20090108Vol VIII [technical hearing] pgs 1621-2052.pdf

ORIGINAL.BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS
RATES AND CHARGES FOR ELECTRIC
SERVICE TO ELECTRIC CUSTOMERS IN
THE STATE OF IDAHO.
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Idaho Public Utilties Commission
Office of the SecretaryRECEIVED
NO. IPC-E-08-10
JAN - 8 2009
Boise, Idao
BEFORE
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER JIM D. KEMPTON.
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:December 18, 2008
VOLUME VIII - Pages 1621 - 2052
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CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone] * [phone]
Email csb~heritagewifi.com
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1 APPEARANCES
2 For the Staff:
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5 For Idaho Power Company:
Donald Howell, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83720-0074
Barton L. Kline, Esq.
and Lisa D. Nordstrom, Esq.
and Donovan E. Walker, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
RICHARDSON & 0' LEARY
by Peter J. Richardson, Esq.
Post Office Box 7218
Boise, Idaho 83702
RACINE, OLSEN, NYE, BUDGE
& BAILEY
by Eric L. Olsen, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
Arthur Perry Bruder, Esq.
Assistant General Counsel
U. S. Department of Energy
1000 Independence Ave., SW
Washington, DC 20585
GIVENS PURSLEY LLP
by Conley E. Ward, Esq.
Post Office Box 2720
Boise, Idaho 83701-2720
BOEHM, KURTZ & LOWRY
by Kurt J. Boehm, Esq.
36 E. Seventh Street
Suite 1510
Cincinnati, Ohio 45202
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FISHER PUSCH & ALDERMAN LLPby John R. Hamond, Jr., Esq.
Post Office Box 1308
Boise, Idaho 83701
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For Industrial Customers
of Idaho Power:
For Idaho Irrigation
Pumpers Association:
For The United States
Department of Energy:
For Micron TeGhnology,
Inc. :
For The Kroger Company:
CSB REPORTING
[phone]
APPEARANCES
1 APPEARANCES (Continued).2
3 For the Community Action Brad M.Purdy, Esq.
Partnership of Idaho:Attorney at Law
4 2019 North 17th Street
Boise,Idaho 83702
5 For Snake River Alliance:Mr.Ken Miller
6 5400 West Franklin
Boise,Idaho 83705
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CSB REPORTING APPEARANCES
(208 )890-5198
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1 EXHIBITS
PAGE
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Identified 1772
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3 NUMBER DESCRIPTION
4 FOR I DAHO POWER COMPANY:
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16 - Resume of William E. Avera
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17 - Constant Growth DCF Model, Utility
Proxy Group
8 18 - Sustainable Growth, Utility
Proxy Group
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19 - Constant Growth DCF Model,
Non-Utili ty Proxy Group
11 20 - Sustainable Growth,
Non-Utili ty Proxy Group
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21 - Forward-Looking CAPM, Utility
Proxy Group
14 22 - Forward-Looking CAPM, Non-Utility
Proxy Group
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23 - Historical CAPM, Utility
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24 - Historical CAPM, Non-Utility
Proxy Group
18 25 - Expected Earnings Approach,
Utili ty Proxy Group
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26 - Capital Structure, Utility
Proxy Group
81 - Recent Dividend Yield, Kahal
Proxy Groups
82 - Revised DCF Summary, Kahal
Proxy Groups
88 - S&P, Issuer Ranking: U.S.
Regulated Electric Utilities,
Strongest to Weakest
CSB REPORTING
Wilder, Idaho 83676
EXHIBITS
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1 E X H I BIT S (Continued)
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3 NUMBER DESCRIPTION PAGE
Identified 1762
7 FOR COMMUNITY ACTION PARTNERSHIP ASSOCIATION OF IDAHO:
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8 Identified 1626
CSB REPORTING
Wilder, Idaho 83676
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4 FOR THE STAFF~
5 156 - The Value Line Investment Survey
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501 - CAPAI Response to Idaho Power
Company's First & Second
Production Requests
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11 FOR MI CRON TECHNOLOGY, INC.:
12 701 - Statement of Occupational &
Educational History &
Qualifications Dennis E. Peseau13
14 702 - Review of Utility Ratemaking
Procedures
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703 - Report to the 74th Session of the
Nevada Legislature
17 704 - Request & Response to Request
No. 23
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705 - O&M Expenses Adjusted by Compound
Growth Rates
706 - Annualizing Plant Adjustment
707 - 3CP /12CP Class Cost of Service
Study
EXHIBITS
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1 BOISE, IDAHO, THURSDAY, DECEMBER 18, 2008, 9:00 A. M.
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4 COMMISSIONER SMITH: Good morning.
5 Welcome to the continuing hearing. I see we have a new
6 face in the chairs. Mr. Hammond, would you like to make
7 an appearance?
8 MR. HAMMOND: Thank you, Chairman Smith.
9 My name is John Hammond. I'm with Fisher Pusch &
10 Alderman appearing today as local counsel for Kroger.
11 Mr. Boehm is here. Kurt Boehm is the attorney for Kroger
12 and we filed a motion for limited admission pro hac vice
13 that I think you have. It was filed yesterday.
14 COMMISSIONER SMITH: Yes, I do have a copy
15 of that and the motion will be granted. It's my
16 understanding, Mr. Hammond, that you would like to be
17 excused.
18 MR. HAMMOND: Actually, today would be
19 great because I have another hearing that's been
20 scheduled and I have to run to that. If it's not a
21 problem, yes, at least for today.
22
23 can get Mr. Boehm's --
COMMISSIONER SMITH: Okay, as long as I
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MR. BOEHM: Boehm, Your Honor.
COMMISSIONER SMITH: Boehm, B-o-e-h-m.
CSB REPORTING
[phone]
1621 COLLOQUY
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1 MR. BOEHM: Yes.
2 MR. HAMMOND: And Mr. Boehm has one thing
3 he'd like to address about witnesses just to ask you or
4 offer, if that's okay.
5 COMMISSIONER SMITH: Okay. Mr. Hammond,
6 you may be excused. Mr. Boehm, welcome to the hearing.
7 MR. BOEHM: Thank you, Chairman Smith.
8 COMMISSIONER SMITH: If you haven't
9 already been informed, we have these little mics where
10 you touch and the red light comes on and when you're done
11 talking, you touch and the red light goes off.
12 . MR. BOEHM: Very good. I requested
13 previously that our witness Kevin Higgins be allowed to
14 appear tomorrow. He could be available today by phone if
15 that would be easier for everyone, if that would be more
16 convenient.
COMMISSIONER SMITH: Would he be available
18 in person tomorrow?
19 MR. BOEHM: Yes. Yes, his flight from
20 Salt Lake leaves at 3:00 o'clock today.
21 COMMISSIONER SMITH: He hopes. Isn't that
22 when it's supposed to start snowing? I think that we may
23 have a full day today. We'll see how it goes and we'll
24 be here tomorrow, so having him here tomorrow will work..25 MR. BOEHM: Thank you.
CSB REPORTING
[phone]
1622 COLLOQUY
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1 MR. KLINE: Madam Chair, one other
2 scheduling matter, if I could.
3 COMMISSIONER SMITH: Mr. Kline.
4 MR. KLINE: Dr. Avera called this morning.
5 He is unable to get to Boise either today or tomorrow.
6 His flight was canceled yesterday. He's in Austin.
7 Christmas vacation is starting there, all the students
8 are exiting, so there are no seats to get to Boise and
9 what we'd offer to do is have him testify by phone. That
10 gi ves us some flexibility as to when he testifies then.
11 COMMISSIONER SMITH: It could be an
12 interesting economics exercise for him to go to the
13 airport and find out just what one of those tickets is
14 worth. Just thinking out loud. All right, I believe
15 today we were beginning with Ms. Ottens.
16 MR. PURDY: Yes, we are, Madam Chair.
17 Thank you. Communi ty Action Partnership Association of
18 Idaho calls Teri Ottens.
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CSB REPORTING
[phone]
1623 COLLOQUY
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TERI OTTENS,
produced as a witness at the instance of the Community
3 Action Partnership Association of Idaho, having been
4 first duly sworn, was examined and testified as follows:
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8 BY MR. PURDY:
9 Q
DIRECT EXAMINATION
10 name and spell your last name?
Ms. Ottens, would you please state your
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11 A Teri Ottens, O-t-t-e-n-s.
By whom are you employed and in what
I'm employed in energy issues with the
15 Communi ty Action Partnership Association of Idaho.
12 Q
Thank you. Have you previously prefiled
17 revised direct testimony in this case on November 28th?
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13 capacity?
I have.
Consisting of 10 pages; is that right?
That's correct.
And you don't have any exhibits as of this
22 point to your testimony, do you?
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14 A
I do not.
MR. PURDY: Madam Chair, with the Chair's
indulgence, I would just like to clarify a couple of
CSB REPORTING
[phone]
16 Q
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1624 OTTENS (Di)
CAPAI
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1 matters.
2 COMMISSIONER SMITH: Certainly.
3 MR. PURDY: Ms. Ottens, is there anything
4 regarding your testimony that you would like to clarify
5 for us?
6 A A couple of things. On page 3, line 10,
7 page 4, line 23, I refer to the rate increase, the
8 overall rate increase, at 15 percent. I was not
9 referring to the residential rate increase as correctly
10 pointed out by Idaho Power's testimony. If we're talking
11 low income customers, it might be more appropriate to
12 refer to the actual residential rate increase of six
13 percent.
14 Q Thank you. Anything else?
15 A There was some clarification on page 5
16 where I refer to the tiered rates. We made a suggestion
17 that 600 seemed to be a bit low. We did not make a
18 suggestion on. what we thought it should be and in our
19 rebuttal testimony we did say 850.
20 Q Well, you got done saying earlier,
21 testifying that you did not file rebuttal; is that
22 correct?
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A I'm sorry, our discovery testimony.
Q Thank you.
A Or discovery answers.
CSB REPORTING'
[phone]
1625 OTTENS (Di)
CAPAI
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1 MR. PURDY: Thank you. Madam Chair, I
2 promise this won't take long. May I approach the
3 witness?
4 COMMISSIONER SMITH: Certainly.
5 (Mr. Purdy approached the witness.)
6 MR. PURDY: Ms. Ottens, I've just handed
7 you what I would ask be marked as Exhibit 501 and I have
8 not provided copies to the other parties because they
9 have already been served. If anyone wishes to have a
10 copy of this document, I will provide it.
11 (Community Action Partnership Association
12 of Idaho Exhibit No. 501 was marked for identification.)
13 Q BY MR. PURDY: Ms. Ottens, would you
14 please just briefly identify what Exhibit 501 is?
15 A This is my Response to Idaho Power
16 Company's First and Second Production Requests.
17 Q All right, and would you please read out
18 loud Request No. 1 and your response thereto?
19 A "In response to the Company's proposal to
20 set the first tier of energy consumption at 600 kWh, Ms.
21 Ottens states:'If the purpose of the tier was to
22 promote conservation, it should be set at a higher level
23 so as to be attainable.' At what level does Ms. Ottens
24 propose the first tier be set?".25 The response, "In the testimony of Idaho
CSB REPORTING
[phone]
1626 OTTENS (Di)
CAPAI
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1 Power witness Ms. Courtney Waites, she states that the
2 average monthly residential customer energy usage is 1065
3 kWh. If this is the average consumption, there is very
4 li ttle chance for an average household to reduce its
5 energy usage, no matter what energy efficiency measures
6 it might undertake, to come in at or below the first tier
7 block of 600 kWh. CAPAI believes that if this is meant
8 to be an incentive, it should be an achievable level.
9 CAPAI further asserts that reducing average consumption
10 by 40 percent to derive a first tier is not a reachable
11 goal, however~ cutting usage by 20 percent might be.
12 Thus, CAPAI, through witness Ottens, recommends that the
13 first tier be set at 850."
14 Q Kilowatt-hours?
15 A Kilowatt-hours, sorry.
16 MR. PURDY: Thank you. All right, with
17 that clarification, Madam Chair, I ask that the direct
18 testimony of Teri Ottens be spread upon the record as if
19 read and that Exhibit 501 be identified.
20 COMMISSIONER SMITH: If there is no obj ection,
21 it is so ordered.
22 (The following prefiled direct testimony
23 of Ms. Teri Ottens is spread upon the record.)
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CSB REPORTING
[phone]
1627 OTTENS (Di)
CAPAI
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1 I. INTRODUCTION
2 Q:Please state your name and business address.
3 A:My name is Teri Ottens. I am the Policy
4 Director of the Community Action Partnership Association
5 of Idaho headquartered at 5400 W. Franklin, Suite G,
6 Boise, Idaho, 83705.
7 Q:On whose behalf are you testifying in this
8 proceeding?
9 A:The. Community Action Partnership Association of
10 Idaho ("CAPAI") Board of Directors asked me to present
11 the views of an expert on, and advocate for, low income
12 customers of IDAHO POWER. CAPAI i S participation in this
13 proceeding reflects our organization's view that low
14 income people are an important part of Idaho Power IS
15 customer base, and that these customers will be adversely
16 impacted by the proposed changes to the Company's
17 electric service schedules.
18 Q:Please describe CAPAI' s organization and the
19 functions it performs, relevant to its involvement in
20 this case.
21 A:CAPAI is an association of Idaho's six
22 Communi ty Action Partnerships, the Community Council of
23 Idaho and the Canyon County Organization on Aging,
24 Weatherization and Human Services, all dedicated to.25 promoting self-sufficiency through removing the causes
1628 OTTENS (Di) 2
CAPAI
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1 and conditions of poverty in Idaho's communi ties.
2 Q:What are the Community Action Partnerships?
3 A:Communi ty Action Partnerships ("CAPs") are
4 private, nonprofit organizations that fight poverty.
5 Each CAP has a designated service area. Combining all
6 CAPS, every county in Idaho is served. CAPS design their
7 various programs to meet the unique needs of communi ties
8 located wi thin their respective service areas. Not every
9 CAP provides all of the following services, but all work
10 with people to promote and support increased
11 self-sufficiepcy. Programs provided by CAPS include:
12 employment preparation and dispatch, education assistance
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child care, emergency food, senior independence and
support,
1629 OTTENS (Di) 2a
CAPAI
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1 clothing, home weatherization, energy assistance,
2 affordable housing, health care access, and much more.
3 Q:Have you testified before this Commission in
4 other proceedings?
5 A:Yes, I have testified on behalf of CAPAI in
6 numerous cases involving PacifiCorp, Idaho Power Company,
7 AVISTA, and United Water.
8 II. SUMY
9 Q:Please summarize your testimony in this case?
10 A:First, CAPAI is concerned that there are a
11 considerable number of customers sitting on the margin of
12 becoming low-income, or at the margin of being able to
13 even pay their utility bills. A rate increase of 6%,
14 especially those who rely on electric space heating,
15 could prove devastating. Along these lines, CAPAI
16 proposes an adj ustment to Idaho Power's proposed first
17 tier block rate for residential customers.
18 Second, CAPAI proposes an increase in funding
19 to Idaho Power's low-income weatherization program.
20 Third, CAPAI proposes that Idaho Power
21 implement an energy efficiency education program to
22 low-income customers as described herein.
23 Fourth, CAPAI recommends that Idaho Power
24 provide monthly arrearage reports..25 III. RECOMMNDATIONS
1630 OTTENS (Di) 3
CAPAI
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1 Q:Why has CAPAI intervened in this particular
2 proceeding?
3 A:CAPAI is concerned that the combined proposed
4 increases in fees and rates will add to the already
5 unwieldy energy cost burden that low income families in
6 Idaho face, particularly in these uncertain economic
7 times.This is of significant importance to low-income
8 Idaho customers and those who must provide services to
9 them.
10 Q:Can you provide poverty statistics for Idaho?
/
1631 OTTENS (Di) 3a
CAPAI
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1 A:According to the Idaho Department of Commerce,
2 12.6% of the State's population, when using the 2006
3 Census data, falls within federal poverty guidelines and
4 an additional 12.4% fall wi thin the state guidelines set
5 at 150% of poverty levels. The 2006 Census reveals that
6 those living in poverty are categorized as 8. 7% elderly,
7 15.1% children, 9.8% all other families, 28.5% single
8 mothers and 26.4% all others.
9 Q:How does this translate to energy
10 "affordability?"
11 A:According to the U. S. Department of Energy, the
12 "affordability burden" for total home energy is set
13 nationwide at 6% of gross household income and the burden
14 for home heating is set at 2% of gross household income.
15 In Idaho, there was a gap in the 2006/2007 heating season
16 of over $123 million between what Idahoans can afford to
1 7 pay (based on federal standards) for energy and what they
18 actually paid. While this gap increased by $26.7 million
19 from the previous year, the LIHEAP funding only increased
20 by $1.8 milli9n.Currently, the LIHEAP program sends
21 approximately $12.2 million (for energy assistance,
22 weatherization and administration) to Idaho.
23 Q:How do these increases proposed by Idaho Power
24 directly impact its low-income customers?
25 A.Due to Idaho Power's lack of low income data
1632 OTTENS (Di) 4
CAPAI
.1 tracking CAPAI cannot precisely answer this question.
2 However we believe that this rate increase, coming on top
3 of past recent increases and the recent cost of living
4 increases in food and fuel will have a significant impact
5 upon our customers. Already, without this increase, the
6 CAP's serving Idaho Power's terri tory have seen an
7 approximate 25% increase in calls for assistance and many
8 of these are from "new" clients, or those never seen
9 before asking for assistance. The additional burden
10 caused by an over 6% increase in utility rates will only
11 increase the needs of those in poverty or on the edge.
12 Q.What does CAPAI feel could assist this customer
13 base?.14
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24.25
1633 OTTENS (Di) 4a
CAPAI
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1 A:CAPAI is most concerned about the level of
2 the rate increase proposed by Idaho Power and the
3 proposed tier structure for the residential class. The
4 proposed rate increase of over 6% will present a
5 deepening burden on low income families and cause a rate
6 shock for even those living on the margin of poverty. We
7 know that low income customers have a higher energy
8 burden and that they are the group of customers most
9 likely to be disconnected due to non-payment,
10 particularly after the winter months when their burden is
11 highest, and that the impact of increased fees will be
12 significant upon this customer group.
13 We also have concerns about the proposed tier
14 levels. By Idaho Power's own testimony an average
15 monthly residential customer's energy use is 1,065 kWh
16 (in 2007). AGcording to Company witness Courtney Waites,
17 the U. S. Departments of Housing and Urban Development
18 estimates that the "baseline" level of electricity usage
19 (only lighting and basic, home applicances) nationwide
20 ranges from 700-850 kWh per month, not including space
21 heating or air conditioning. Witness Waites believes
22 that even this is too low and estimates, by relying upon
23 average spring and fall usage, a baseline load for Idaho
24 Power's customers is 806-838 kWh/mo. Testimony of
25 Courtney Waites, pp. 10-11. As a result, witness Waites
1634 OTTENS (Di) 5
CAPAI
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1 proposes increasing the existing first tier from 300 to
2 600 kWh. While CAPAI commends Idaho Power for
3 recognizing the disparity between actual baseline usage,
4 not even including heating or air conditioning, and the
5 amount included in the tier, a movement to only 60% of
6 actual baseline load is not adequate to recognize those
7 whose usage of electricity is at a bare minimum and fails
8 to send the proper incentive to those who are slightly
9 above baseline usage to reduce their consumption to fall
10 entirely or almost entirely within the cheaper first
11 tier, thereby. which would promote energy conservation.
