there has have been some adjustments in the Washington
PCA.And I'told you about what know.
have a survey that was done in 2001
by Regulatory Research Associates of all the states.And
the result of that survey is very few utilities are
exposed to not recovering their purchase power costs.
But most of those aren't hydro generation?
That is correct.And really, the low cost
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of hydro makes recovery even more important because the
first step out of hydro is a big one.I mean, what
happens to Idaho Power is that if they're short of hydro
power they're going from a very cheap source of power and
replacing it with an expensive source of power.
Let's compare that to the Public Service
of New Mexico, which is an exhibit in Dr. Peseau'
testimony.Public Service of New Mexico is primarily
coal.And they have only one percent oil and gas.So if
they have to go outside their normal source of power
they're going from kind of a mid-range cost of power to
other al ternati ves which in their part of the world are
mid-range.Idaho Power goes from a very low cost of
power to higher cost of power in a power market , the
western power market , that is experiencing extreme
variations of price.
So I think the exposure here is very, very
significant.The low cost of hydro power is a two-edged
sword.
Well , you mentioned Avista in Washington.
But isn't it true that Avista in Idaho and other western
utili ties , I believe Sierra Pacific , for example, have a
90 percent sharing for their PCA; isn't that true?
I think as to Idaho.But I think you'
question was to other western states dependent upon hydro
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power.So I think in different jurisdictions they have
different sharing mechanisms.
But the predominant sharing mechanism
nationally is 100 percent recovery.
On page 13 you discuss changes to the
Public Utility Holding Company Act, and to a limited
extent the Federal Power Act, greatly increased the
prospective competition for the production and sale of
power at the wholesale level and therefore increased
risk.
Isn't this flexibility exactly what many
utilities lobby to obtain?
Yes, because as I was - - Mr. Richardson
was it -- in our previous discussions, many utilities
were able to make money off of the power market.But
again, I think experience has shown that one thing that
happens in competition is volatility.Prices go up and
they go down.And I think what the risk element that
this competition has created is it's very hard to know
what the wholesale price will be because it has proved to
be very volatile, particularly in the West.
On page 16 of your direct testimony there
at the bottom , you discuss numerous downgrades in
electric -- in the electric power industry in 2002.
Isn't it true that the majority of these
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downgrades were companies involved in nonregulated,
nontraditional operations?
I don't think so because I think the
number of traditional utilities predominates the
population.So I don't know for a fact , Ms. Nordstrom,
but I would have a hard time speculating that a majority
were driven by non-utility actions.
On page 14 of your testimony, lines 17
through 19 , you confirm that Idaho Power is and is
expected to remain , a fully integrated public utility.
Hasn't IDACORP even reduced its risk exposure
with the elimination of IDACORP Energy?
I understand that IDACORP Energy is being
wound down.And I think given the circumstances that
probably has an effect on IDACORP.m not sure it has
an effect on Idaho Power because I think Idaho Power has
its own bond rating and its own risk profile.That's one
of the problems that I disagree with Ms. Carlock'
approach of using IDACORP as the benchmark for Idaho
Power's cost of equity.
Isn't Idaho Power's PCA and past
Commission decisions allowing purchase power recovery one
reason why Idaho Power's credit rating continues to be
better than most neighboring utilities?
Well , I think that's one contributing
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factor.I think that had the Commission taken a
different course and not enacted the PCA given the
extremes of water conditions that had been experienced
the last several years , I think Idaho Power would
probably be in a world of hurt.But I think that's not
the sole reason the bond rating is what it is.I think
the capital structure, the other characteristics of the
Company have a lot to do with the bonds rating.But I
think clearly, but for the PCA , the Company would be in a
worse condition.But I don't think you can go from that
to say, therefore Idaho Power has significantly less risk
than other utilities.I think that is an unjustified
leap.
On page 25 you discuss the risk of
potential market volatility.Do you consider this risk
greater than the risk of recovering plant investment and
rate base if a system were overbuilt to assure that no
market purchases were required?
It's really hard to compare those two
because I think you have to look at the circumstances.
Certainly there have been utilities who have been found
with excess capacity through imprudent action and there
have been disallowances for those utili ties.But I think
in many cases the imprudence was not so much building the
capacity but the way it was built.For example , the
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nuclear plants.So I think there is a certain risk that
goes with a utility-building capacity but I think , in the
current circumstances, a utility that gets a significant
amount of their capacity on the open market, given the
recent volatility of the open market, in the minds of
investors, that's a bad thing.And I think investors are
comforted when they see utilities such as Idaho Power or
Sierra Pacific investing in their own generating
resources.And even more than investors, I think
customers are well- served by insulating, by having more
certainty in future prices that comes with the utility
controlled and owned generation.