12
1635 OTTENS (Di) 5a
CAPAI
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1 Instead, the Company proposes a rate tier at
2 600 kWh which indicates that no matter how much one
3 conserves, they will not likely come in under this tier,
4 particularly if they rely upon electric heat and/or air
5 condi tioning. If the purpose of the tier was to promote
6 conservation, it should be set at a higher level so as to
7 be attainable. In addition, while the Census does not
8 correlate age' of housing with income of tenants, through
9 the CAP's extensive statewide experience, we find that
10 low income families are most likely to be located in
11 housing that is aging because this housing is the least
12 expensi ve to rent or buy. Aging housing equates with
13 less energy efficient construction and in some cases, no
14 energy efficiency measures at all. While a low income
15 family might be interested in conservation measures and,
16 in fact, may even be trying to implement such measures,
17 the likelihood of success without extensive resources is
18 small. The conclusion is that these families will, in
19 most cases, be unable to stay under the tier level
20 proposed by the Company to avail themselves of the best
21 rates.If the level is set at an unreasonably low level
22 then low income families generally will not benefit from
23 this proposal.
24 One of the programs that help low income
25 customers to reduce their utility bill is Idaho Power's
1636 OTTENS (Di) 6
CAPAI
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1 highly successful weatherization program. This program
2 allows the CAP's to provide energy efficiency measures to
3 a home, not only reducing the electric bill but providing
4 a long term solution by continuing to reduce electric
5 costs in the future.We believe that increasing this
6 program funding to allow for weatherization of more low
7 income homes would be highly desirable (currently only
8 10% of the homes receiving a LIHEAP benefit are
9 weatherized). Since the last major increase implemented
10 by Idaho Power in 2004, with a few exceptions, the funds
11 currently being offered by Idaho Power have been
12 exhausted by our agencies. In the agencies where they
13 have not been exhausted there have been extenuating
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25
circumstances. These have included:
1637 OTTENS (Di) 6a
CAPAI
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1 1) In the first year of the program, agencies
2 had to ramp up their staff and application process to
3 meet the new revenue levels. This took some agencies
4 more time than other to get up to speed.
5 2) Because other funding resources are time
6 specific (in that they must be spent in specific time
7 periods) and the Idaho Power funding is more flexible,
8 agencies have purposely and strategically carried over
9 funds from one year to another to make up for anticipated
10 funding gaps. This has enabled them to keep crews
11 working year round.
12 However, with an anticipated increase in
13 federal funding, CAPAI proposes that Idaho Power increase
14 its weatherization funding through phased program over
15 three years, to accommodate the growth capabilities of
16 each agency.
17 Q:Why should this Commission approve an increased
18 level of weatherization funding for Idaho Power.
19 A:The answer to that is several-fold. First,
20 low-income weatherization has proven to be a cost
21 effective resource for Idaho Power. This addresses
22 resource needs for the Company, while having the added
23 benefit of assisting low-income customers.
24 Weatherization constitutes a true resource acquired at a
25 favorable price. Currently, there are literally
1638 OTTENS (Di) 7
CAPAI
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24.25
1 thousands of households that otherwise qualify and could
2 benefi t for and from the program but for whom there are
3 insufficient funds to provide them the opportunity of
4 giving to, and benefitting from, the program. Thus,
5 there is a significant back log of eligible residences to
6 be weatherized and inadequate funding to accomplish this.
7 Thus, while CAPAI believes that Idaho Power's
8 low-income weatherization program is quite successful and
9 consti tutes a cost effective conservation program, there
10 remains a considerable amount of relatively low-cost
11 energy to be tapped by the program.
12 Q:What amount of increase and level of low-income
13 weatherization funding do you propose that Idaho Power
adopt?
1639 OTTENS (Di) 7a
CAPAI
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1 A:I propose a three-year phase in to the
2 following annual, total amount of funding:
3 2010 - $1.5 million
4 2011- $1.75 million
5 2012 - $2.05 million
6 Q:Will the foregoing increase in low-income
7 weatherization funding eliminate the backlog:
8 A:No. It will certainly contribute toward the
9 problem, but will fall well short of eliminating it.
10 Q:Is there another program that Idaho Power could
11 implement that would benefit the Company's low-income
12 customers?
13 A: Yes. A second program that has been tied to
14 weatherization is the provision of energy efficiency
15 education. Currently only those homes qualifying for
16 weatherization assistance currently receive such
17 education. The expansion of energy efficiency education
18 to more low income homes receiving LIHEAP would help
19 those homes to reduce their energy burden, thereby
20 reducing their individual bill amounts. Currently only
21 10% of homes receiving LIHEAP receive this education.
22 Consequently we believe that the company could assist in
23 funding a low income energy conservation education
24 program in the amount of $25,000 annually for each agency.25 in its service territory, for a total of $125,000.00
1640 OTTENS (Di) 8
CAPAI
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1 annually, to bring this education directly to those most
2 in need. While we commend the education programs Idaho
3 Power already has in place, we also recognize that a
4 household in trouble may not take time to read a bill
5 stuffer on conservation. In addition, without resources,
6 or help in finding resources, to implement conservation
7 measures the current program has minimum impact on the
8 low income families it serves.CAPAI believes education
9 to be a highly effective mechanism for reducing energy
10 demand, thereby providing system-wide benefit to all
11 ratepayers.
12 Q:Has any other electric utility implemented a
13 program of the nature described above?
1641 OTTENS (Di) 8a
CAPAI
.
.
1 A:Yes. As part of the settlement in the most
2 recent AVISTA rate case (AVU-E-08-01), AVISTA agreed to
3 implement a conservation education program as I describe
4 above. AVISTA agreed to fund the program in the amount
5 of $25,000.00.
6 Q:Why are you proposing a greater amount of
7 funding for Idaho Power?
8 A:The conservation information that will be
9 provided to customers under this program take place in
10 person and are administered by the CAP agencies. There
11 is only one CAP agency in AVISTA' s service territory.
12 There are five CAP agencies operating in Idaho Power's
13 service area. Furthermore, Idaho Power has roughly 4-5
14 times as many Idaho customers as AVISTA. My proposal for
15 Idaho Power, therefore, is relatively equal with that
16 agreed to by AVISTA.
17 Q:In your opinion, will this program have
18 system-wide benefits? Yes. Like any other
19 cost-effecti ve conservation program, such as Idaho
20 Power's low-income weatherization program, the
21 implementation of the proposed conservation education
22 program will constitute a cost effective energy resource.
23 Q:Are. there other measures that the Company can
24 take to assist low-income customers?.25 A:CAPAI also recognizes that while it is
1642 OTTENS (Di) 9
CAPAI
.
.14
15
16 /
17
18 /
19
20 /
21
22
23
24.25
1 unrealistic for Idaho Power to track low income customers
2 (other than LIHEAP recipients) due to privacy issues that
3 there are current tools to assist in recognizing trends,
4 we propose that a monthly arrearage report be compiled
5 and provided to all interested parties so that CAPAI can
6 stay on top of these trends without waiting for a rate
7 case to obtain this information. PacifiCorp currently
8 provides this information. In addition, a further
9 condi tion of an arrearage study, similar to that provided
10 by PacifiCorp is that Idaho Power would attempt to
11 identify past trends, possible causes and solutions
12 regarding the problem of arrearages.
13 iv. CONCLUSION
Q:Does that conclude your testimony?
1643 OTTENS (Di) 9a
CAPAI
.
.
1 A:Yes it does.
2
3
4
5
6
7
8
9
10
11
12
15
16
17
18
19
20
21
22
23
24
25
J
1644 OTTENS (Di)10
CAPAI
.
.
.
1
2 open hearing.)
(The following proceedings were had in
4 cross-examination.
MR. PURDY: And I tender the witness for
17
18
19
20
21
3
5
6 questions?
7
8 you.
9
10
11
12
13 Madam Chair.
14
15
16
22 you.
23
24
25
COMMISSIONER SMITH: Mr. Ward, do you have
MR. WARD: I have no questions. Thank
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions,
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Boehm.
MR. BOEHM: No questions, Your Honor.
COMMISSIONER SMITH: Mr. Howell.
MR. HOWELL: No questions.
COMMISSIONER SMITH: And Ms. Nordstrom.
MS. NORDSTROM: I have a few. Thank
CSB REPORTING
[phone]
1645 OTTENS
CAPAI
.
.
1 CROSS-EXAMINATION
2
3 BY MS. NORDSTROM:
4 Q Good morning.
5 A Good morning.
6 Q In regards to your correct~ons regarding
7 the 15 percent, does that also apply to the 15 percent
8 reference that appears on line 3, page 5?
9 A Oh, yes, if I refer to it in my testimony,
10 I'm sorry, I must have missed that.
11 Q Thank you. A significant portion of your
12 testimony discusses the setting of appropriate rate tiers
13 for the residential class. Al though Idaho Power and
14 CAPAI may disagree as to what constitutes baseline usage,
15 is it fair to say that CAPAI supports a residential
16 tiered rate design that promotes energy efficiency?
17 A I think it would be fair to say that,
18 yes.
19 Q CAPAI has requested $125,000 in energy
20 conservation education funding in this case; correct?
21
22
A Correct.
Q The Commission is currently considering
23 allocating up to a half a million dollars to fund energy
24 education in an open docket, Case No. IPC-E-08-11. Are.25 you familiar with that docket?
CSB REPORTING
[phone]
1646 OTTENS (X)
CAPAI
1 A Yes..2 Q Has CAPAI participated in that docket or
3 does it plan to?
4 A I can't answer that at this time, but I
5 can respond to what our concerns are here and why we ask
6 for separate funding, if you'd like me to.
7 Q Please, go ahead.
8 A Providing education to low income
9 customer~ is different than providing general education
10 to the Idaho Power customer and there's a lot of reasons
11 for that. A low income customer many times is in
12 survi vor mode. Their concerns are not reading little
13 flyers that come in their bill or participating in little.14 exercises. They often are hard to reach. Oftentimes
15 when they get their bill they won i t even open them
16 because they're in a state of basically they know they
17 can't pay the bill, so it goes on a pile with everything
18 else.
19 We provide energy education through the
20 weatherization program and what we're -- what we were
21 proposing here is because the weatherization folks only
22 are anywhere between four and ten percent of those that
23 receive LIHEAP funding, we would like to have a program
24 that specifically reaches out to those LIHEAP.25 participants as well. If that can be part of the program
CSB REPORTING
[phone]
1647 OTTENS (X)
CAPAI
.
.
18
1 that you're proposing in your separate case, we'd be
2 willing to work with you, but in this case, we made the
3 request at the Avista hearing. We saw the logic of it
4 and felt that it would be nice to be able to expand it
5 throughout the state.
6 Q Do you have an opinion as to what the
7 source of low income education funding should be or does
8 it matter so long as it is accomplished?
9 A I don't have an opinion.
10 MS. NORDSTROM: Thank you. No further
11 questions.
12 COMMISSIONER SMITH: Are there questions
13 from the Commission?
14 COMMISSIONER KEMPTON: No questions.
15 COMMISSIONER SMITH: Nor I. Do you have
16 any redirect,' Mr. Purdy?
17 MR. PURDY: I do not.
19 help, Ms. Ottens.
COMMISSIONER SMITH: Thank you for your
20 THE WITNESS: And. thank you for
21 accommodating my scheduling issues. I appreciate that.
22 Thank you.
23
24.25
COMMISSIONER REDFORD: Thank you.
(The witness left'the stand.)
COMMISSIONER SMITH: All right, is there a
CSB REPORTING
[phone]
1648 OTTENS (X)
CAPAI
.
.
.
19
1 preference where we go from here since the Company
2 witness is
3 MR. KLINE: -- not available? Well, I
4 don't particularly have a preference, but I would like to
5 see if we could get a time that I could call Dr. Avera.
6 I told him we would call him and set up the facilities
7 for him.
8 COMMISSIONER SMITH: Well, shall we do Mr.
9 Kahal and Dr. Peseau?
10 MR. WARD: We'd be ready any time.
11 MR. BRUDER: I had contemplated that Mr.
12 Kahal would follow rather than precede Mr. Avera if that
13 would be all right.
14 COMMISSIONER SMITH: Okay.
15 MR. BRUDER: Okay, thank you.
16 COMMISSIONER SMITH: It's not a problem
17 with me, so let's go to your witness, Conley -- I'm
18 sorry, Mr. Ward.
20 to the stand.
MR. WARD: Yes, Micron calls Dennis Peseau
21 MR. PURDY: Madam Chair, may I interject
22 just briefly? When she pleases, may Ms. Ottens take
23 leave of us?
24
25
COMMISSIONER SMITH: Yes, Ms. Ottens is
excused.
CSB REPORTING
[phone]
1649 COLLOQUY
.
.
18
1 (Pause in proceedings.)
2 COMMISSIONER SMITH: We'll go back on the
3 record.
4
5 DENNIS E. PESEAU,
6 produced as a witness at the instance of Micron
7 Technology, Inc., having been first duly sworn, was
8 examined and testified as follows:
9
10 DIRECT EXAMINATION
11
12 BY MR. WARD:
13 Q Dr. Peseau, would you please state your
14 name and address for the record?
15 A It's Dennis Peseau, spelled P-e-s-e-a-u.
16 My address is 1500 Liberty Street, Suite 250, and that's
17 in Salem, 97302.
Q By whom are you employed and in what
19 capacity?
20
21
22
23
A I'm president of Utility Resources, Inc.
Q And for whom are you appearing today?
A On behalf of Micron.
Q And in connection with this proceeding,
24 did you prepare direct testimony consisting of 46.25 pages?
CSB REPORTING
(208) 890-519~
1650 PESEAU (Di)
Micron Technology
.1 A I did.
And do you have any additions or
3 corrections to that testimony?
2 Q
I have two, which are both on page 43.
Okay, would you go ahead and explain
On line 15, the number "40 percent" is
8 shown. It should be "41 percent," and on line 17, that
4 A
9 same "40 percent" should be "41 percent."
.
5 Q
Thank you. Any other corrections?
No.
If I asked you the questions contained in
13 your prepared direct testimony today, would your answers
A
22 if read.
6 those?
7 A
10 Q
They would.
And did you also prepare under your
17 direction or supervision Exhibit Nos. 701 through 707?
18
19
11 A
Yes.
MR. WARD: With that, Madam Chair, I'd
20 request that Exhibits 701 through 707 be identified and
12 Q
21 that Dr. Peseau' s testimony be spread upon the record as
23
14 be as given?
COMMISSIONER SMITH: Without obj ection, or
24 is there an opjection?.25
15 A
MR. KLINE: I'm sorry, there is an
16 Q
CSB REPORTING
[phone]
1651 PESEAU (Di)
Micron Technology
.
.
.
1 obj ection. Previously, Madam Chairman, I filed a motion
2 to strike Exhibit 702 and 703, made that on a written
3 pleading. Counsel was given copies of it previously.
4 The reason for my motion is that I believe that Exhibit
5 702 and 703 are hearsay testimony, and let me say at the
6 outset that I recognize that the Commission has
7 tradi tionally viewed hearsay testimony very liberally and
8 I generally support that viewing of hearsay testimony
9 because I recognize that the Commissioners are experts.
10 They do have the ability to discriminate between credible
11 hearsay testimony and, I guess, incredible hearsay
12 testimony, but in this particular instance, I think in
13 one instance the testimony went beyond the normal scope
14 that the Commission utilizes.
15 Generally, Exhibits 702 and 703, I think,
16 are pretty innocuous. They are kind of a restatement of
17 the law in Iowa and Nevada and they discuss very
18 generally some of the basic utility controversies that we
19 have sometimes with respect to test years, but in
20 Dr. Peseau' s testimony when he's talking about systemic
21 bias, and that's on page 7 of his testimony, he really
22 doesn't present evidence supporting his allegation that
23 the use of a forecast test year creates systemic bias.
24 He just simply says it's obvious and that we should look
25 at -- and that the Commission should look at 702 and 703
CSB REPORTING
[phone]
1652 PESEAU (Di)
Micron Technology
.1 as the evidence supporting that conclusion. To me, that
2 is going beyond the normal scope of hearsay testimony and
3 for that reason, I believe that it should be stricken.
4 Like I say, the written filing that I made outlines our
5 arguments in that regard.
6 COMMISSIONER SMITH: Mr. Ward.
7 MR. WARD: Thank you. I think I can be
8 pretty brief about this. As Mr. Kline has acknowledged,
9 hearsay evidence is not, per se, inadmissible in
10 administrative proceedings and particularly the Public
11 Utilities Commission where we can hardly conduct a
12 proceeding without it; however, in the spirit of my
13 always prevalent stance of accommodating Mr. Kline when I.14 can and in the spirit of the holidays, I will suggest
15 this: Exhibits Nos. 702 and 703 I think have valuable
16 information that the Commission would like to consider.
17 The only point that would make them hearsay is the -- is
18 Dr. Peseau' s observation beginning at line 22 after he
19 says, "This point seems so obvious to me that it doesn't
20 require further elaboration," and then he goes on to say,
21 "but those who wish to see the argument fleshed out in
22 detail can peruse Exhibit Nos. 702 and 703," so what I
23 would propose to do is put a period after "elaboration"
24 and strike "but those who wish to see" through the end of.25 the sentence and I think that eliminates the hearsay
CSB REPORTING
[phone]
1653 PESEAU (Di)
Micron Technology
.
.
20
21
22
23
24.25
1 argument.
2 COMMISSIONER SMITH: And then Exhibits 702
3 and' 3 become perhaps reading material for the Commission
4 gi ven the weight that we determine it's entitled to.
5 MR. WARD: Correct. They are in fact
6 referred to elsewhere in the testimony and I think the
7 Company has no objection to that.
8 COMMISSIONER SMITH: Mr. Kline, does that
9 satisfy your obj ection?
10 MR. KLINE: Actually, it does in the
11 spiri t of the holidays.
12 COMMISSIONER SMITH: Now that we've all
13 gotten the only Christmas gifts we're getting, we will
14 move on to spread the prefiled testimony of Dr. Peseau
15 wi th the strike-out that has just been made on page 7 and
16 the corrections he made earlier as if read today and
17 identify Exhibits 701 through 707.
18 (The following prefiled direct testimony
19 of Dr. Dennis Peseau is spread upon the record.)
CSB REPORTING'
[phone]
1654 PESEAU (Di)
Micron Technology
.
.
1 Q.PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A.My name is Dennis E. Peseau. My business address is
3 Suite 250, 1500 Liberty Street, S.E., Salem, Oregon
4 97302.
5 Q.BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
6 A.I am the President of Utility Resources, Inc.
7 ("URI") .URI has consulted on a number of economic,
8 financial and engineering matters for various private and
9 public entities for more than twenty years.
10 Q.PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND WORK
11 EXPERIENCE.
12 A.My resume is attached as Exhibit No. 701.
13 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE IDAHO
14 PUBLIC UTILITIES COMMISSION?
15 A.Yes, on numerous occasions for more than 25 years.
16 Q.FOR WHOM ARE YOU APPEARING IN THIS CASE?
17 A.I am appearing on behalf of Micron Technology, Inc
18 ("Micron") .
19
20
Q.WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?
A.Micron has asked me to review Idaho Power Company's
21 application and make appropriate recommendations to the
22 Commission.
23 Q.PLEASE SUMMARIZE THE RECOMMENDATIONS YOU WILL BE
24 MAKING IN THIS TESTIMONY..25 A.My testimony is divided into three sections. I will
1655 PESEAU (Di) 2
Micron Technology
.
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
1 first explain my concerns with Idaho Power's use of a
2 forecasted test year. In the second section, I will
3 propose a number of adj ustments to the Company's revenue
4 requirement. In the third and final section of my
5
6 /
7
8 /
9
10 /
1656 PESEAU (Di) 2a
Micron Technology
.
.
16
17
18
19
20
21
22
1 testimony I will explain why Idaho Power's cost of
2 service studies are badly flawed, and offer a more
3 reasonable cost of service al ternati ve.
4 Idaho Power's Forecasted Test Year
5 Q.PLEASE EXPLAIN WHAT A TEST YEAR IS AND THE ROLE IT
6 PLAYS IN PUBLIC UTILITY RATEMAKING?
7 A.Every public service commission in the country uses
8 the "test year" concept as the foundation for determining
9 a regulated utility's revenue requirement and rates. The
10 traditional form of a test year has been succinctly
11 described by the Iowa Utili ties Board as follows:
12 A rate proceeding before the Board begins with
historical data. This is adj usted for known and
measurable changes in costs not associated with a
different level of revenue and revenues not
associated with a different level of cost that will
occur wi thin twelve months of the date of filing by
the utility. Typically, an historical test year is
the latest calendar year; however, a test year can
be any prior 12-month period of audited information.
In a rate proceeding, the utility files actual data
for the period and proposes adjustments to revenues,
expenses, assets, liabilities, and capital
issuances. These changes are known as "pro forma
adj ustments. . ." Once the Board decides which
adj ustments are allowed and the resulting revenue
requirement, the utility files new rates that remain
in effect until a new rate case is brought. The
goal in setting rates is to take the data from the
historical test year and make adjustments to the
historical data that more closely reflect the
expected costs and revenues going forward.
13
14
15
23 Iowa Utili ties Board, Review of Utili ty Ra temaking
24 Procedures, Report to the General Assembly (January.25 2004), P. 6 (hereafter "Iowa Report").
1657 PESEAU (Di) 3
Micron Technology
.
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
1 Q.YOU CHARACTERIZED THE ABOVE QUOTE FROM THE IOWA
2 BOARD AS A DESCRIPTION OF A "TRADITIONAL" TEST YEAR. ARE
3 OTHER TYPES OF TEST YEARS USED FOR UTILITY RATEMAKING?
4
5 1
6
7 1
8
9 1
1658 PESEAU (Di) 3a
Micron Technology
.
.
1 A.Yes. According to the Iowa Report, approximately 30
2 states use the traditional test year described above.
3 Iowa Report, P. 8. Other states allow some form of
4 forecasted results into the test year, although those
5 that do often start the forecast process with historical
6 data, and many impose other restrictions on the use of
7 this data. See Iowa Report, P. 8-9. Another recent
8 study of test year practices by the Nevada Public
9 Utili ties Commission provides further details on a
10 state-by-state basis. See Report to the 74th Session of
11 the Nevada Legislature (May 10, 2006). Because both the
12 Iowa and Nevada reports contain a detailed discussion of
13 issues present in this case, I have attached the relevant
14 portions of both to my testimony as Exhibit Nos. 702 and
15 703, respectively. In its present filing, Idaho Power
16 has modified its last proposed test year methodology to
17 make some tracing of its proposed test year adjustments
18 back to a historic test year possible, but only some.
19
20
Q.WHERE DOES THE IDAHO COMMISSION FIT IN THIS PICTURE?
A.The Idaho Commission normally uses the traditional
21 test year. But the Commission has also authorized the
22 use of a "hybrid" test year, using approximately 6 months
23 of actual test year data and 6 months of forecasted or
24 budgeted data, provided the proj ections can be tested and.25 verified before the close of the case.
1659 PESEAU (Di) 4
Micron Technology
.
12 1.13
14
15
16 1
17
18
19
20
21
22
23
24.25
1 Q.HOW DOES IDAHO POWER'S PROPOSAL IN THIS CASE COMPARE
2 TO THE IDAHO COMMISSION'S NORMAL TEST YEAR METHODOLOGIES?
3 A.Idaho Power's proposal is a significant departure
4 from this Commission's normal test year practices.
5 First, it has compiled historical data for the 2007 test
6 year. It has then adjusted the 2007 data to forecasted
7 2008 levels, using a variety of methodologies. In
8 addition, it has annualized many of the forecasted 2008
9 changes, so that the actual test year is actually
10 centered in early 2009.
11
1
1660 PESEAU (Di) 4a
Micron Technology
.
.
.
1 Q.CAN YOU BE MORE SPECIFIC ABOUT THE WAY IN WHICH
2 IDAHO POWER FORECASTED 2008 CHANGES?
3 A.In his testimony on behalf of Idaho Power, Greg Said
4 described the general methodology as follows:
5 The primary methods used to adj ust historical 2007
data to the 2008 test year include trending of plant
6 investments less than $2 million using a compound
growth rate, using "known and measurable
7 adj ustments" for plant investments of greater than
$2 million, and basing the growth of expenses and
8 revenues upon compound growth rates. (Quotation
marks are mine)
9
10 Testimony of Gregory Said, P. 24, L. 7-13.
11 Q.HOW DOES THE COMPANY ATTEMPT TO JUSTIFY ITS
12 DEPARTURE FROM PAST TEST YEAR PRACTICES?
13 A. According to Mr. Said, "The fundamental reason that
14 Idaho Power is utilizing a 2008 test year is to address
15 current concerns about regulatory lag." Testimony of
16 Gregory Said, P. 27, L. 15-17.
17 Q.DO YOU FIND THIS ARGUMENT FOR A FORECASTED TEST YEAR
18 PERSUASIVE?
19 A.I personally do not. In the first place, I disagree
20 with Idaho Power's implicit assertion that regulatory lag
21 inevi tably produces a revenue shortfall for the utility,
22 even when incremental costs exceed embedded costs.
23 Secondly, concerns about regulatory lag are not
24 new-utilities have been making similar arguments
25 throughout my career in this business. But the Idaho
1661 PESEAU (Di ) 5
Micron Technology
.
.
.
10 1
11
12 1
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Commission has nevertheless consistently refused to allow
2 the use of a fully proj ected test year, primarily because
3 forecasting introduces a host of intractable problems.
4 These problems fall under three general headings: (1)
5 forecasts of this type are inherently inaccurate and
6 unreliable,
7
8 1
9
1662 PESEAU (Di) 5a
Micron Technology
1 2) they are difficult if not impossible to verify, and.2 (3) their use in ratemaking creates a perverse set of
3 incentives and temptations for the utility and a
4 structural bias in the ratemaking process.
5 Q.WOULD YOU PLEASE EXPLAIN THE DIFFICULTY IN MAKING
6 ACCURATE FINANCIAL FORECASTS?
7 A.First of' all, it is important to carefully explain
8 what is really at issue here. There is undeniably a
9 place for forecasts in ratemaking. Idaho Power's annual
10 power cost adj ustment (PCA) provides a perfect example.
11 In the PCA proceedings, power supply costs are forecasted
12 using a carefully constructed and agreed upon model,
13 based on proj ected stream flows provided by an.14 independent third party. At the end of the year, these
15 predictions are, in effect, "trued up" to actual results.
16 Similarly, many pro forma changes that are
17 annualized during the test year, and "known and
18 measurable" changes that occur after the close of the
19 test year, are often a form of forecasting. Even if they
20 don't occur exactly as forecast, there is nevertheless a
21 very high degree of certainty about the probability of
22 the forecasted event and its likely magnitude. The
23 classic example is a nearly finished generating unit that
24 is scheduled to come on line after the close of the test.25 year.
1663 PESEAU (Di) 6
Micron Technology
.
.
.
13
14
15
16
17
18
19
20
21
22
23
24
25
1 These "forecasts" are qualitatively different
2 than the forecasts Idaho Power is using in this case,
3 where it is attempting to proj ect future costs and
4 revenues in myriad accounts, generally by using a simple
5 assumed compound annual growth rate. By definition,
6 these across-the-board forecasts are either "unknown" or
7 "unmeasurable" or both. In essence, they are simply one
8 party's guess about future trends, and that guess
9
10 1
11
12 1
1
1664 PESEAU (Di) 6a
Micron Technology
.
.
1 can neither be confirmed nor refuted because it is simply
2 an opinion about the unknowable future.
3 Actual recorded results stand on a much
4 different footing. They can be audited and verified. At
5 least within the limitations of GAAP and regulatory
6 accounting rules, they are a matter of fact. That is why
7 SEC regulations require companies to issue annual reports
8 based on audited results rather than budgets.
9 Sarbanes-Oxley now requires the top levels of management
10 to verify, under penalty of law, that those reports are
11 basically true and correct. Conversely, when management
12 issues what are called in the trade "forward looking
13 statements," they typically come with a legal disclaimer
14 to the effect that they are not statements of fact and
15 are not to be relied upon for investment decisions.
16 Q.YOUR FINAL OBJECTION TO THE USE OF A PROJECTED TEST
17 YEAR IS THAT IT WILL BIAS RESULTS IN FAVOR OF THE
18 UTILITY. THIS IS SOMETHING OF AN INFLAMMATORY STATEMENT.
19 WHAT IS YOUR EXPLANATION?
20 A.I am not talking about Enron style fraud here.
21 What I am talking about here is a systemic bias that has
22 li ttle or nothing to do with fraudulent acti vi ties.
23
24.25
Q.WHAT DO YOU MEAN BY THE TERM "SYSTEMIC" BIAS?
A.It is obvious that Idaho Power's board and
management are primarily responsible to the Company's
1665 PESEAU (Di) 7
Micron Technology
.
.
.
10
11 1
12
13
14
15 1
16
17
18
19
20
21
22
23
24
25
1 shareholders. If rates and ultimately rates of return
2 are dependent on forecasts, then there is every incentive
3 for management to overestimate costs and underestimate
4 revenues. Then it becomes a game of "catch me if you
5 can" for the PUC staff and other parties. This point
6 seems so obvious to me that it doesn't require further
7 elaboration. But those ,.'ho ,dsh to see the argument
8 fleshed out in detail can peruse Buhibit Nos. 702 and
9 -7.
1
1666 PESEAU (Di) 7a
Micron Technology
1 Q.WHY DO YOU DISAGREE WITH IDAHO POWER'S "IMPLICIT.2 ASSERTION" ABOUT THE EFFECT OF REGULATORY LAG?
3 A.Idaho Power is arguing that a differential between
4 embedded and incremental costs, coupled with system
5 growth and general inflation, will invariably produce a
6 revenue shortfall as a result of regulatory lag. The
7 fundamental flaw in this argument is that it cherry picks
8 the data by focusing only on factors that tend to
9 increase revenue requirements. Idaho Power's argument
10 would be correct if it was preceded by the caveat "all
11 other things being equal." But all other things are
12 never equal or static for a complex economic entity like.13 Idaho Power.
14 While it is true that system load growth and
15 general inflation tend to increase costs, other
16 prevailing trends decrease them. These countervailing
17 factors include such items as labor producti vi ty gains,
18 efficiency improvements, and greater economies of scale.
19 Other maj or cost inputs, the most notable of which are
20 interest rates and natural gas prices, move in
21 unpredictable ways, and they can either increase or
22 decrease costs significantly. In short, regulatory lag is
23 like financial leverage-it can work both ways. Whether
24 it helps or hurts a utility, or has no effect, depends on.25 the circumstances.
1667 PESEAU (Di) 8
Micron Technology
.
.14
15 1
16
17 1
18
19
20
21
22
23
24.25
1 To his credit, Idaho Power's witness Ric Gale
2 acknowledges this fact. As Mr. Gale points out, "The
3 impact of regulatory lag is dependent on the situation-if
4 costs are not going up faster than rates, then the
5 utility is not harmed and may even be helped by lag."
6 But Mr. Gale then goes on to allege that "Idaho Power is
7 not in that situation and will not likely be for the
8 foreseeable future." Testimony of John R. Gale, P. 1, L.
9 1-6.
10 Q.DO YOU DISAGREE WITH MR. GALE'S VIEWS ABOUT THE
11 "FORSEEABLE FUTURE?"
12
13 1
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1 A.Gi ven the economic circumstances we are facing
2 today, Mr. Gale's assumption about the "foreseeable
3 future" is demonstrably wrong. In fact, as I will
4 explain later, the prevailing cost trends are now working
5 in Idaho Power's favor by tamping down load growth and
6 lowering costs. But before I turn to a discussion of
7 today' s new realities, I think it is important to point
8 out that the historical record shows that there have been
9 long periods of time in recent years when regulatory lag
10 did not produce a revenue shortfall for Idaho Power,
11 notwithstanding the presence of continuing system growth,
12 general inflation, and an embedded/incremental cost
13 differential.
14 Q.PLEASE DESCRIBE THE HISTORICAL EVIDENCE YOU JUST
15 REFERENCED.
16 A.If we look back over the last 15 years, we see that
17 nearly a full decade passed without a rate case prior to
18 Idaho Power's 2003 filing. Avista and Pacificorp
19 experienced a similarly long hiatus between rate cases
20 during roughly the same time frame. In Pacificorp' s
21 case, this respite can be partially attributed to agreed
22 upon merger and acquisition related rate freezes. But,
23 to the best of my knowledge, neither Avista nor Idaho
24 Power were under similar constraints.
25 Q.WHAT CONCLUSIONS DO Y~U DRAW FROM THIS TEN YEAR
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1 SUSPENSION IN RATE CASES?
2 A.Investor owned utili ties are for-profit
3 insti tutions, and neither Idaho Power nor Avista has
4 shown any reluctance to engage in frequent rate cases
5 when they believed they had a revenue shortfall, either
6 before or after the 1994-2003 decade. Therefore, I
7 conclude that these companies generally believed they
8 were earning a fair return during this approximately 10
9 year time period, notwithstanding the very long lag after
10 the initial rate determination.
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1670 PESEAU (Di) 9a
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1 Q.WAS THAT BECAUSE THE CONDITIONS MR. GALE IS
2 DESCRIBING IN 2008 WERE DIFFERENT DURING THAT TIME FRAME?
3 A.No. The Consumer Price Index showed general
4 inflation during the 90s holding relatively steady at an
5 annual rate of a little less that 3%, very near the
6 current CPI rate today.
7 According to Value Line, Idaho Power's book
8 value per share steadily increased throughout the 1990s,
9 as did capital spending per share in most years. This
10 indicates that Idaho Power was growing at a fairly steady
11 pace during that period.
12 Finally, just based on my experience in this
13 industry and in following Idaho Power over that time
14 frame, I can say with confidence that its incremental
15 capi tal costs also exceeded embedded costs then, just as
16 they do now. Noticeable exceptions were the drop in
17 wholesale prices with transmission access, and the heat
18 rate improvement in new combustion turbines.
19 So conditions then were very similar to the
20 circumstances described in Mr. Gale's testimony.
21 Q.SO WHY DIDN'T THE LONG REGULATORY LAG BETWEEN THE
22 SETTING OF RATES IN THE EARLY 90S AND THE GENERAL RATE
23 CASE FILED IN 2003 PRODUCE REVENUE DEFICIENCIES?
24.25
A.I couldn't say without undertaking a complex and
lengthy study. I suspect the persistent decline in
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1 capital costs and fuel prices from the highs of the early
2 1980s, together with productivity and efficiency
3 improvements, the adoption of annual power cost
4 adj ustments, and other factors, all played a part. But
5 my point is that history shows that for roughly
6 two-thirds of the last 15 years, regulatory lag was
7 benign from the utility's
8
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1672 PESEAU (Di) 10a
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1 point of view. It also shows that neither system growth,
2 general inflation, nor a differential between embedded
3 and incremental costs means that regulatory lag will
4 inevi tably produce a revenue requirement shortfall.
5 Idaho Power's presumed cause and effect relationship
6 between these items simply doesn't exist.
7 Q.YOU EARLIER STATED THAT MR. GALE'S FORECAST OF THE
8 "FORSEEABLE FUTURE" IS DEMONSTRABLY WRONG. WOULD YOU
9 PLEASE EXPLAIN THAT STATEMENT?
10 A.When Mr. Gale drafted his testimony, presumably
11 sometime in the spring of 2008, he effectively assumed
12 that the past. was prologue; that Idaho Power would
13 continue to experience strong system growth, fed in large
14 measure by the continuation of the housing and
15 construction booms, and that costs, particularly fuel and
16 commodi ty costs, would continue to escalate at marginal
17 rates well in excess of embedded costs. These
18 assumptions are wildly at odds with current realities,
19 and are almost certain to remain so through at least the
20 first half of 2009.
21 Q.WHY DO YOU SAY THAT?
22 A.When Mr. Gale was writing his testimony, he could
23 not have foreseen the complete collapse of the biggest
24 housing bubble in history, followed by what is generally
25 regarded as the worst financial crisis since the Great
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1 Depression. In only a few short weeks we have witnessed
2 a once unthinkable destruction of some of the nation's
3 largest financial institutions, followed by the partial
4 or complete nationalization of others, such as Fannie Mae
5 and Freddie Mac and most of the nation's largest banks.
6 This catastrophe has predictably spilled over
7 into the "real" economy. In the words of Merrill Lynch's
8 chief investment strategist, Richard Bernstein, "We have
9
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1674 PESEAU (Di) 11a
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.1 progressed beyond a global credit crisis. This is now a
2 global economic crisis." Barron's, P. M3 (Oct. 13,
3 2008). The evidence for Mr. Bernstein's view is all too
4 familiar to all of the parties in this proceeding, so I
5 will not belabor it at length. But I think it is
6 important for the record to contain a least some
7 illustrations of the dire economic circumstances we are
8 facing.
9 As this testimony is being finalized, the
10 Standard and Poor's 500 stock index is down about 40%
11 year to date, with most of the world's other exchanges
12 reporting similar or even greater losses. The housing.13 market is at a virtual standstill, except for
14 foreclosures running at the rate of about 300,000 per
15 month. Newsweek, P. 40 (Oct. 20, 2008). Credit card
16 delinquencies have roughly doubled in the last year, with
17 even the strongest issuer (American Express) reporting
18 uncollectibles of roughly 6.7%. Wall Street Journal, P.
19 C1 (Oct. 20, 2008). The Federal Reserve just reported
20 that industrial production fell 2.8% in September, the
21 worst monthly loss since 1974. Reuters Wire Service
22 (Oct. 17, 2008). Not surprisingly, unemployment has
23 increased for' nine straight months by roughly 33% to (a
24 probably understated) rate of 6.1%. Newsweek P. 39 (Oct..25 20,2008).
1675 PESEAU (Di) 12
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1 We don't have comparable figures for all these
2 categories for Idaho alone or Idaho Power's service
3 terri tory, but there is plenty of anecdotal evidence that
4 Idaho is not immune from the unfolding national disaster.
5 Home foreclosures in Ada and Canyon counties are up 137%
6 for the year,. and running at the rate of about 460 per
7 month. Idaho Statesman, Business Section P. 1 (Oct. 21,
8 2008). As of September, 2008, Idaho unemployment has
9 increased 86.6% in the last year, and my client, and the
10 state's largest
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1676 PESEAU (Di) 12a
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.1 private employer, has just announced layoffs for about
2 1500 employees, equal to about 15% of its local
3 workforce.
4 Q.ARE THERE ANY BRIGHT SPOTS IN THIS ECONOMIC PICTURE?
5 A.Not many. About the only thing one can point to is
6 the precipitous drop in commodity prices, particularly
7 oil and natural gas. Oil prices now stand at less than
8 $70/barrel, down from a 52 week high of $145, and. natural
9 gas prices are at $ 6. 53/mmbtu, down from a 52 week high
10 of $13.57. This will tamp down the inflation rate, and
11 perhaps lead to short term deflation for both consumers
12 and companies alike..13
14
15
Q. WHAT DOES ALL THIS HAVE TO DO WITH REGULATORY LAG
AND THE USE OF A FORECASTED TEST YEAR?
A.Under these circumstances, the use of an historical
16 test year, properly adjusted for known and measurable
17 changes, is not likely to produce meaningful regulatory
18 lag. In fact, it could quite easily produce regulatory
19 lead, in which historical data overstates actual expenses
20 and understates earnings.
21 Furthermore, it makes Idaho Power's forecasted
22 test year, which is premised on a continuation of steady
23 system load growth and a further rapid climb in already
24 high costs, implausible to the point of impossibility, as.25 I will show in the next section of my testimony which
1677 PESEAU (Di) 13
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21
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24.25
1 discusses proposed adj ustments to its revenue
2 requirement.