On page 27 at the very bottom you
reference AA public utility bond yields of 6.9 percent in
2002.Isn't it true that Idaho Power just completed a
long-term debt issuance at a rate of 5.5 percent?
Yes.I understand from Mr. Gribble that
that occurred and it was a wonderful result to lock those
rates in for the future.
Let's turn to your rebuttal.You
criticize Ms. Carlock's analysis for utilizing Idaho
Power and IDACORP data for her DCF analysis.I sn 't it
possible that Ms. Carlock also utilized utility
comparisons to validate the appropriateness of using
Idaho Power , IDACORP' S specifics?
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Well , I think she did.And reading her
testimony she looked at the growth rates and yields for
the Moody's composite.But I think that is not as useful
as actually doing a DCF on a different utility but
related and comparable.So I recognize that Ms. Carlock
looked at industry data.But it was still used in the
context of a DCF on a single company.And I don't think
that is as reliable as doing DCFs on other companies
because it is , you re trying to estimate an unobservable
and there's a lot of chance of error creeping into your
observation.So I think there is some comfort in
sampling and having a larger sample.Although I don'
think you need as huge a sample as Dr. Peseau does.
Is it true that Ms. Carlock used current
and forward-looking data in her DCF calculations?
Yes , she did.
On page 5 of your rebuttal testimony,
lines 20 through 23, you testified that while, quote
while Ms. Carlock stated that , quote, much of the
theoretical approach , end quote, that she used was
consistent with my testimony, Ms. Carlock did not use the
risk premium approach to estimate the cost of equity, end
quote.
Yes.
Do you believe that every approach must be
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utilized for much of the theoretical approach to be
consistent?
No.I mean, I believe that the DCF was
similar and I think it had the same approach.We did
make reference to the comparable earnings.But I did
feel it important to point out that the risk premium was
not considered.And I believe in the last rate case Ms.
Carlock did have some risk premium information.So I'
not criticizing what she did, I'm trying to point out
what was missing.
Isn't it true that cost of capital
witnesses and commissions do not always accept every
method to evaluate the cost of equity?
Yes , Ms. Nordstrom , that's the heartbreak
of being a cost-of-capital witness.
On pages 9 and 10 you discuss flotation
costs.In your direct testimony on page 65 you
acknowledge that there isn't a precise method to
recognize flotation costs.
Isn't it possible that Ms. Carlock
evaluated the need for flotation costs when she examined
the dividend yield used in the DCF calculation?
It is possible.But I did not see
explicitly in her testimony any consideration of
flotation costs.And I think in this circumstance, since
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we are looking at a company that may have to make
significant capital investments , that flotation cost is a
relevant consideration.
Thank you.
MS. NORDSTROM:I have no further
questions.
COMMISSIONER SMITH:Do we have some
questions from the Commissioners?
I just had a couple.
EXAMINATION
BY COMMISSIONER SMITH:
When you spoke of Avista having the
opportunity to recover 100 percent of its purchase power
costs in Washington , when were these costs incurred?Was
that 2002 , 2001?
Well , I believe there was a case
particularly about those deferrals and I believe the
outcome was some were ruled to be imprudent.But I think
, there was also a more recent case where my understanding
was that the Company had an opportunity to defer future
costs.And there was a mechanism set up where they could
go to the Washington commission and try to get recovery.
There was not
- -
it was a deferred approach and it was
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kind of an opportunity, not a guarantee.
All right.So Avista didn't get 100
percent of their costs?
Not for the energy crisis period.The re
was a write-off.
Okay.When you talk about predominant
number of utilities that get 100 percent recovery for
their purchase power costs, do you mean only electric
companies?
I was meaning that in terms of electric
companies based on the RRA survey which was of the
electric recovery.
Okay.All right.Thank you.
COMMISSIONER SMITH:That's all I have.
Commissioner Hansen.
COMMISSIONER HANSEN:I think I do just
have one question.
EXAMINATION
BY COMMISSIONER HANSEN:
This is concerning the Washington
commission.But with Avista could they also -- you say
they could maybe justify and get the 100 percent, could
they also wind up with less than the 90 percent?
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They certainly could, Commissioner Hansen.
I think it is an opportunity to make their case.And the
commission , in its wisdom will evaluate whether those
costs 100 percent, 90 percent , 79 percent , should be
recovered.
I think the difference in what is
available here, as I understand the Idaho system, is that
the 10 percent is kind of off the table.
Are you saying that you feel that it'
less risky that a utility company could get less than say
90 percent , 70 percent , or whatever; or they may be able
to recover 100 percent.But there's a wide range of
recovery.You re saying that I s less risky than in this
case where it's 90 percent set?
, Commissioner Hansen.I think that
particular aspect may be more risky.But I think the
notion that the PCA puts Idaho Power in a whole new
category of lower risk is inaccurate because I think that
Idaho Power's recovery mechanism has some risk.The 1
percent is pretty clearly a risk and it has had a $55
million bite in the last three years.
So all of these mechanisms have some risk.
And I would have to think about whether Avista Washington
versus Idaho Power Idaho, I don't know how investors
would view those vis-vis each other.But I think Idaho
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Power is not, as I believe Ms. Carlock may have
suggested, in a situation of being kind of by itself in a
low risk category.I think it is in the hunt as far as
where other electric utilities are.
In fact , most electric utilities as the
RRA survey revealed, get 100 percent recovery.Most kind
of more or less automatically every three months or six
months there's a revision in the fuel factor.So I think
in terms of the relative positioning of Idaho Power
Idaho Power is better off than if it didn't have any PCA
but it's not in the eyes of investors, as well off as
those utilities that have 100 percent, more or less,
contemporaneous pass-through.
Now , relative to Avista Washington,
think investors would have to make an assessment of how
they think the Washington commission is going to
implement their judgment.And that's where the
regulatory risk comes in , and I think it would depend on
the investors perception of the risk of the regulatory
environment in Washington.
But in your opinion you re not
recommending one , Washington's better than Idaho or Idaho
Power s better off with the 10 percent, you're not
picking ,one or the other?
, sir.I hope I didn't suggest that.
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But what I am suggesting is that Idaho Power is not out
here in the extreme low-risk category.It's somewhere
with the other utilities that have various elements of
recovery risk.And then there's the group of utilities
that has very little recovery risk.
I think it's important to note, for
example, in the PNM Value Line sheet that Dr. Peseau has
attached to his testimony, the sheet says, New Mexico or
Public Service New Mexico does not have a fuel adjustment
mechanism.Most otherThat's news because it's rare.
utilities they don't even talk about it because the norm
is some recovery mechanism.
COMMISSIONER SMITH:Okay.Dr. Avera , I
guess you've said so many times most utilities collect
100 percent of the purchase power cost.Do you have a
list of them?Is there somewhere I could get your list
from you showing that most got 100 percent?
THE WITNESS:I would very much recommend
to the Commission looking at this RRA study.
COMMISSIONER SMITH:We don't have it.
THE WITNESS:I don't know if we can put
it in the record.I think it should be.
MR. KLINE:Sure.
COMMISSIONER SMITH:It may be
copyrighted.You have to buy it.
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Anyway, that's something for you to think
about.And, Mr. Kline.
MR. KLINE:Would you like us to make that
available to the Commission in a supplemental filing?
COMMISSIONER SMITH:I think so, yeah.
MR. KLINE:Okay.
COMMISSIONER SMITH:Do you have redirect
Mr. Kline?
MR. KLINE:I have one question for sure.
COMMISSIONER SMITH:All right.
REDIRECT EXAMINATION
BY MR. KLINE:
Dr. Avera, in response to a question from
Mr. Richardson you discussed Idaho Power Company's need
for a strong credit rating.The Company currently has an
A rating; isn't that correct?
Well , a low an A- or an A3 by the two
maj or rating agencies.
, for whatever reason the Company were
to have that rating reduced or there'd be a risk that
that rating would be reduced , is there a particular risk
in the case of Idaho Power because of its small size and
limited coverage by financial analysts?
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Yes.Idaho Power is a relatively small
utility.I think in thatIt doesn't get much attention.
circumstance a rating by the rating agencies that are
given great attention by the investment community,
probably has more relative importance because there are
not a lot of analysts following Idaho Power.I think
there's just several local firms that have equity
analysts following Idaho Power.I think investors tend
to look at Moody , and Standard and Poor s, who do have
direct contact, and interview the Company, and look at
the financials very carefully, that they accord the bond
rating particular attention which would be more, in its
relative importance , than a company like PG&E or Dominion
that's followed by many equity analysts that has somebody
talking about it on CNBC every other day.
Just one second.
MR. KLINE:That's all the questions we
have.
COMMISSIONER SMITH:Thank you
very much.
Thank you , Dr. Avera.
(The witness left the stand.
COMMISSIONER SMITH:And let's go
to lunch.You want to come back at 1: 15?
(Noon recess.
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