3 Q.SO WHAT is YOUR RECOMMENDATION TO THE COMMISSION
4 REGARDING IDAHO POWER'S USE OF A FORECASTED TEST YEAR?
5 A.I personally believe that, even in normal
6 circumstances, the type of general, across-the-board
7 expense increases Idaho Power is forecasting in this case
8 are too unrel~able for use in ratemaking, and that they
9 are likely to be biased in the Company's favor as well.
10
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1678 PESEAU (Di) 13a
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1 Given the economic circumstances we now find ourselves
2 in, the use of a forcasted test year that essentially
3 posi ts the continuation of the now deflated boom of the
4 early years of the century is nonsensical on its face.
5 Therefore, I believe the most accurate method would be to
6 use the normal 2007 historical test year, adjusted for
7 known and measurable changes.
8 But if the Commission should disagree, then I
9 strongly urge it to adopt some limitations or
10 "sideboards" on the use of forecasts that I will describe
11 in the following section of my testimony dealing with
12 revenue requirement issues.
13 Revenue Requirement Adj ustments
14 Q.PLEASE DESCRIBE THE FIRST REVENUE REQUIREMENT ISSUE
15 YOU WILL BE ADDRESSING.
16 A.The first issue is also the simplest, and it has to
17 do with net power supply expenses. The forecasted
18 increase in tpis expense is the largest single component
19 of Idaho Power's $67 million rate increase request,
20 accounting for approximately $23. 7 million of that total.
21 This forecast is, in turn, primarily dependent on two
22 interrelated elements. The first has to do with the
23 delay of approximately 62 average megawatts of PURPA
24 generation previously scheduled to come on line during
25 2008. The second factor in the forecasted increase is
1679 PESEAU (Di) 14
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1 proj ected natural gas prices.
2 Q. PLEASE EXPLAIN WHY THE PURPA SHORTFALL AND NATURAL
3 GAS PRICES ARE INTERRELATED?
4 A.Most merchant plants and virtually all of the
5 peaking generators in the Pacific Northwest are natural
6 gas fired. Consequently, when a regional utility
7 experiences a shortfall in system resources, such as the
8 PURPA plant delays at issue here, the biggest single
9 factor
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1680 PESEAU (Di) 14a
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1 in determining the price of replacement power is the
2 price of natural gas to fuel the replacement generation.
3 I should point out that this is not a direct or linear
4 relationship because the Idaho Power net power supply
5 expense model is very complex and considers a host of
6 factors. But it is nevertheless true that there is a
7 strong correlation between natural gas prices and
8 replacement power costs.
9 Q.HOW DOES THAT RELATIONSHIP PLAY OUT IN THIS CASE?
10 At the time Idaho Power prepared its testimony inA.
11 this case, it used a March 2008 NYMEX natural gas price
12 forecast averaging about $10 /mmtu. As my testimony is
13 being prepared in mid-October of 2008, actual natural gas
14 prices, as well as gas price forecasts are under
15 $7/mmbtu. This approximate 30% reduction in prices will,
16 of course, have a significant effect on regional
17 electricity prices and Idaho Power's net power supply
18 expenses for the test year.
19 Q.CAN YOU QUANTIFY THAT EFFECT WITH PRECISION?
20 Not precisely, because I do not have access to IdahoA.
21 Power's proprietary power supply model. I am sure,
22 however, that use of the current natural gas prices in
23 the net power supply expense model would eliminate all or
24 a very substantial portion of the forecasted increase in
25 net power supply expenses.
1681 PESEAU (Di) 15
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1 Q.WHY DO YOU SAY THAT?
2 Because current natural gas prices are relativelyA.
3 close to the prices the Commission used to determine
4 PURPA rates by using a modeled combined cycle natural gas
5 generator as a surrogate for market prices. If both the
6 PURPA model and net power supply expense model are
7 performing as they should, the implied result would be a
8 relatively minimal
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1682 PESEAU (Di) 15a
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1 gap between the price Idaho Power would have paid for the
2 missing PURPA generation and the cost of replacement
3 power.
4 DID YOU REQUEST THAT IDAHO POWER RE-RUN ITS POWERQ.
5 SUPPLY MODEL TO REFLECT THE APPROXIMATE 25-30% REDUCTION
6 IN NATURAL GAS PRICE FORECASTS?
7 Yes. Micron data requests Nos. 21-23 asks for thisA.
8 information. Unfortunately, the requests apparently were
9 not sufficiently clear. Nonetheless, Idaho Power
10 produced 2 re-runs of its model in response to Micron's
11 requests.
12 WHAT DIFFERENCES IN NET POWER SUPPLY COSTS, IF ANY,Q.
13 DID THESE RE-RUNS PRODUCE?
14 A. The actual production request and response is
15 attached as Exhibit No. 704.Pages 2 and 3 contain the
16 resul ts of the re-runs using current natural gas prices.
17 These two re-runs list net power supply costs of
18 $64,153,700 and $62,142,900. This compares with the
19 Company's filed net power supply expense of $88,421,200,
20 a decrease of approximately $24 million to $26 million.
21 ARE YOU PROPOSING THAT TEST YEAR NET POWER SUPPLYQ.
22 EXPENSES BE REDUCED BY THE APPROXIMATE $25 MILLION COST
23 REDUCTION SHOWN IN YOUR EXHIBIT NO. 704?
24 Not exactly. Since I do not have access to theA.
25 Company's power supply model, and the outputs supplied by
1683 PESEAU (Di) 16
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1 Idaho Power were not prepared under my supervision and
2 control, I cannot verify whether the Company successfully
3 made all necessary adj ustments to its modeling. I can
4 only state that the exhibit's dramatic reduction in net
5 power supply costs is about what I expected, given the
6 sizable decline in expected natural gas prices.
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1684 PESEAU (Di) 16a
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1 Q.HOW SHOULD THE COMMISSION DEAL WITH THIS ISSUE IN
2 THIS PROCEEDING?
3 A.NYMEX real time and futures prices are published by
4 a variety of sources and are readily verifiable. So my
5 ideal solution would be to have the Commission direct the
6 Staff or Idaho Power rerun the model using the most
7 current available prices just before an order is issued
8 in this case. Unfortunately, counsel informs me that
9 there may be a legal problem with the development of
10 evidence after the close of proceedings in this case.
11 So, as a next best solution, I would suggest that the
12 Staff should supply updated model results with their
13 rebuttal testimony filing. Failing that, the Commission
14 should use the re-runs of the model, with now current gas
15 prices, contained in Exhibit No. 704. This would, of
16 course, completely negate Idaho Power's forecasted $23.7
17 million net power supply cost increase.
18 Q.ARE THERE ANY OTHER REVENUE REQUIREMENT ISSUES THAT
19 ARE DIRECTLY RELATED TO IDAHO POWER'S FORECASTS?
20 A.Yes. Idaho Power has chosen to inflate its 2008
21 individual operations and maintenance (O&M) line items by
22 ei ther a three or five year historical compound annual
23 growth rate. Company Exhibit No. 41 shows that most of
24 these annual growth rates fall within the range of 7-11%.
25 No rationale is provided for the use of this inflator,
1685 PESEAU (Di) 17
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1 other than the argument that this methodology is
2 "transparent" and easy to explain.
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1686 PESEAU (Di) 17a
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1
2
Idaho Power Company
O&M Expenses Adjusted by Compound Growth Rates
tPC tPC IPC
Expense 2007 Actual Proposed Increase Peronl
Steam Operation Expense 18.979.077 20.333.969 1.354.892 7.14%
Steam Maintenance Expense 29.479.799 31.584.657 2.104.858 7.14%
Hydro Operation Expense 24.394.953 26,353.868 1,958.915 8.03%
Hydro Maintenance Expense 8.551.183 9.237.843 686.660 8.03%
Oth Power Operalion 1.188.339 1.328.087 139.748 1176%
Oth Power Maintenance 908.885 1.015.770 106.885 11.6%
Load control 77489 86.602 9.113 11.6%
Other Expenses 2.450.96 2.739,193 288.233 11.76%
Transmission O&M 16.188.474 16.832.775 644.301 3.98%
Distribution O&M 44.601.780 44,913992 312.212 0.70%
Customer Accounts 16.065,646 16.075.185 9.539 006%
Customer Service 9.607.619 9.613.384 5.765 0.06%
Admin & Gene ral 89.376.659 97.787,203 8.410.544 941%
Tolal 261.870.86 277.902.528 16.031.6ô 612%5.237.417 (10.794.248)
3 Max
Increase (Q
2% Adjustment4
5
6
7
8
9
This is simply not an adequate reason for the use of
percentage inflators that are shockingly high by any
measurement.They are well above the system load growth
15 rate, which Mr. Said projects at 1.9% a year, as well as
16 the growth in 'number of employees.They are also well
17 above the Producer Price Index (" PPI") inflation rate,
18 which is running in negative terri tory at this writing.
19 Barring very unique circumstances, no well run
20 utility should experience prolonged O&M growth rates of
21 this magnitude for any extended period of time, and this
22 is doubly true when prices for items like gasoline and
23 other commodities are in decline as they are now, the
24 Producer Price Index has dipped into negative terri tory,
25 and the country is likely either in, or entering, what
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1 could be a nasty recession. This is particularly true
2 for the Administrative and General ("A&G") expense
3 category, which comprises more than half the forecasted
4 O&M increase, and is forecasted to rise at a rate well in
5 excess of 9%. A&G expenses consist of items like office
6 supplies, office salaries, and advertising
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1688 PESEAU (Di) 18a
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1 that are subj ect to considerable management discretion
2 and control, and should be one of the first places to
3 look for savings when times get tough, as they certainly
4 are now.
5 Q.HOW SHOULD THE COMMISSION DEAL WITH THIS ISSUE?
6 A.My preferred solution is to eliminate all of the
7 across-the board inflators and accept only known and
8 measurable adj ustments to the historic test year. But if
9 general price inflation forecasts are allowed, this is
10 one of those instances where some objective standard must
11 be used to limit the use of a generic inflator in order
12 to provide efficiency incentives and to temper the
13 utili ty' s incentive to select the highest possible method
14 of forecasting expenses. I have suggested three possible
15 obj ecti ve caps above-the PPI index, the rate of system
16 load growth, or employee load growth. Any of these three
17 would effectively cap the O&M inflator at no more than
18 2g.o .Anyone of these three inflators makes Idaho Power
19 far better off than under the previous, more traditional
20 test year concepts, while providing safeguards for the
21 ratepayers. A 2% cap would reduce the requested revenue
22 increase by approximately $10.8 million, as shown on
23 Exhibit 705.
Q.WOULD YOU PLEASE EXPLAIN THE NEXT REVENUE
REQUIREMENT ISSUE YOU HAVE IDENTIFIED?
1689 PESEAU (Di) 19
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1 A.Idaho Power's forecasted test year results in a
2 proposed increase in rate base of over $280 million.
3 Approximately $190 million of this total is attributed to
4 "known and measurable" rate base adjustments during 2008,
5 and the remaining $91 million is due to annualizing the
6 impact of these additions, i. e., treating them as if they
7 were in rate base for the entire year.
8 While such annualizing adjustments may be
9 appropriate for an historic test period, in my opinion
10 they are totally inappropriate for a future test period.
11 In any historical test
12
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1690 PESEAU (Di) 19a
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1 period, additions to rate base will be made throughout
2 the period. Actual earned return on rate base will
3 depend on income and actual in service dates for rate
4 base additions. Setting rates based on the assumption
5 that some assets will be in rate base for the whole
6 period, when in fact they are not, ignores reality and
7 introduces numerous complexities that require secondary
8 forecasts about the associated revenues and other items.
9 Furthermore, it effectively creates a rate base that is
10 actually representative of the 2009 test year or beyond,
11 until the next maj or plant addition comes on. This
12 simply tilts the playing field too far in Idaho Power's
13 direction.
14 Q. CAN YOU PROVIDE AN ILLUSTRATION OF THE DIFFICULTIES
15 ASSOCIATED WITH THE SECONDARY FORECASTS YOU REFERRED TO
16 ABOVE?
17 A.Yes. MrA Said's Exhibit No. 52, attached here as my
18 Exhibit No. 706, illustrates this problem very clearly.
19 In Mr. Said's exhibit, the approximate $ 13 million
20 requested increase in costs (roughly $ 91.3 million plant
21 annualization * .0855 (return) * 1.642 (tax gross up))
22 compares with Idaho Power's proposed offsetting revenue
23 annualization of a paltry $1,489,324, also shown on
24 Exhibit 706. Idaho Power's proposed "matching" of
25 annualized costs and revenues comes out in favor of
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1 shareholders over ratepayers by a factor of nine to one.
2 This seems to me indefensible and unreasonable on its
3 face.
4 Furthermore, with Idaho Power on record as
5 intending to seek annual rate increases for at least the
6 next few years, presumably including a rate increase in
7 2009, the case for forecasted annualization to capture
8 2009 results is extremely weak, at best, particularly
9 when the annualized results are so blatantly skewed in
10 the utility's favor.
11
12 /
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1692 PESEAU (Di) 20a
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.1 I urge the Commission to deny the Company's
2 proposed $91.3 million Plant annualization adjustment.
3 This would decrease the Company's requested revenue
4 requirement increase by about $ 12.8 million.
5 Q.WHAT is YOUR RESPONSE TO IDAHO POWER'S REQUEST FOR
6 THE INCLUSION OF RELICENSING CONSTRUCTION WORK IN
7 PROGRESS ("CWIP") IN RATE BASE?
8 A.I am adamantly opposed to the inclusion of the
9 forecasted 2009 relicensing costs of $7.6 million, both
10 as a matter of principle and for a number of practical
11 reasons.
12 Q.WOULD YOU PLEASE EXPLAIN THE "MATTER OF PRINCIPLE".13 INVOLVED IN THIS ISSUE?
14 A.Perhaps the best way to begin is with a brief
15 general discussion of what is often referred to as the
16 "regulatory compact" between an investor owned utility,
17 such as Idaho Power, and its ratepaying customers. Since
18 I am an economist and not an attorney, I will not discuss
19 the various statutes and court decisions that flesh out
20 this "compact," but instead describe the situation as
2 1 economists understand it.
22 As a general rule, de jure monopolies are
23 fundamentally at odds with the competitive free market
24 system that characterizes most of the American economy..25 We have chosen, however, as a matter of public policy, to
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1 make an exception to this general rule for certain
2 utility services like the provision of electricity,
3 primarily on the grounds that the duplication of
4 facili ties by competing providers would be inefficient
5 and wasteful. Thus, an investor owned utility like Idaho
6 Power has an exclusive franchise to provide electric
7 service wi thin its franchise area.
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1694 PESEAU (Di) 21a
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1 In return for this exclusive monopoly, the
2 utili ty is obligated to raise the necessary capital and
3 make appropriate investments to enable it to provide
4 reasonable, non-discriminatory service to all who request
5 it. The ratepayers' side of the compact is an obligation
6 to pay the reasonable costs of providing this service,
7 generally consisting of the reimbursement of the
8 utili ty' s prudently incurred expenses, plus a fair
9 opportuni ty to earn a reasonable return or profit on
10 investments that are "used and useful" in the provision
11 of electric service.
12 It is important to point out that, contrary to
13 a widely held misperception among the general public, an
14 investor owned utility's investments are not risk free,
15 nor are its profits guaranteed. This is primarily due to
16 the fact that public service commissions are charged with
17 the duty of regulating the investor owned utili ties in a
18 manner that, as nearly as possible, imposes the financial
19 discipline and operating efficiencies that would
20 otherwise be provided by competitors or the threat of
21 competition. One of the tools the commissions use to
22 replicate the effects of competition is, of course, the
23 disallowance of imprudently incurred expenses and
24 nonproductive capital investments in ratemaking.
25 Q.WHAT DOES THIS GENERAL DESCRIPTION OF THE REGULATORY
1695 PESEAU (Di) 22
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1 COMPACT HAVE TO DO WITH IDAHO POWER'S CWIP REQUEST?
2 A.From an economist's point of view, the fundamental
3 problem with CWIP is that it breaks the regulatory
4 compact in a way that mitigates efficiency incentives and
5 is fundamentally unfair to ratepayers. Capitalists all
6 over the world understand that when they make an
7 investment in new production facilities they are putting
8 their money at risk of a partial or total loss, and that
9 they will see no return of, or on, their investment until
10 the facilities actually produce a marketable output.
11 These considerations force management to make
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1 careful and frugal investment decisions and to implement
2 them as rapidly and efficiently as possible.
3 But when a utility is allowed to place CWIP in
4 rate base, these powerful efficiency incentives
5 disappear. In essence, the public misconception I
6 mentioned earlier becomes correct-utili ties are now
7 guaranteed a risk free profit. Investments pay the same
8 whether they are productive or not, and there is no need
9 to proceed with construction as diligently and
10 efficiently as possible because the completion date and
11 the beginning of productive output are irrelevant. Since
12 the state, acting through the public utilities
13 commission, will forcibly extract compensation from the
14 public for good and bad performance alike, there is no
15 incentive to perform. History is replete with examples
16 of the folly of this approach.
17 Q.YOU HAVE EXPLAINED WHY YOU OPPOSE CWIP IN PRINCIPLE,
18 BUT YOU ALSO STATED THAT IT IS "FUNDAMENTALLY UNFAIR TO
19 RATEPAYERS. " WOULD YOU PLEASE EXPLAIN THAT STATEMENT?
20 A.Including CWIP in rate base essentially converts
21 Idaho Power's ratepayers into involuntary investors.
22 They will be investing in the Company's relicensing
23 effort for the Hells Canyon projects. If successful,
24 this will result in an immensely valuable asset for Idaho
25 Power Company's shareholders, but the ratepayers will not
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1 get the ownership stake they would normally be entitled
2 to for their investment.
3 This problem is compounded by the fact that the
4 utili ty' s CWIP will earn its normal rate of return, which
5 is premised on the idea that utility shareholders are
6 bearing the investment risk, when it really should
7 recei ve no more than the much smaller risk free rate of
8 return for investments funded by ratepayers rather than
9 shareholders.
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1 Q.PERHAPS THE RATEPAYERS SHOULD GET WHAT WARREN
2 BUFFETT is REPORTED TO HAVE RECEIVED FOR HIS CASH FLOW
3 INFUSION IN GENERAL ELECTRIC AND GOLDMAN SACHS-PREFERRED
4 STOCK PAYING ABOUT A 10% DIVIDEND AND STOCK WARRANTS THAT
5 WILL CAPTURE ANY UPSIDE IN THE COMPANIES' FORTUNES.
6 A.Not under Idaho Power's proposal.
7 Q.SO WHAT DO THE RATEPAYERS GET UNDER IDAHO POWER'S
8 CWIP PROPOSAL?
9 A.Under Idaho Power's proposal, the ratepayers would
10 get, in return for their cash infusion, a "Regulatory
11 Asset" amortized over the life of the plant asset.
12 Testimony of Catherine M. Miller P. 13, L. 9-19.
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Assuming that the plant life is on the order of 30 years,
this amounts to a 30 year unsecured loan at 0% interest.
15 Moreover, the. consumers have to pay for the taxes Idaho
16 Power will incur on this cash infusion, which turns the
17 total rate impact into roughly $12 million dollars,
18 rather than the $7.6 million Idaho Power would actually
19 recei ve. At a time when approximately 40% of households
20 are carrying significant credit card debt, this amounts
21 to many ratepayers borrowing at double digit interest
22 rates to make an unsecured, interest free, 30 year loan
23 to an investor owned utility whose borrowing costs are
24 far below theirs.
25 This Idaho Power proposal should be rejected in
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1 its entirety.
2 Q.ARE THERE ANY OTHER REVENUE REQUIREMENT ISSUES YOU
3 WISH TO ADDRESS?
4 A.Just one. About $17 million of Idaho Power's
5 requested rate increase is tied to its request for an
6 increase in its return on equity. I do not intend to
7 make a formal presentation on
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1 this subj ect, although I believe the Staff and DOE will
2 do so. But I would like to note for the record that it
3 is my understanding that the Commission is entitled to
4 consider "all relevant matters" in rate cases. The
5 economic circumstances Idaho Power's customers are facing
6 seem to me very relevant, and I have great difficulty
7 imagining a rationale that would justify an increased
8 return on equity in the face of the economic difficulties
9 we are facing.
10 Q.EVEN WITHOUT A FORMAL STUDY, ARE YOU ABLE TO ASSESS
11 THE VALIDITY OF IDAHO POWER'S REQUEST FOR AN INCREASE IN
12 RETURN ON EQUITY ("ROE") FROM THE 10.25% DETERMINED IN
13 2007 TO THE 11.25% NOW BEING REQUESTED?
14 A. Yes. I have reviewed several of Idaho Power witness
15 Dr. Avera's testimonies over the years, in Idaho and
16 other jurisdictions. Dr. Avera's approach to estimating
17 his ROE here is the same as in the 2007 Idaho case. It
18 is therefore a fairly easy matter to determine whether
19 his financial indicators, market interest rates and Idaho
20 Power risk measurements do, or do not, warrant an
21 increase or decrease from the currently allowed ROE of
22 10.25%. I conclude from the analysis below that no
23 change is necessary.
Q.PLEASE REVIEW YOUR ANANLYSIS OF DR. AVERA'S ROE
ESTIMATES.
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1 A.Dr. Avera relies on standard measures of interest
2 rates, risk measures (beta) and growth rates in
3 implementing his DCF (discounted cash flow), CAPM
4 ( capital asset pricing model) and his comparable earnings
5 approaches. We can compare these key financial
6 determinants used by Dr. Avera in this case (2008) with
7 the same determinants he used in 2007. This comparison
8 indicates that his 2008 ROE estimate should be slightly
9 lower
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1 than, or at best equal to, his 2007 estimate. Thus, a
2 reasonable return on equity should be no more than the
3 return of 10.25% the Commission found fair and reasonable
4 in 2007.
5 Q.PLEASE BRIEFLY DESCRIBE THE KEY COMPONENTS OF THIS
6 COMPARI SON.
7 A.Dr. Avera's 2008 long-term Treasury rates (4.6%) are
8 slightly less than those used in 2007 (4.8%), indicating
9 that interest rates have declined. Bond rates have been
10 essentially flat for IDACORP, being 6.24% in June 2007,
11 6.26% in March 2008, 6.23% in June 2008 and 5.94% in
12 September 2008.
13 Dr.. Avera's risk measure for his 2007 sample
14 was .95, and dropped to .88 in the 2008 case. This risk
15 index, beta, measures the market risk (also called
16 systematic risk) of IDACORP compared with the market.
17 The degree of risk of Idaho Power, as measured by beta,
18 has declined slightly from 2007 to 2008.
19 Dr. Avera's "forward-looking risk premium",
20 another component used in his risk-adjusted ROE estimate,
21 has declined from 11.5% in 2007 to 10.8% in 2008. All
22 else constant, this reduces Idaho Power's estimated ROE.
23 Dr. Avera uses different samples of
24 "comparable" companies from 2007 to 2008. This change in
25 samples is the only method that produced a slightly
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1 higher estimated ROE in the 2008 case, from 10.6% to
2 11.1%.
3 Finally, Dr. Avera's range of DCF estimates for
4 ROE in the 2007 and 2008 cases produce near exactly
5 identical midpoint ROE, the only difference being a
6 wider range of estimates results from his 2008 study.
7 Again, my assessment from a comparison of the
8 determinants used by Dr. Avera leads me to conclude that
9 no increase from the currently authorized 10.25% ROE is
10 justified or necessary.
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1 Q.SINCE THE 2003 IDAHO POWER GENERAL CASE WAS THE LAST
2 CONTESTED CASE, DID YOU ALSO VERIFY THE CURRENTLY ALLOWED
3 ROE OF 10.25% REMAINS FAIR AND REASONABLE WHEN COMPARED
4 TO 2003?
5 A.Yes. Dr. Avera also testified on ROE on behalf of
6 Idaho Power in 2003. In that case, his mid-point DCF
7 estimate was nearly identical to his recommended
8 mid-point in this case.
9 His interest rate used in that case was 5.39%,
10 higher than in this case, which would argue for a lower
11 ROE in the 2008 case. His risk estimate, beta, and his
12 risk premium in the 2003 case results in a higher CAPM
13 estimate than today. This leads to the conclusion that
14 the ROE estimate in 2008 is lower than in 2003.
15 Q.WOULD YOU PLEASE SUMMARIZE YOUR TESTIMONY ON REVENUE
16 REQUIREMENT ISSUES?
A.Idaho Power is requesting a revenue requirement
18 increase in this case of approximately $ 67 million. I
19 have proposed- the following adj ustments to the Company's
20 filing, all of which I believe to be well justified:
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1.Updated net power supply costs ($25 million);
2.O&M increase capped at 2% ($10.8 million);
3.annualization elimination ($12.8 million);
4.CWIP elimination ($12 million); and
5.No change in ROE ($17 million) .
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1 In total, these adj ustments reduce Idaho
2 Power's claimed revenue requirement by approximately $78
3 million. Consequently, I believe an approximate $11
4 million decrease in Idaho Power's revenue requirement is
5 just and reasonable.
6 Q.ARE YOU SURPRISED BY THESE RESULTS?
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1 A.Not at all. Idaho Power's request in this case is
2 predicted on the "forecast" that recent load growth and
3 cost trends would continue for the "foreseeable future."
4 As I have pointed out in this case, and prior filings,
5 this supposed forecast is really just an assumption and
6 it is no more supportable or rational than the assumption
7 that stock prices and housing prices always go up.
8 As millions of homeowners and investors have
9 now discovered to their dismay, economic trends can slam
10 into reverse without warning, and this reversal can be
11 much sharper, and last much longer, than the conventional
12 wisdom assumes. This is exactly what is happening to
13 Idaho Power now. As growth stops and costs plummet, its
14 revenue requirement goes down, not up. This is a
15 perfectly logical and predictable result, and it is only
16 surprising to those who bought into the utility delusion
17 that costs and revenue requirements always go up.
18 Rate Structure - Cost of Service Issues
Q.WOULD YOU PLEASE EXPLAIN WHY IDAHO POWER'S COST OF
20 SERVICE STUDIES ARE "BADLY FLAWED"?
21 A.Before I do so I would like to first offer some
22 background information that I hope will help to frame the
23 cost of service issues in this case. Idaho Power's cost
24 of service witness, Mr. Timothy Tatum, correctly
25 describes the cost of service process from a technical
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1 point of view, but he doesn't explain what's really at
2 issue, or provide the context of such studies wi thin the
3 regulatory framework. Consequently, I suspect that this
4 technical discussion is virtually unintelligible to
5 members of the general public. So I propose to start
6 wi th some basic principles of cost of service, and then
7 gradually hone in on the more difficult concepts, as well
8 as the issues in this case.
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1 Q.WOULD YOU PLEASE START BY EXPLAINING THE PURPOSE OF
2 A COST OF SERVICE STUDY?
3 A.All rate cases really consist of two distinct
4 undertakings, and in fact the Idaho Commission has
5 occasionally divided rate cases into two separate
6 hearings on these issues. First, the Commission
7 determines a utility's overall revenue requirement, i. e. ,
8 the size of the pie. The next task is to determine what
9 proportion of that total revenue requirement should be
10 recovered from each rate group or "customer class," i.e.,
1 1 how the pie should be apportioned among the rate groups.
12 These rate groups or customer classes exist
13 because it is a universally accepted principle of
14 ratemaking that, "It is more expensive to serve some
15 customers than others." Charles F. Phillips, Jr., The
16 Regula tion of, Public Utili ties ( Public Utilities Reports,
17 1993), P. 435 (hereafter "Phillips"). Therefore,
18 customers are grouped into rate classes with roughly
19 similar cost characteristics, e.g., a residential class,
20 an industrial. class, etc. Very large customers-like
21 Micron, Simplot, and DOE on the Idaho Power system-are
22 typically each treated as a unique customer class unto
23 themselves, known in the trade as "contract customers."
24 The purpose of a cost of service study is to
25 allocate an appropriate portion of the utility's total
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1 revenue requirement to each of these customer classes
2 based primarily on cost causation principles.
3 Q.WHY is COST CAUSATION IMPORTANT?
4 A.Economists don't always agree on much, but on this
5 issue there is rare unanimity in the profession. While
6 the Commission can, and sometimes should, consider
7 factors other
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1 than costs, there are two primary reasons for focusing on.2 cost causation in creating the rate structure.
3 The first is "fairness," which basically refers
4 to the idea that customers should pay their own costs and
5 not someone else's.Furthermore, those who cause a
6 higher revenue requirement should pay an appropriate
7 share of the costs they cause, and vice versa.
8 The second reason, and probably the most
9 important to economists, is the "efficiency" rationale.
10 This is the idea that prices should promote the most
11 efficient possible use of the utility system. Thus,
12 those who use the system primarily when costs are high.13 should pay a rate that reflects those disproportionately
14 high costs so they will be encouraged to conserve or find
15 al ternati ve means of meeting their needs. And there is
16 an important, but out of favor, counterpoint here as
17 well. Those who consume in low cost periods should
18 recei ve an appropriate price signal to do so when
19 consumption is an economic plus for all.
20 Q.is THERE A SIMILAR AGREEMENT AMONG ECONOMISTS ON THE
21 PROPER METHOD OF DETERMINING COST CAUSATION?
22 A.Only to a degree. Some cost of service issues are
23 relatively non-controversial, but others are routinely
24 contentious, perhaps none more so than the proper method.25 of allocating peak and off peak costs.
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1 Q.WHY is THIS ISSUE SO CONTENTIOUS?
2 A.Very few practitioners in this field would argue
3 wi th the general view expressed in a basic regulatory
4 text:
5 Customers who use the service during the peak demand
period are more expensive to serve than off-peak
6 users. A basic factor in determining the size of a
utility plant is the peak demand. Therefore, it
7 costs less to serve those customers who use the
service without burdening the business as a
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whole by adding to the peak demand period. Further,
if off-peak usage is increased, the utility may
obtain a better utilization of its plant throughout
the day, thereby resulting in a larger total output
over which fixed costs may be spread.3
4 Phillips, P. 436.
5 But while there is little argument about the
6 general principle that on-peak usage should cost more
7 than off-peak, there are repeated disputes about the
8 manner of calculating the cost difference between peak
9 and off-peak usage. This issue is so significant that
10 cost of service methodologies are in fact named for the
11 manner in which they allocate costs between high load
12 factor and low load factor customers.
13 Q.WHAT DO YOU MEAN BY THE TERM "LOAD FACTOR?"
14 A.For the utility itself, "load factor" refers to the
15 relationship between the peak load on the system and the
16 average load. When applied to customers, the term "load
17 factor" refers to a customer's consumption related to a
18 utili ty' s peak sales. A customer with a high load factor
19 is one who consumes in a nearly steady state, both daily
20 and annually.' A low load factor customer consumes
21 electrici ty unevenly, generally in disproportionate
22 amounts either on the daily or monthly peaks, or both.
23 In general, a greater allocation of costs to peak periods
24 tends to benefit high load factor customer classes, while
25 a lesser allocation benefits low load factor customer
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1 classes.
2 It is important to point out a common
3 misconception here. If peak costs are appropriately
4 assigned, high load factor customers don't escape these
5 peak costs. After all, if a customer is consuming a
6 steady load 24/7, then it is on line during the peak, and
7 should get an appropriate share of those costs. The
8 benefit to high load factor customers of a properly
9 designed cost of service study is that they are also
10 online when costs are low, and therefore should get an
11 appropriate "credit" in their average rate.
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.1 Q.is THERE A SINGLE CORRECT METHOD FOR ALLOCATING PEAK
2 COSTS BETWEEN HIGH AND LOW LOAD FACTOR CUSTOMERS?
3 A.No, because a large component of peak costs consist
4 of what are known in economics as "j oint and common"
5 costs. Most of these j oint and common costs consist of
6 the capital cost of generating plants and transmission
7 facili ties that are used to some degree by all customers
8 throughout the year, both on and off peak. In the lingo
9 of the cost of service profession, these facilities
10 provide either "capacity" or "demand" (peak)" and
11 "energy" (off and on peak) services. Economic theory
12 alone cannot determine the correct method of assigning.13
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these costs to customer classes.
Having said that, however, it is worth noting
15 that many engineers and economists would argue for
16 assigning the bulk of the capital costs of generation and
17 transmission plant to customer classes in proportion to
18 their use on the highest single peak of the year, on the
19 grounds that these facilities are sized to meet this peak
20 demand. There are, however, some practical problems with
21 this approach, and most commissions don't weight single
22 peak costs as heavily as many members of these
23 professions would.
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Q.DOES THE IDAHO COMMISSION HAVE AN ESTABLISHED METHOD
OF RESOLVING THESE ISSUES IN IDAHO POWER RATE CASES?
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1 A. Yes. For roughly 25 years now, the Idaho Commission
2 has used what is known as the "Weighted 12 Coincident
3 Peak" ("W12CP") cost of service method to allocate costs
4 on the Idaho Power Company system. A short explanation
5 and history of this cost of service choice is necessary
6 to understand the issues in this case.
7 Wi th regard to the always controversial issue
8 of allocating. generating plant costs, the Idaho
9 methodology first classifies a percentage of generation
10 plant to "energy" based
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1 on the system load factor, which in this case is
2 approximately 59%. The remaining 41% is classified as a
3 demand cost.
4 It is important to point out that the language
5 employed by cost of service studies can lead to real
6 confusion here. When we talk about the classification of
7 generating costs to "energy," we are not talking about
8 actual "energy" costs, primarily fuel and related items,
9 that vary with the amount of energy consumed and are
10 directly assigned to the various customer classes based
11 on their actual, recorded energy usage. Instead, we are
12 talking about the amount, or percentage, of the fixed
13 capi tal costs of generating plants that don't vary with
14 usage, but are treated as if they did for cost of service
15 purposes.
16 Q.WHEN DID THE IDAHO COMMISSION FIRST ADOPT THE W12CP
17 METHOD?
18 A.The Idaho Commission first adopted the weighted
19 W12CP methodology in 1982 in Case No. U-1006-185. In
20 reviewing the cost of service studies before it, the
21 Commission found:
22 We find:' For the limited purposes for which we use
cost of service data in allocation of the revenue
requirement among the customer classes, Idaho
Power's weighted 12 coincident peak study may be
reasonably used to represent costs. Although there
could be improvements in both W12CP studies
presented in this case, the similarities in the
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1 resul ts obtained from both of them, which were the
best cost-of-service studies presented in this case,
show that we may use the Company's W12CP for the
next step of the rate allocation process.
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4 Order No. 17856, P. 13.
5 In 1987, in Case No. U-1006-265A, the
6 Commission again revisited cost of service issue in what
7 was probably the most intensive litigation of the issue
8 in the history of Idaho rate cases. The following quote
9 from the Commission's final order provides something of
10 the atmosphere of the proceedings:
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1 Idaho Power prepared five cost-of-service studies.
A Weighted 12 Coincident Peak (IPCo W12CP) study, a
12 Coincident Peak (IPCo 12CP) Study, an Average and
Excess Demand (IPCo AED) study, a Positive ExcessDemand (IPCo PED) study, and a Modified Posi ti ve
Excess Demand (IPCo MPED) study. In addition, the
Ci ty of Boise presented two variations of the
Company's W12CP called Boise I and Boise II. FMC
presented a modified weighted 12 coincident peak
(FMC MW12CP) study and a 7 coincident peak (FMC 7CP)study. The Staff presented an al ternati ve weighted
12CP (Staff W12CP) study and an unweighted 12CP
(Staff U12CP). The results of those studies are
shown on Table 6 on the following page. For the
reasons stated in the following pages of this Order,
we will use the Company's W12CP as a starting point
in our allocation of revenues among the customerclasses.
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11 Order No. 21365. Since the 1982 case, the Idaho
12 Commission has relied solely or primarily on the W12CP
13 method in every Idaho Power rate case.
14 Q. WHY DID THE COMMISSION CHOOSE THE W12CP METHOD IN
15 1982?
16 A.In the spectrum of possible cost of service
17 methodologies, the W12CP method assigns less cost to peak
18 periods than most. This made some sense at the time it
19 was first adopted. In the early 1980s, Idaho Power was
20 still predominantly a hydroelectric utility. It had two
21 base load coal plants, Jim Bridger and Valmy, but no
22 peaking plants analogous to today' s gas fired peakers.
23 Instead it met peak loads with its
24 hydroelectric. plants, which could adjust load almost.25 instantly to meet demand, plus power purchases and
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1 exchanges. These hydroelectric plants were (1)
2 relati vely cheap on a dollar per kilowatt of capacity
3 basis, (2) more heavily depreciated than more recent
4 plants, and (3) had variable energy costs close to zero.
5 The result was that actual peak costs did not
6 greatly exceed, and were sometimes below, base costs. In
7 this context, the Commission's choice of a cost of
8 service methodology that gave relatively little weight to
9 peak costs made considerable sense.
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1 Q. HAS THE IDAHO COMMISSION CONTINUED TO USE THE
2 WEIGHTED 12 CP METHOD IN RECENT CASES?
3 A.Yes. The 2005 and 2006 rate cases were settled
4 wi thout a specific cost of service determination, but in
5 the 2003 rate case the Commission again adopted the W12CP
6 methodology:
7 As we have in most rate cases, the Commission finds
the W12CP cost of service study is the appropriate
8 starting point to allocate costs to customer
classes. . . (W) e find that the W12CP cost of service
9 results reflect "a reasonable approximation of class
responsibility" and thus provide a measure of
10 relative revenue responsibility among the customerclasses.
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12 Order No. 29505, P. 46-47 (citations omitted).
13 Q. DOES IDAHO POWER FOLLOW THE WEIGHTED 12CP COST OF
14 SERVICE METHOD IN THIS CASE?
15 A.Mr. Tatum, Idaho Power's cost of service witness,
16 never quite says so explicitly, but his testimony clearly
17 implies that his "Base Case Study" follows the
18 traditional Commission approved methodology. It does
19 not. Mr. Tatum's Base Case in fact follows an
20 alternative methodology that was presented in the 2003
21 rate case, in which average costs were combined with the
22 weighted 12CP costs. This al ternati ve method was
23 discussed without comment in the Commission's order, and
24 ci ted in the appendix to the 2003 decision.
25 Mr. Tatum apparently assumes that this
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1 inclusion of the alternative method in the appendix
2 represents Commission approval. But this is clearly
3 inconsistent with the plain language of the Commission's
4 order accepting the W 12CP, as cited above. While I
5 cannot explain how or why the al ternati ve method found
6 its way into the appendix, I find it impossible to
7 believe the Commission meant to j ettison its consistent
8 practice of more
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1 than twenty years' standing without a single word of
2 comment in the order. This is doubly true when the plain
3 language of the order, and the resultant rate spread,
4 clearly adopts the normal weighted 12CP method.
5 Q.WHAT is THE EFFECT OF MR. TATUM'S USE OF THE
6 ALTERNATIVE METHODOLOGY?
7 A.This change has significant consequences for the
8 cost of service results because it shifts costs from peak
9 to off peak, and from low load factor customers to high
10 load factor customers, by disregarding actual peak costs.
11 Q.ARE THERE ANY OTHER DEFECTS IN THE IDAHO POWER COST
12 OF SERVICE STUDIES, BEYOND THE MISUSE OF THE W 12 CP YOU
13 DISCUSSED ABOVE?
14 A. Yes. As Mr. Tatum explains in his testimony at
15 pages 25-27, he weighted annual capacity costs based on
16 monthly peak hour deficits identified in the Company's
17 2006 Integrated Resource Plan (" IRP"). The months with
18 proj ected deficits include, reasonably enough, the months
19 of June-August and, less reasonably, December. But the
20 other two identified deficit months are May and
21 September. A~signing a disproportionate share of
22 capaci ty costs to these months is nonsensical on its
23 face.
24 Anyone at all familiar with Idaho Power's
25 system will immediately recognize that May and September
1723 PESEAU (Di) 36
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18
19
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1 are both off-peak months. In fact, April and May are
2 typically two of the lowest cost months of the year on
3 the Idaho Power system by a substantial margin. Yet
4 Idaho Power's cost of service studies treat Mayas a high
5 cost, peak month. This misidentification of peak months
6 is a very serious and consequential error.
7 Q.HOW DOES THIS ERROR OCCUR?
8
9 /
10
11 /
12
/
1724 PESEAU (Di) 36a
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.
.
.
1 A.The problem is that IRP identified load deficiencies
2 and off system purchases are not reasonable or
3 appropriate substitutes for actual system peaks.
4 Deficiencies can occur for a variety of reasons, not the
5 least of which is scheduled plant maintenance. For most
6 Northwest utilities, spring is the optimal time to take
7 plants down for maintenance because power demands are low
8 and hydropower generation is relatively high, making
9 replacement power relatively (and sometimes very) cheap.
10 The fall months are, of course, the next best time to
11 take plants down. Somewhat similar considerations apply
12 to power exchanges and a host of other factors.
13 Q. HOW DOES THIS WEIGHTING ERROR AFFECT THE COST OF
14 SERVICE RESULTS?
15 A.When combined with the misuse of W 12 CP method, it
16 doubly corrupts the results, and once again the result is
17 an erroneous transfer of costs from on-peak to off-peak.
18 Q.IS THERE ANOTHER WAY TO ILLUSTRATE YOUR CONCLUSIONS
19 THAT MR. TATUM'S COST OF SERVICE RESULTS ARE IN ERROR?
20 A.Yes. Graph No.1, below, compares Idaho Power's
21 power supply model's variable or marginal energy costs
22 wi th the average variable or marginal costs contained in
23 its unweighted allocators. Graph No. 2 compares the
24 combined marginal monthly energy and capacity costs for
25 the model and the annual average marginal monthly energyand capacity costs.
1725 PESEAU (Di) 37
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.i
2 Monthly Impld E..rgy Costs
3 120
4 100
5
80
6
7 l 60 11===twe~1
I;8 40
9
20
10
011 J F M A M J J A S 0 N 0
Iln'"12.13
14
Monhly "'lJlid Powr Suppl Costs
15
140
16
120
1 7
10018
8019
l 1= :=ll.We~hml2060
21 40
22 20
23
0
24 J F.M A M J J A S 0 N 0
Meth.25
1726 PESEAU (Di)38
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1 These graphs show that, by Idaho Power's own
2 power supply model estimates, monthly energy costs range
3 from a low of about $52/mwh in June to a high of $100 in
4 July. Similarly, total monthly power supply costs vary
5 from about $56/mwh in April to a high of $120 in the
6 month of July. This seasonal cost information is crucial
7 in a cost of service study in order to ensure that rates
8 in effect reflect costs allocated to these seasons.
9 But in its proposed cost of service studies,
10 Idaho Power chooses to assume that monthly power supply
11 costs do not vary significantly month-to-month, as is
12 shown in each of the above graphs as a horizontal line,
13 when it averages this with a truly weighted allocator.
14 The Company's. study is misleading because it claims to
15 use the historical method of computing the W12CP, when in
16 fact it does not. Instead, the Company uses a modified
17 allocator that averages out seasonal cost differences.
18 Choosing entirely new inputs for the model is not a
19 legitimate "Base Case" scenario.
20 Idaho Power further compounds this error by
21 treating low cost months of May and September as if they
22 were peak months. But as Idaho Power's own testimony
23 notes, these are in fact low cost months because there is
24 very little demand for space heating or air conditioning.
25 As the Company further acknowledges, it is in fact the
1727 PESEAU (Di) 39
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18
19
20
21
22
23
24
25
1 summer months of June-August that are "the Company's most
2 expensive time to provide power." Testimony of Darlene
3 Nemnich, P. 5, L. 16-19.
4 Q.PLEASE SUMMARIZE THE CONSEQUENCES OF IDAHO POWER'S
5 COST OF SERVICE ERRORS THAT DILUTE ITS ACTUAL SEASONAL
6 COST DI FFERENCES .
7 A.There are two chief consequences. First, high load
8 factor customers are allocated a larger share of costs
9 than they actually cause the power system to incur.
10 Conversely, low load
11
12 /
13
/
1728 PESEAU (Di) 39a
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1 factor customers are charged too little. This is not.2 only unfair; it is also terribly inefficient because it
3 creates cross subsidies between rate classes.
4 A corollary to this consequence is the
5 undesirable effect that the misallocation has on the
6 valuable conservation and load management programs in
7 place and being developed here in Idaho for everyone's
8 benefi t. By proposing to set rates that undercharge
9 summer peak costs and overcharge during low cost seasons,
10 the proposed rates act in direct contradiction to
11 responsible efforts to conserve energy when it is most
12 costly. In the longer-term, costs of service will be.13 higher for all customers because peak loads will grow
14 faster that average energy consumption.
15 Q.DO THE IDAHO POWER SYSTEM PLANNERS RECOGNIZE THIS
16 RISK?
17 A.Yes. The perils of promoting on-peak load growth
18 are discussed on page 1 of Mr. Greg Said's workpapers
19 from the last rate case, from which I quote an excerpt:
20 Effect of Load Growth. Peak load in the Idaho Power
Company service territory is growing twice as fast21 as the annual energy requirement. Going forward,
then, this growth will lead to higher ramp rate22 requirements in the summertime and less available
hydro capacity for managing the system. The cost of23 reserves would then likely increase, which could
increase the integration cost for wind.
24.25 Page 1 (emphasis added).
1729 PESEAU (Di) 40
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20
21
22
23
24
25
1 Idaho Power's proposal to adopt seasonal
2 pricing that charges more in the June-August period for
3 virtually all rate schedules is further evidence that it
4 understands the growing peak problem. But it makes no
5 sense to shift an enormous amount of costs off peak and
6 then try to somehow counter that effect by imposing
7 seasonal pricing. In effect, Idaho Power's cost of
8 service department is working at cross purposes with its
9 rate design department.
10
11 /
12
13 /
14
15 /
16
17
18
19
1730 PESEAU (Di) 40a
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1 Q.YOUR CRITIQUE THUS FAR HAS FOCUSED ON THE "BASE
2 CASE" IDAHO POWER STUDY. DO YOU HAVE AN OPINION ABOUT
3 THE OTHER TWO IDAHO POWER COST OF SERVICE STUDIES?
4 A.Yes. I think all parties are in agreement that the
5 treatment of PURPA resources contained in the "Modified
6 Base Case" study is appropriate, so I don't propose to
7 address that issue. Instead, I will focus on Mr. Tatum's
8 "preferred" cost of service methodology, 3CP/12CP, which
9 is a potentially acceptable method, but flawed in two
10 respects.
11 Q.WHAT IS YOUR PROPOSED COST OF SERVICE SOLUTION?
12 A.I propose the adoption of Mr. Tatum's 3CP /12CP
13 method, but with a proper treatment of base load and
14 intermediate load plants. This method would
15 appropriately treat Idaho Power's summer peak loads, and
16 send the proper economic signals to customers.
17 As I explained earlier, there was a rational
18 basis for the Commission's original decision 25 years ago
19 to choose a cost of service methodology that minimized
20 the influence of peak costs. But this is no longer Idaho
21 Power's situation, and hasn't been for some time, as we
22 can see in the steady decline in Idaho Power's load
23 factor from 68% in 1994 to 59% a dozen years later. All
24 of us who participate in these cases, including myself,
25 have been too slow to recognize this dramatic change.
1731 PESEAU (Di) 41
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1 Peaking costs are now driving costs higher for everyone,
2 to the detriment of all. So we should be looking to
3 adapt our cost of service to recognize these changes,
4 rather than vice versa.
5 Q.PLEASE EXPLAIN THE CHANGE YOU ARE PROPOSING TO THE
6 COMPANY'S RECOMMENDED 3CP /12CP STUDY?
7 A.Simply put, Idaho Power chooses a peculiar means of
8 conducting its 3CP /12CP cost of service study. It is
9 not, in my opinion, a study that is guided by the
10 Electric Utility Cost
11
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
1732 PESEAU (Di) 41a
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1 Allocation Manual published January 1992 by NARUC, as Mr.
2 Tatum suggests. Testimony of Tim Tatum, P. 6, L. 4-8.
3 The reason the choice of study is peculiar is
4 because it is in direct conflict with the very real
5 problem identified in numerous places in Idaho Power's
6 filing, that is, the problem of the Company's excessive
7 peak load growth, which is causing deterioration in the
8 system load factor. In Mr. Tatum's words:
9 "...In recent years, the Company's system peak has
grown at a much faster pace than average demand, a
trend that is expected to continue into the future.
For example, a comparison of Figures 4-1 and 4-2 on
pages 39 and 40 of the 2006 IRP (included in my
workpapers) will show that by 2012, the Company
expects an energy deficit in July of approximately
150 aMW with a peak hour deficiency of almost 600 MW
in the same month..."
10
11
12
13
14 Testimony of Tim Tatum, P. 24, L. 12-19.
15 Despi te this observation, Mr. Tatum deliberately uses a
16 cost of service method that treats baseload generation
17 peak capacity and energy costs as predominantly off peak
18 energy costs. The intended or unintended consequence of
19 this method is to communicate to customers that summer
20 capacity and energy usage is much cheaper than it
21 actually is. . This misallocation naturally under prices
22 summer usage rates, stimulating summer consumption.
23 Q.WHY DO YOU CONCLUDE THAT MR. TATUM" S PROPOSED
24 3CP/12CP METHOD PROMOTES SUMMER PEAK USAGE?
25 A.Mr. Tatum's attempts to deal with the summer peak
1733 PESEAU (Di) 42
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1 load problem by using a 3CP allocator to allocate the.2 cost of peaking facilities.This is a rational approach,
3 but Mr.Tatum makes two errors in the implementation of
4 this method.
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8 /
9
10 /
11
12
13.14
15
16
17
18
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21
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24.25
1734 PESEAU (Di)42a
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1 The first error is that Mr. Tatum mistakenly
2 treats Idaho Power's hydro facilities as entirely
3 baseload. However, it is commonly known that the Hells
4 Canyon complex and most of the Pacific Northwest hydro
5 system is used to "follow load," that is to store as much
6 hydro as possible for use in the peak periods, because
7 hydro is used most economically to displace the highest
8 variable cost peaking facilities.
9 Mr. Tatum does not classify Idaho Power's hydro
10 facili ties to summer peaks, but instead to his baseload
11 classification. I correct this in my proposed study by
12 allocating Idaho Power's hydro on the basis of 50%
13 capacity or peaking and 50% to baseload. These
14 facilities would be classified nearly 100% to peaking
15 were it not the case that some of Idaho Power's upstream
16 hydro facilities are essentially run of the river.
i 7 The' second major departure from accepted cost
18 of service principles is found in Mr. Tatum's "double
19 allocation" of baseload steam production to energy.
20
21
Q.PLEASE EXPLAIN.
A.Mr. Tatum commits a classification error when he
22 labels over 59% of baseload generation plant costs as
23 energy related, then goes on to allocate the remaining
24 41% of baseload plants costs over a period of 12 months,
25 based on 12 coincident peaks. Use of Mr. Tatum's 12CP
1735 PESEAU (Di) 43
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20
21
22
23
24
25
1 allocator has the effect of spreading this additional 41%
2 of capacity or demand costs essentially on an energy
3 basis. The NAUC Cost Allocation Manual referenced by Mr.
4 Tatum makes this point quite succinctly:
5 "This method (meaning the 12CP) is usually used whenthe monthly peaks lie wi thin a narrow range; i. e.
6 when the annual load shape is not spiky..."
7 NARUC Manual, P. 46.
8
9 /
10
11 /
12
13 /
14
15
16
17
18
19
1736 PESEAU (Di) 43a
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1 Stated another way, the 12CP method is completely
2 inappropriate for a strongly peaking utility like Idaho
3 Power. Furthermore, it is disingenuous for Mr. Tatum to
4 lament the rapid growth in the spikiness of summer peak
5 demand, when his preferred cost of service study
6 maximizes the. amount of summer peak costs pushed out of
7 the summer peak period into off peak seasons. We can see
8 this very clearly in the ul timate results of his 3CP /12CP
9 study, which in fact shifts more costs off peak than the
10 flawed modified base case I described earlier. In short,
11 Mr. Tatum is headed in precisely the wrong direction.
12 Q.ARE THERE TANGIBLE, NEGATIVE CONSEQUENCES FOR ALL
13 RATEPAYERS ASSOCIATED WITH MR. TATUM'S NOVEL COST OF
14 SERVICE STUDY?
15 A.Yes. In allocating summer peak capacity and energy
16 costs to off peak seasons, rates for summer usage will be
17 too low, and rates for non-summer usage will be too high.
18 But this problem does not balance out. The reason it
19 does not balance out is that the underpricing of summer
20 usage will promote more summer usage and require Idaho
21 Power to invest more heavily than otherwise in new
22 peaking facilities and DSM programs. The Company of
23 course earns a return on these programs but, as a result,
24 all ratepayers' rates are higher.
25 Q.IS THERE A STRAIGHTFORWARD FIX TO MR. TATUM'S STUDY
1737 PESEAU (Di) 44
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23
24.25
1 THAT DOES NOT INVOLVE THE INTRODUCTION OF A COMPLETELY
2 DIFFERENT COST OF SERVICE APPROACH?
3 A.Yes. Mr. Tatum has correctly identified the summer
4 peak load problem, but then he paradoxically produces a
5 resul t that further understates peak costs. We can
6 restore some degree of peak responsibility back into the
7 summer period' by modifying his study to:
8 1. Classify 50% of hydro facilities to peak or
9 CP and 50% to the 12CP.
10
11 /
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13 /
14
15 /
16
17
18
19
20
21
22
i 738 PESEAU (Di) 44a
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1 2. Classify 100% of steam production facilities to
2 capacity and demand using the 12CP method.
3 While further empirical investigation is needed
4 to improve the study, making my recommended corrections
5 will both help reduce or eliminate Idaho Power's
6 deteriorating system load factor, and reduce the need
7 for, and the costs of, peaking facilities. These
8 corrections will also vastly improve the allocations made
9 to on peak and off peak seasons and provide all customers
10 wi th rates that reflect their respective costs of usage
11 and consumption.
12 Q.HAVE YOU CONDUCTED A COST OF SERVICE STUDY THAT IS
13 CONSISTENT WITH YOUR RECOMMENDATIONS?
14 A. Yes. My study is attached as Exhibit No. 707.
15 PLEASE BRIEFLY SUMMARIZE THE RESULTS OF YOUR COST OFQ.
16 SERVICE STUDY.
17 A.The following table compares the results of my study
18 with those adopted by this Commission in 2003 and the
19 three proposed Idaho Power cost studies. In this
20 presentation, results below one are below cost of
21 service, and results above one equate to an over
22 recovery:
23
24
1739 PESEAU (Di) 45
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1 Return Indexes Peseau/2003 Tatum Base Tatum Tatum.Micron Case Mod.RECOMM
2 Base.ENDED
CP/12CP
3
Residential (1)1. 12 1. 1 1.23 1. 21 1. 18
4 Gen Service (7)1. 04 1. 1 1. 04 1. 05 1. 04
Gen Service (9 )1. 1 1. 2 1. 01 1. 03 1. 025Industrial( 19)1. 08 1.2 .79 .86 .83Irrigation(24).35 .17 .51 .46 .60
6 Micron (SC).93 1. 4 .40 .53 .51
DOE .93 1.2 .49 .62 .51
7 Simplot .99 1. 5 .47 .61 .57
8
9 /
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11 /
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13 /.14
15
16
17
18
19
20
21
22
23
24.25
1740 PESEAU (Di)45a
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1 Q.WHAT DOES THIS COMPARISON SHOW?
2 A.My cost of service study in this case, in contrast
3 to Idaho Power's three cost of service studies, is
4 generally much more consistent with results found to be
5 valid by the Commission in the last contested 2003
6 general rate case, and is more reflective of the
7 reali ties and challenges Idaho Power is facing.
8 In evaluating this data, the Commission should
9 be aware that because of the way the cost of service data
10 is presented, we could not back out the $25 million
11 overstatement of net power supply costs I identified
12 earlier in my testimony. If we could, it would
13 significantly' improve the results for high load factor
14 customers, particularly the three contract customers.
15 Q.HOW DO YOU PROPOSE THAT THIS COMMISSION ALLOCATE
16 REVENUE REQUIREMENT TO THE VARIOUS RATE CLASSES IN THE
17 LIGHT OF THESE COST OF SERVICE RESULTS?
18 A.My recommended cost of service study shown in
19 Exhibit 707 suggests that the conclusions reached by this
20 Commission many times on the matter of rate spread still
21 largely hold true. A fair conclusion is that the
22 residential class and the industrial classes, including
23 special contract customers are all near or below an
24 average rate of return, meaning that their respective
25 rates exceed their cost of service. Irrigators remain
1741 PESEAU (Di) 46
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1 well below an average rate of return. Gi ven my
2 conclusion that Idaho Power's rates should be reduced,
3 that reduction should be spread to the customer classes
4 whose results are furthest above unity, i. e., the
5 residential and industrial classes.
6 Q.DOES THIS CONCLUDE YOUR TESTIMONY?
7 A.Yes.
8
9
10
11
1742 PESEAU (Di) 46a
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.1
2 open hearing.)
(The following proceedings were had in
COMMISSIONER SMITH: Now we're ready for
4 cross-examination. Mr. Olsen, do you have questions?
3
5
6
7 Ward.
8
MR. WARD: Oh.
COMMISSIONER SMITH: Oh, I'm sorry, Mr.
MR. WARD: One more thing, if I may. I
9 would like to do just one bit of live rebuttal in
10 response to something that took place yesterday.
.
11
12
13
14
15 BY MR. WARD:
COMMISSIONER SMITH: All right.
DIRECT EXAMINATION
( Continued)
Dr. Peseau, were you in the Hearing Room
17 when Mr. Walker cross-examined Mr. Hessing?
19
16 Q
I was.
Okay. Mr. Walker, and obviously, it's
20 difficult to get this question exactly correct, but
18 A
21 Mr. Walker asked Mr. Hessing whether Mr. Said's Exhibit
Q
22 50 has anything to do with peak costs and Mr. Hessing
23 replied no. Do you recall that question and answer?
24.25
A
Q
Yes, I do.
And this, as I say, was in reference to,
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20
i or if I didn't say so before, this was in reference to,
2 my cross of Mr. Said on his Exhibit 50. Is Mr. Hessing
3 correct that Exhibit 50 and the cross-examination that we
4 had the other day on that matter has nothing to do with
5 peak costs?
6 A No, I think that's an overstatement. I
7 can see why he was able to answer that way, but the crux
8 of the issue is whether or not the June period marginal
9 energy costs are low when June in fact is a peak period,
10 and if I can just refer to Mr. Tatum's Exhibit 59, page
11 5, that is clearly a cost and demonstrates the point.
12 Q Okay; so would it be correct to say that
13 Mr. Tatum' s exhibit repeats exactly the way not
14 exactly the same numbers, but repeats the same relative
15 weighting that appears in Exhibit 50; that is, June
16 appears to be, if you would believe the marginal
17 weightings he has, the lowest marginal weighted month
18 when it's in fact a peak month?
19 A That's correct.
MR. WARD: That's all I have and
21 Dr. Peseau is now available for cross.
22 COMMISSIONER SMITH: Okay, thank you.
23 Mr. Olsen.
24
25
MR. OLSEN: Yes, thank you, Madam Chair.
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1 CROSS-EXAMINATION
2
3 BY MR. OLSEN:
4 Q Dr. Peseau, I've seen you sit through
5 these hearings and one of the common themes as it relates
6 to the issues in the cost of service testimony that we've
7 heard so far is the issue of assigning proper
8 responsibili ty for the cost of growth on the system; is
9 that a fair statement?
10 A I've heard that, yes.
11 Q Okay. Now, you take issue with the
12 Company's cost of service study, do you not?
13 A Yes, I do.
14 Q Okay, and if I could direct you to page 29
15 of your direct testimony down beginning on line 20.
16 A On line 20?
17 Q Yes, starting on line 20 there.
18 A Yes.
19 Q You talk about why cost causation is
20 important and. you outline basically two reasons, fairness
21 and efficiency. Now, with respect to the client that you
22 represent, Micron, you've testified that it's a high load
23 factor customer; correct?
24.25
A Correct.
Q Okay, and the effect of the proposed cost
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1 of service study by the Company, the 3CP /12CP, you claim
2 unfairly, I guess, biases high load factor customers by
3 allocating more on energy rather than on capacity; is
4 that a fair assumption?
5 A Well, that's one side of the coin. The
6 other way to look at it and then perhaps it would be
7 clearer, I think we heard some technical explanations
8 yesterday on how it gets translated from demand to energy
9 which is pretty frankly difficult to understand. You've
10 got system load factors, you've got 12 months CP' sand
11 all the things that go into that and it's not real clear.
12 Another way to look at it and I think perhaps a clearer
13 way for the Commission is that the Company's cost of
14 service study allocates all costs that occur in the peak
15 period of summer some percentage of all these costs into
16 the non-peak period, and that's where the trouble begins
17 wi th all the growth in the peak that we're experiencing
18 and the improper price signals telling all consumers,
19 Micron included, whoever consumes during the summer ought
20 to pay that cost and they're not under the Company's
21 study.
22 Q Wi th respect to a cost of service study,
23 it bases or looks at the various customer classes based
24 on a test year; is that correct?
25 A Correct.
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1 Q Okay, and so that's a static look at what
2 the class components make up for that point in time; is
3 that correct?
4 A It's static in a sense, but in this case
5 the Company has introduced and I think all parties have
6 to some degree gone along with certain more
7 forward-looking aspects of this to get to what you could
8 call a static test year, but there are a lot of
9 adjustments to get there, so I think static may be a
10 Ii ttle bit overstated, but it's certainly a snapshot in
11 time.
12 Q . Okay; but they've tried to model it to
13 look forward and anticipate costs; is that fair?
14 A Yes, in excess in my mind, but yes.
15 Q Now, Mr. Yankel has put forward -- have
16 you looked over the testimony of the irrigator expert
17 Mr. Yankel?
18
19
A It's been awhile, but yes.
Q Okay. We've put forward an adj ustment to
20 the cost of service study that tries to look forward and
21 anticipate growth in classes making up the Idaho Power
22 load. What's the difference between that methodology
23 trying to look at forward looking and what the Company
24 has done in its current study?
25 A Well, there's a lot of difference,
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1 frankly. A proper cost of service study attempts to view
2 various periods of time in which costs are incurred, high
3 costs or low costs, and the exercise we perform with our
4 marginal costing and embedded costing is to ask during a
5 particular time, August peak period, who's consuming, who
6 is on peak and who's not, and whether that's a new
7 customer, an old customer, anyone of those customers has
8 the option to some extent, depending on elasticities and
9 I realize there are limits to shifting demand, but any
10 customer who's consuming on peak, whether they're new or
11 whether they've grown or not should bear that cost and
12 that's different than trying to go back and identify and
13 in a sense vintaging who has grown or who hasn't and even
14 if that party, irrigators, for example, who probably have
15 less ability to shift during the peak, whether they can
16 shift or not, the economic solution is still to charge
17 them what they impose on the system, so there's a good
18 deal of difference between customer growth and growth in
19 system demand.
20 Q You participated in the '03 rate case;
21 correct?
22 A I did.
23 Q And previously in this hearing I just
24 pointed out that the irrigation class has more or less
25 been flat. Although there's some changes and moving
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1 there, it's not growing relative to the other customer
2 classes on the system.
3 A That's correct.
4 Q Okay; so when you talk about fairness and
5 cost causation, isn't there something inherently unfair
6 wi th the fact that although we're on peak, we should get
7 our fair share of those costs, but other classes are
8 causing the growth on the system and, therefore, the need
9 for more of these peaking resources?
10 A Well, that's all true, but in the end, we
11 have an embedded cost determination and the test year
12 concept is to determine what our capacity mix is, peakers
13 and base load to intermediate, determine the cost and
14 then attribute those costs, both energy and capacity, to
15 the time period in which they incur, and so it's not
16 unfair to charge anyone who hasn't grown or has grown any
17 differently. I think that would be discrimination. They
18 are indeed undeniably if you do your cost of service
19 study correctly and allocate costs to peak periods
20 correctly, they are imposing that cost on the system,
21 both capacity and energy, and I think in fairness it goes
22 to who pays the right price at the right time.
23 Q Are you familiar with the testimony of
24 Keith Hessing, Staff witness Keith Hessing, in this
25 matter?
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20
21
1 A Yes.
2 Q He characterized the fact that there were
3 certain, what he characterized, spill-over costs. He
4 says the cost of growth is not fully, and hopefully I'm
5 fairly characterizing this, but he says that the cost of
6 growth is not fully being borne by the customer classes
7 that are causing it and, therefore, other classes bear
8 the rest of the burden; is that fair?
9 A Yes, and that point I make in my testimony
10 as well.
11 Q That's right, and you make that point as
12 well.
13 A Yes.
14 MR. OLSEN: Okay, no further questions,
15 Your Honor.
16 COMMISSIONER SMITH: Thank you, Mr. Olsen.
17 Mr. Purdy.
18 . MR. PURDY: I have no questions.
19 Thanks.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: I have a couple,
22 Madam Chair, thank you.
23
24
25
CSB REPORTING
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1750 PESEAU (X)
Micron Technology
.
.
1 CROS S - EXAMINAT I ON
2
3 BY MR. RICHARDSON:
4 Q Dr. Peseau, would you refer to page 43 of
5 your direct testimony?
6 A I'm there.
7 Q At the top of that page you're referencing
8 what you call errors that Mr. Tatum made in dealing
9 with -- in his attempts to deal with the Company's summer
10 peak problem. You state that first, he treats hydro
11 facilities as entirely base load and to correct this, you
12 recommend that the Company's hydro resources be allocated
13 50 percent capacity and 50 percent base load.
14 Dr. Reading recommends a split of 75 percent capacity and
15 25 percent energy. Would Dr. Reading's solution to this
16 problem be acceptable to you?
17 A Well, yes, I think it would because, you
18 know, historically, we find that hydro, a hydro system is
19 best utilized economically by following load, by being
20 available and shifting that energy to periods in which
21 both (inaudible) and seasonally and we can do that to
22 some degree in the Northwest. It's really an empirical
23 question and shouldn't be determined frankly on someone' s
24 opinion of 50 percent or 75 percent or, you know, zero.25 percent as the Company does. There are ways we should
CSB REPORTING
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1751 PESEAU (X)
Micron Technology
.
.
.
1 look at that and mine was just simply, a 50-50 was a
2 start at that and I think traditionally, 75 percent-25
3 percent has been more accurate. The trouble is I can't
4 state that today that that's the most accurate. It
5 certainly is something in that ball park.
6 Q So Dr. Reading's approach would be a
7 reasonable approach in your opinion?
8 A Yes.
9 Q Now, the second of Mr. Tatum's errors that
10 you discuss is what you call double allocation of base
11 load steam production to energy. Could you please define
12 for me what you mean by double allocation?c
13 A Well, Dr. Goins did an admirable job, I
14 think, touching on this and it's very complicated. I
15 don't know why anyone would want to wade through this and
16 try to understand it, but what happens in the Company's
i 7 study, and, again, I think bottom-up is a good method, is
18 that you lose track of what you're doing. Historically,
19 in Idaho, and I've been doing these studies since the
20 early' 80s here, we did all basically go along with this
21 59-41 percent and as I discuss in my testimony, under
22 some circumstances you can continue to do it. Dr. Goins
23 pointed out it's not empirically verifiable, it's just
24 not, but it's an acknowledgment of the fact that base
25 load can be some energy and some capacity.
CSB REPORTING
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1752 PESEAU (X)
Micron Technology
.
.
1 If we do that, come up with some method of
2 defining total plant costs as capacity and energy, then
3 the mistake is to go and allocate it on a 12CP which is a
4 means of spreading this cost out. Dr. Goins
5 characterized it as spreading it in fact, really, to
6 energy and that's kind of hard to understand, but I think
7 it's easier to understand if we say what goes on here is
8 that we're taking capacity costs. All plant, base load
9 included, is built, first of all, for the peak period.
10 It's used in the off peak period, but the cause of that
11 is peak period.
12 Once we do that, then the 12CP allocates
13 if you want to call it energy, that's fine, but what it
14 really does that's wrong is allocates costs out of the
15 peak period, whether they're energy or capacity, whether
16 it's 49 percent or 50 percent or whatever it is, it takes
17 them out of the summer period and treats them as though
18 they're off peak costs and they're not, and what happens
19 when you do that is you lower the price during the summer
20 peak period and you raise it in the off peak period which
21 can't be good for a system that has a peak load growth
22 twice its average. It just doesn't make sense.
23 Q And Dr. Peseau, were you in the room
24 yesterday when Staff witness Lobb was on the stand?.25 A Yes.
CSB REPORTING
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1753 PESEAU (X)
Micron Technology
.
.
1 Q And do you recall generally his
2 cross-examination on the CWIP in rate base issue?
3 A Yes.
4 Q And did you hear him explain that the
5 Company's relicensing expenditures for Hells Canyon are
6 different from other resource expenditures because the
7 hydro complex is currently operating and used and
8 useful?
9 A I did hear that.
10 Q But you're not recommending the Commission
11 allow CWIP in' rates; correct?
12 A No. For different reasons, but no, I'm
13 not.
14 Q But you're not denying that Hells Canyon
15 is used and useful, are you?
16 A No.
17 Q And then finally, you've offered two
18 recommendations for changes in the Company's cost of
19 service study on pages 43 and 44. Is it your belief that
20 these two recommendations will fix what you term a badly
21 flawed cost of service study or are there other
22 problems?
23 A No, unfortunately , it seems like the
24 parties in this case rather than advancing the more.25 tradi tional way of doing this that used to be supported
CSB REPORTING
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1754 PESEAU (X)
Micron Technology
.1 by the Company have tried to fix the Company's study and
2 I've made a couple of fixes, Dr. Goins made some others,
3 Dr. Reading made some others and that's all I could do.
4 I tried to put it back as best I could and I agree with
5 Dr. Goins' conclusion that I really don't think the
6 Commission ought to pick my study over anybody' s study.
7 I think it's going to cause something that's unintended.
8 For example, the Company's study asks to increase
9 Micron's rates by 15 percent and that's only because they
10 capped it.
11 If they don't cap it in this and
12 subsequent cases, they're going to be recommending for.13 high load factor customers rate increases of 250 percent
14 times the average; in other words, the Company is asking
15 for 9.8 percent in this case. The unconstrained, you
16 know, the true cost of service that comes out of the
17 Company's says Micron's rate should go up by 25 percent.
18 Go back to the 2003 case and the Commission recognized
19 that Micron should have a three percent rate increase
20 when overall ~verage was five percent and that's what's
21 baffling to high load factor customers is they went from
22 below average rate increases to 250 percent and I'd hate
23 to see that happen and I'm not saying my study is perfect
24 or anybody else's, but I sure thought it was appealing,.25 Dr. Goins' suggestion that we may want to go across the
CSB REPORTING
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1755 PESEAU (X)
Micron Technology
.
.
.
1 board.
2 If you look at the 2003 study, an
3 across-the-board increase is fair, very close to -- if I
4 can refer, if people have my testimony, to page 45 of my
5 testimony. There I have a table and the purpose of this
6 table is to show why there's such spirit behind the high
7 load factor customers' testimony in this case criticizing
8 the Company's study. The 2003 case found these numbers,
9 which with one exception, all surround the number one.
10 One would be unity. If my class, if Micron is paying 100
11 percent of cost of service, exactly the right rate, that
12 number would have been 1.0. If it was below one in the
13 2003 case Order, not me, found the irrigation at .17,
14 that means they're not paying 100 percent, and on that
15 basis, the Commission gave the industrial high load
16 factor customers slightly below average and they capped,
17 and I think that was fair to cap it, the irrigation rate
18 at 13.95 percent, I think it was, and I can tell you from
19 doing these cost of service studies in Idaho on the Idaho
20 Power system that the 2003 case was not unique.
21 All prior cases that I can remember since
22 the early '80s found this rough relationship, that is,
23 residentials are paying close to what they should be,
24 everyone is, except irrigation, and I think in reading
25 last night the 2003 Order, the Commission recognized that
CSB REPORTING
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1756 PESEAU (X)
Micron Technology
.
.
.
1 and that's been the basis, frankly, I think for the 2005
2 and 2007 settlements to have roughly an equal percent
3 across the board. What's baffling if you look at the
4 three cases proposed by Mr. Tatum is that the high load
5 factor customers -- residentials stay about the same, but
6 the high load factor customers go from about one or over
7 one in every case to half and that's where we get the
8 recommended 250 percent of average rate increase and the
9 whole point of belaboring this is to say that this
10 decision on cost of service is huge and it really stands
11 to do some dislocations that I don't think the Commission
12 wants to do given the fact that everyone is criticizing
13 everyone else's study and maybe this is a good time to
14 have an across-the-board percentage increase. Sorry for
15 the long answer.
16 Q So in addition to endorsing Dr. Goins'
17 recommendation for a uniform percent increase across the
18 board, do you have any thoughts on his recommendation
19 yesterday that the Commission retain an independent third
20 party to examine the cost of service issues?
21 A Workshops haven't worked. You know,
22 everyone is an advocate, unfortunately, and I'd go along
23 with it. I don't know how it's carried out, frankly.
24 There are -- almost any consulting firm you would find,
25 you know, may be claimed to be objective, but they're
CSB REPORTING
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1757 PESEAU (X)
Micron Technology
.
.
1 coming from a particular point, so I'm not sure, but I
2 think that's the only al ternati ve I can think of is to
3 somehow agree ahead of time so that no one can cook the
4 books to a consulting firm that we all have some
5 confidence in and let the dice roll.
6 MR. RICHARDSON: Thank you, Madam Chair.
7 That's all I have.
8 COMMISSIONER SMITH: Thank you, Mr.
9 Richardson. ~r. Bruder, do you have questions?
10 MR. BRUDER: Just a couple, if I may,
11 Madam Chairman.
12
13 CROSS-EXAMINATION
14
15 BY MR. BRUDER:
16 Q Going a little bit further with some of
17 the things that Dr. Goins said from the stand yesterday,
18 he stated yesterday that as a practical matter, something
19 in the range of 80 percent of all of the Company's costs
20 are classified in such a way as to cause them to be
21 allocated among ratepayer classes on the basis of
22 year-round usage rather than on the basis of peak usage.
23 Does that approximate 80 percent figure that Dr. Goins
24 put forward, is that in the realm of what you think the.25 number is?
CSB REPORTING
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1758 PESEAU (X)
Micron Technology
1 A Yes , it's astoundingly high for a system.2 that's become capacity constrained.
3 Q Okay, and I believe at least some of this
4 has been addressed, but I'll ask the tie-up question,
5 would you please explain why it is, if it is why it is,
6 both illogical and detrimental to classify and then to
7 allocate the Company's costs in that fashion?
8 A I think Dr. Goins and I were coming at
9 this issue slightly differently. Whenever you take a
10 peak period cost, whether it's energy or capacity, and
11 spread it, you know, they say it's weighted, but it's
12 weighted over 12 months which means you're giving weight.13 to capacity costs, for example, that are caused by the
14 summer peak, you're counting it as if it's needed all
15 year and that has the effect, the same smoothing effect,
16 against seasonal prices or seasonal costs as an energy
17 allocator, so they're somewhat equivalent and that's
18 where I was responding to someone' s question, I can't
19 remember, that whether you call it an 80 percent energy
20 or 20 percent, they are undeniably moved out of the peak
21 period, costs that you can verify in the Company's books
22 that are incurred in the summer and you're taking them by
23 allocating, by some new means allocating, them to the off
24 peak period and that has the effect of an energy.25 allocator.
CSB REPORTING
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1759 PESEAU (X)
Micron Technology
.1 Q Okay, and you mention, too, that there is
2 some weighting in the CP' s over the year. It has been my
6 A
3 understanding in the methodology that is presently
4 recommended by the Company those weightings have been
5 removed; is that not so?
7
8 further.
9
10
11
That's correct.
MR. BRUDER: Okay, thank you. Nothing
COMMISSIONER SMITH: Thank you.
MR. BOEHM: No questions, Your Honor.
COMMISSIONER SMITH: Mr. Miller, do you
12 have any questions?.13
14 Madam Chairman.
15
16
17
18
19
20 BY MR. HOWELL:
21
22
23
Q
A
Q
MR. MILLER: No questions. Thank you,
COMMISSIONER SMITH: Mr. Howell.
MR. HOWELL: I do have a few questions.
CROS S - EXAMINAT ION
Good morning, Dr. Peseau.
Good morning.
On page 25 and 26 of your testimony, you
24 discuss comparisons in key components related to the.25 return on equity analysis between the last rate case and
CSB REPORTING
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1760 PESEAU (X)
Micron Technology
.
.
.
17
1 this case. Didn't you conclude after performing that
2 analysis that no increase above the 10.25 percent return
3 on equity is justified or necessary?
4 A This section of my testimony goes to Dr.
5 Avera's methods and I did not, as I stated did not, do an
6 independent discounted cash flow capital asset pricing
7 model. What I did knowing that there would be some good
8 technical testimony given by other parties, it always
9 helps me if I'm not, you know, talking with someone not
10 entirely in finance to say what's happened since the last
11 case to this case if I use the Company's witness' exact
12 methods and simply look at the data. What happened to
13 interest rates, what happened to Idaho Power's risk index
14 and so forth, and that's what I did and based on the
15 factors that Dr. Avera uses, I concluded that there was
16 no increase necessary.
Q And given today's economic climate, is
18 that still your opinion?
19 A Yeah, it is. My 401(k) didn't get, nor do
20 I expect it to get, 10.25 percent, but I think it's fair.
21 There are certainly lots going on in the financial
22 markets and we're expecting to see another rate case by
23 Idaho Power next year and it will be curious whether any
24 of these events trickle down into the factors that
25 determine Dr. Avera's cost of capital.
CSB REPORTING
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1761 PESEAU (X)
Micron Technology
.
.
.
1 Q And isn't it true that you and Dr. Avera
2 and maybe other witnesses in this case use data from
3 Value Line Publications?
4 A Yes.
5 Q And is it not accurate to say that the
6 concept of timeliness is a key indicator value reported
7 by Value Line?
8 A It's one of four, safety, timeliness and
9 so forth, four or five.
10 MR. HOWELL: May I approach the witness?
11 COMMISSIONER SMITH: You may.
12 (Mr. Howell approached the witness.)
13 MR. HOWELL: For purposes of
14 cross-examination, I've handed out to the witness and the
15 parties what's been marked as Staff Exhibit 154, page 1
16 of 4.
17 COMMISSIONER SMITH: But there's already a
18 154, Mr. Howell, and a 155, so this has to be 156.
19 MR. HOWELL: Then it shall be 156 and I
20 will give no Christmas presents to our folks.
21
22 mistake.
COMMISSIONER SMITH: That would be a
23 (Staff Exhibit No. 156 was marked for
24 identification.)
25 Q BY MR. HOWELL: Dr. Peseau, what is the
CSB REPORTING'
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1762 PESEAU (X)
Micron Technology
.
.
.
1 title of this document and its date?
2 A This is called the Value Line Investment
3 Survey of December 19, 2008.
4 Q And as you've just recognized by your
5 watch, they must be clairvoyant because that is
6 tomorrow's date, is it not?
7 A I wasn't sure if it was the week in
8 hearings, but that wasn't computing with me. Thank
9 you.
10 Q If I could have you look at page 1 and
11 there is, I confess that there is, a lot of data on each
12 of these pages, so for your purposes, we have highlighted
13 several things, but if you could look at page 1 on column
14 2, isn' t it true that the Electric Utility West Industry
15 is ranked 24 for timeliness or performance in the next 12
16 months?
17 A I'm sorry, page
18 Q It's on page 1, it's alphabetical, but on
19 page 2 it's numerical, so you could look at either page 1
20 or 2.
21 A Okay, yes, and it's explained in the page
22 1 that the numerals in the parentheses after the industry
23 is the rank for probable performance; is that where
24 you're speaking?
25 Q That is correct.
CSB REPORTING.
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1763 PESEAU (X)
Micron Technology
.
.
.
18
1 A Okay, thank you.
2 Q So page 1 and page 2 generally reflect
3 that the Electric Utility West Industry is ranked 24 out
4 of 99 industries?
5 A I haven't counted the industries, but that
6 looks about r~ght.
7 Q Well, if you look at page 2, they're
8 counted for you.
9 A Okay, good, thanks. That's correct,
10 then.
11 Q And do you know if this ranking of 24 for
12 the Electric Utility Industry West, is that an
13 improvement in the last three months?
14 A I don't know.
15 Q Would you accept, subj ect to check, that
16 the last ranking was No. 57?
17 A I'd accept that, subj ect to check.
Q And what is the importance of
19 timeliness?
20 A Well, investments are relative to expected
21 returns and risk and apparently, the financial community
22 is expecting a relative improvement in the expected
23 returns and the risk vis-a-vis the rest of the industry
24 for this particular group.
25 Q And if I could have you turn to page 3,
CSB REPORTING
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1764 PESEAU (X)
Micron Technology
.
.
.
1 what's been marked as page 3, of Exhibit 156, in the
2 right-hand column you'll see a number of utilities ranked
3 under the industry rank of 24. Is IDACORP one of those
4 listed?
5 A Yes, it is.
6 Q Is timeliness, then, and the ranking of
7 No. 24 for the Western Utility Group which includes
8 IDACORP, is that an indication that this industry and
9 IDACORP will attract capital more easily at favorable
10 rates than industries ranked lower than 24?
11 A If I'm an investor looking to making
12 equi ty investments, I probably wouldn't limi t it to the
13 utility industry, but I would use something like this if
14 I use Value Line and we do, that it should -- this would
15 be a form of prediction by the financial community that
16 this will be easier than many of the electrics, the
17 performance.. I'm sorry, I wasn't very clear with that.
18 Q And on page 26 of your direct testimony,
19 you note at line 8 that Dr. Avera's risk measurement for
20 his sample for IDACORP dropped from. 95 to .88 for beta.
21
22
A Correct.
Q Looking at page 3 of Staff Exhibit 156,
23 what is the beta indicated for IDACORP?
24
25
A .80.
Q So does this mean that the market risk of
CSB REPORTING
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1765 PESEAU (X)
Micron Technology
.
.
.
1 IDACORP has improved over .88?
2 A Well, technically, it means that the
3 systematic or stock market risk of Idaho Power relative
4 to the market being one has improved slightly.
5 Q If I could have you turn to page 4 of
6 Staff Exhibit 156, could you indicate to the Commission
7 what the yield shown for 30-year treasuries in the first
8 column is?
9 A 3.09.
10 Q And what is the yield shown in the second
11 column for utility bonds 25 to 30 years with a rating of
12 Baa/BBB?
13 A 7.55.
14 Q And would it be accurate to say that the
15 interest rate premium or the spread between these rates
16 is 4.46 percent?
17 A It looks correct.
18 Q If this is the interest rate premium, is
19 it accurate to describe an equity risk premium as the
20 difference between the bond yield and the cost of equity?
21 A That's one of way of doing it. There are
22 various ways, long term, short term, but yes, this would
23 be a short-term loan.
Q I'm assuming you've read Dr. Avera's24
25 testimony several times?
CSB REPORTING
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1766 PESEAU (X)
Micron Technology
.
.
.
1 A Over a number of years, yes.
2 Q Well, in particular in this case.
3 A Yes.
4 Q And on lines 13 and 16 of his rebuttal
5 testimony, he states or refers to a regulatory finance
6 on page 12 of Mr. Avera's testimony or Dr. Avera's, on
7 line 14 he cites to a literature Regulatory Finance:
8 Utili ties Cost of Capital and he concludes that these
9 studies imply that the cost of equity changes only half
10 as much as interest rates change. Do you see that
11 line?
12 A I don't have it in front of me, but I'm
13 listening.
14 Q All right, if one were to follow this
15 logic that the risk premium cost of equity change being
16 half of the interest rate change, would the bond yield of
17 7.55 plus one~half of what we just calculated the spread
18 to be of 4.46 equal, and I know you don't have the
19 numbers in front of you, 9.78 percent cost of equity?
20
21
22
23
A It was 4.06?
Q 4.46.
A 4.46?
Q And the bond yield of 7.55 shown on page 4
24 of Exhibit 156.
25 A I think that's right.
CSB REPORTING
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1767 PESEAU (X)
Micron Technology
.
.
.
1 Q And isn't that figure 9. 78 less than your
2 10.25 recommended return on equity?
3 A Yes.
4 Q I'd like, finally, to return to one little
5 area in your testimony dealing with inflation, and on
6 page 8, you discuss Idaho Power's system load growth and
7 general inflation, that those two elements tend to
8 increase the Company's cost. Now, just addressing
9 inflation, isn't it true that the rate of inflation this
10 year is expected to be below or near zero?
11 A That's correct.
12 Q And on page 17 and 18 of your testimony,
13 you obj ected to the Company's use of average compound
14 growth rates to forecast increases in its O&M expenses
15 and given your testimony that the product price index is
16 near zero, would this fact alone generally suggest that
17 the costs of O&M for the Company's expenses should be
18 lower?
19
20
A Yes, yes.
Q On page 18, you have a table where you
21 list or point out Idaho Power's forecasts for their O&M
22 expense categories with growth rates between 7 percent
23 and 11.76 percent. Given the current inflation rates,
24 are these growth rates reasonable in your opinion?
25 A Well, as I state in my testimony, I don't
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1768 PESEAU (X)
Micron Technology
1 think they're reasonable and, you know, one reason I.2 don't think they're reasonable is because they're high
3 relati ve to where we are right now, but I guess more than
4 that, I obj ect to just using a growth rate for something
5 like this in the context of this case and that's true for
6 the CWIP position I take as well. When I developed this
7 revenue requirement portion of this case, I looked at
8 where we were. a few years back with the historical test
9 year, moving to the historical with maj or plant
10 addi tions, and looked to this case and I thought that the
11 Company, while I don't think any adjustment is wrong in a
12 legal sense or even necessarily in a regulatory sense, I
.13 think we have to be a little careful.
14 This escalator would have been zero in all
15 past cases because they just weren't allowed to do this
16 in a current or future test year and now, you know, I've
17 gone along with many of the adj ustments to the test year
18 and I just think that capping this and seeing where we
19 are next year, especially given the downturn, the
20 negative wholesale and producer price indexes that we're
21 experiencing, so there's two reasons: I think these are
22 too high and even if we were continuing the status quo, I
23 don't think we need every possible adjustment to O&M, to
24 annualization, to all this. You know, I want to balance.25 ratepayer and' the Company interests.
CSB REPORTING
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1769 PESEAU (X)
Micron Technology
.
.
.
17
1 Q In your opinion, are these growth rates
2 that the Company has used known and measurable changes to
3 the test year?
4 A No, they're estimated and predicted
5 changes.
6 Q And, finally, do you believe the 9.41
7 percent growth factor for admin and general expenses is
8 reasonable in today' s climate?
9 A That did stick out with some of my staff
10 as well as me and it does seem, you know, I mean, the
11 Company may be able to explain that in more detail than
12 they have, but it does seem excessive in the times we're
13 in.
14 MR. HOWELL: Thank you. I have no further
15 questions, Madam Chairman.
16 COMMISSIONER SMITH: Mr. Kline.
MR. KLINE: Thank you. Can I have just a
18 second?
19
20 five minutes?
COMMISSIONER SMITH: Actually, do you want
21
22
23
24
25
MR. KLINE: Yeah, half an hour.
MR. KLINE: Let's take five minutes.
(Recess. )
COMMISSIONER SMITH: We'll go back on the
record. Mr. Kline.
CSB REPORTING
[phone]
1770 PESEAU (X)
Micron Technology
.
.
.
16
1 MR. KLINE: Thank you, Madam Chairman.
2
3 CROSS-EXAMINATION
4
5 BY MR. KLINE:
6 Q Dr. Peseau, you cover a broad range of
7 subj ects in your testimony here, but I'd like to start
8 wi th the discussion on the forecast test year, and in
9 order to do that, I'd like to have -- I'd like to
10 approach the witness, but I'm trapped, so I'm going to
11 have Donovan approach the witness and the Commission with
12 an exhibit that I would like to enter into the record.
13 A You're more intimidating than Bart.
14 Q That's right.
15 (Mr. Walker approached the witness.)
MR. KLINE: And while Donovan is
17 distributing that, you'll note on the lower right-hand
18 corner of the document that we previously marked it as
19 Exhibit No. 88. This is an exhibit that we had planned
20 to have Mr. Keen introduce, but because of the shuffling
21 of witnesses,' we need to use it now for cross-examination
22 purposes. I doubt if anybody will have any obj ections,
23 but if they do, why, we can bring Mr. Peseau back after
24 Mr. Keen testifies or however.
25 COMMISSIONER SMITH: Yes, so we will mark
CSB REPORTING
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1771 PESEAU (X)
Micron Technology
.
.
.
1 this as Exhibit 88.
2
3 (Idaho Power Company Exhibit No. 88 was
4 marked for identification.)
5 Q BY MR. KLINE: Dr. Peseau, would it be
6 fair to summarize your testimony in this case regarding
7 the use of forecast test years as that you are generally
8 opposed to the use of forecast test years?
9 A I think that's a little strong, Mr. Kline.
10 I have often and consistently advocated adj ustments and
11 in some cases they're forecasts, but what I fear in this
12 case has happened is that the workshops and so forth that
13
14
have sort of eased some concerns and allowed the Company
to come forward with an application with a future test
15 year that maybe this time around I think the Company has
16 forecast to its benefit over the customers, to put it
17 frankly, and so I don't disagree, but I think wi thin a
18 forecast test year and, again, referring as I did before
19 back to where we were, where we've progressed with major
20 plant additions, I just think that the Company's case is
21 a li ttle excessive in forecasting and going forward, so
22 it's not an obj ection, carte blanche. I think future
23 test years are tough, but whatever needs to be done to
24 keep a company's financial integrity, you know, you work
25 that way. I just think maybe it's a little too far.
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1772 PESEAU (X)
Micron Technology
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1 Q That's good. I'd like to have you take a
2 look at page, the last page of Exhibit 88. Actually,
3 it's page 6 of Exhibit 88 and the first column after the
4 names of the various utili ties has the capital
5 B' s/negative, stable, that kind of stuff. Do you see
6 that column of figures?
7 A I do.
8 Q Okay, and looking at the utili ties in this
9 list that have a double B rating, isn't it true,
10 Dr. Peseau, that a double B rating is a less than
11 investment grade rating or a more commonly used term a
12 junk rating?
13 A That's correct.
14 Q All right. I'd like you now to turn to
15 your Exhibit 703 and go to page -- and it's page 21 of
16 that exhibit. That's the Nevada document that we talked
17 about this morning.
18 Do the Commissioners have that? Are you
19 there?
20
21
22
23
COMMISSIONER REDFORD: This is page 23?
MR. KLINE: It's page 21 of Exhibit 703.
COMMISSIONER REDFORD:Okay.
Q BY MR. KLINE: Now, Dr. Peseau, looking at
24 the -- let's start with the last three utili ties on
25 Exhibit 88 on page 6, Texas-New Mexico Power, Public
CSB REPORTING
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1773 PESEAU (X)
Micron Technology
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1 Service of New Mexico and PNM Resources and all of those
2 utilities are, have a junk bond rating or a junk credit
3 rating and they're all regulated in the State of New
4 Mexico, are they not?
5 A I'm on page 21.
6 Q I'm sorry, now I'm on Exhibit 88.
7 A Oh, I'm sorry.
8 Q Sorry. You need both of them in front of
9 you.
10 A Okay.
11 Q All right.
12 A Yes.
13 Q All right. Now, looking at the bottom of
14 Exhibi t 88, Public Service of New Mexico, PNM Resources,
15 the bottom of the list of the junk credit rating
16 companies and they're regulated in the State of New
17 Mexico, are they not?
18
19
A Yes, they are.
Q And if you then turn to page 21 of your
20 Exhibit 703 which has the types of test years that each
21 of the states use, if you look at New Mexico, it shows
22 that the New Mexico Commission uses a historic test year
23 as part of its regulation of Public Service of New Mexico
24 and PNM Resources. Do you see that?
25 A Yes, we're on page 21, correct?
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1774 PESEAU (X)
Micron Technology
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1 Q Yes, historic test year New Mexico.
2 A Yes.
3 Q Okay, let's look at Nevada because they're
4 the next group of utilities that have the junk bond
5 credit rating on Exhibit 88. Let's look at Nevada and
6 Nevada uses a historic test year as well, does it not?
7 A No, it does not. I'm not sure what the
8 date, what that attachment -- no, in fact, Nevada Power
9 was authorized to put their Ely coal plant, it be
10 advanced, so as a result of this workshop which I
11 participated in, we actually in Nevada went to a major
12 plant addition type of forecast, yes, it's true, and in
13 fact, I indicated in some of our reports that Idaho had
14 been doing that and with some success, so...
15 Q So is there a forecast test year in
16 Nevada?
17 A Excuse me, no, but there's a big
18 difference between a historic and a -- you can adjust a
19 historic all the way to a future or beyond if you want,
20 so if that's the distinction you're making, Nevada does
21 not call their procedure a future test year. I'm sorry,
22 I'm confused.
23 Q But it's certainly not a forecast test
24 year?
25 A It's not a forecast. It's based on other
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1775 PESEAU (X)
Micron Technology
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1 factors.
2 Q What about Tucson Electric in Arizona?
3 And, again, your exhibit that you sponsored that you
4 presented to this Commission as -- you know, we discussed
5 it this morning and your counsel characterized it as a
6 useful document, Arizona uses a historic test year, don't
7 they?
8 A That's what it indicates.
9 Q And that's Tucson Electric and that's also
10 a junk bond. Well, I can continue to do this. It will
11 be a little repetitive. Would you accept, subject to
12 check, that everyone of the junk bond utili ties,
13 utili ties that have a junk credit rating, with the
14 exception of the distinction you're making with Nevada,
15 utilizes a historic test year?
16 A I'll accept that.
17 Q I'm not going to go look at all of the
18 utili ties that have a double A rating, but there is a
19 trend there as well and it has to do with using forecast
20 test years.
21
22
A Not surprising.
Q All right. Let's take a look at
23 construction work in progress. That was also a part of
24 your testimony and on page 21 and 22 of your testimony,
25 that's where you talk about construction work in
CSB REPORTING
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1776 PESEAU (X)
Micron Technology
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1 progress, and sitting here in the hearing for the last
2 two or three days, there's been quite a bit of discussion
3 about the history of the statute in Idaho regarding
4 construction work in progress and the fact that it's been
5 changed now. The legislature changed the statute to
6 allow the Co~ission to include construction work in
7 progress in rate base if the Commission finds that's in
8 the public interest.
9 A Correct.
10 Q All right, and you're opposed to the use
11 of construction work in progress, of including
12 construction work in progress in rate base; isn't that
13 correct?
14 A In general I am. If it's necessary, you
15 know, the regulation has to do what, the regulators have
16 to do what they need to do to keep the Company whole. If
17 that is -- that's one means. I just hate to say that
18 construction work in progress is a good thing. It's a
19 good thing for the Company. It's not a good thing for
20 ratepayers, so I'm not against it. In this case I
21 looked at it and determined that with all the other
22 adj ustments in the future test year, I didn't think it
23 was necessary- and I opposed it.
24 Q And didn't you use the term I oppose it in
25 principle?
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1777 PESEAU (X)
Micron Technology
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1 A Yes.
2 Q Okay. Well, let me ask you this: Is it
3 your recommendation to the Commission here today that in
4 light of the fact that the Idaho legislature has changed
5 the statute, made construction work in progress available
6 as a tool for the Commission that the Commission should
7 now tell the legislature that we don't think that the
8 discretion that you gave us is really worth anything,
9 it's bad regulatory policy, we're just not going to do
10 it?
11 A No, I think you used the word "discretion"
12 and discretion doesn't mean yes each and every time the
13 Company requests it. I think the Commission, I'm sure,
14 will look at that with the rest of their decisions that
15 they make in this case and the adjustments and determine
16 whether it's necessary. I concluded that it was not
17 necessary.
18 Q Now, I'd like to talk a little bit about
19 your testimony regarding rate design, the 3CP and 12CP
20 method and particularly I want to focus in on the
21 recommendation that you made and that other witnesses on
22 behalf of the high load factor customers have made today
23 to have the Commission retain a neutral third party. Let
24 me kind of set the table here a little bit, add a little
25 context. The' first thing I want to ask you about is have
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1778 PESEAU (X)
Micron Technology
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11
1 you ever -- I want to ask you about a phrase. It's a
2 phrase that is attributed to Huey Long who was the famous
3 or infamous Governor and Senator from the State of
4 Louisiana and Mr. Long was describing the perfect tax
5 policy and his description is don't tax you, don't tax
6 me, tax the guy behind the tree. Are you familiar with
7 that phrase?
8 A No.
9 Q It's a good one, isn't it?
10 A It's a good one.
Q Well, in this particular case, we've got
12 at least three parties, principally the high load factor
13
14
customers, that have an economic stake in the outcome of
this 3CP/12CP. rate design question and all of the
15 witnesses that represent those customers and who have an
16 economic stake in the outcome of that decision, they
17 don't like the 3CP/12CP method that the Company has
18 presented. In fact, they've called it fatally flawed and
19 there's been some pretty colorful language, I think,
20 regarding the problems that they have with it, and I
21 think in the case of the irrigators, they haven't joined
22 in that chorus. They may be the guy behind the tree.
23 Then you've got two other parties that have presented
24 testimony on the 3CP /12CP method, the Staff and Idaho
25 Power, and these are companies that don't -- these are
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1779 PESEAU (X)
Micron Technology
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1 enti ties that don't have an economic stake in the outcome
2 of the rate design. In Idaho Power's case, if it gets
3 its revenue requirement, certainly it wants it to be done
4 on a basis that's legal and fair, but it doesn't have an
5 economic stake in how it turns out and the same is true
6 wi th the Staff, would you agree?
7 A No. I think the Company does have a stake
8 in it and I think they read the political winds and I
9 think, as is the case in most jurisdictions, Staff feels
10 protecti ve of residential customers more than anything
11 else and I don't frankly find that wrong, but I consider
12 Staff an advocate for residentials, fair to everybody.
13 I'm not saying that they're going to maximize and harm
14 intentionally either the Company or other parties, but I
15 don't think that there's not a stake by either Staff or
16 Company. It's just not what I found.
17 Q Well, regardless of whether you think that
18 Staff and Idaho Power constructed their cases based on
19 poli tical considerations rather than on trying to get a
20 good cost of service study in front of the Commission
21 MR. WARD: I'm going to object. That's
22 not what he said.
23 MR. KLINE: I'll withdraw that question.
24 COMMISSIONER SMITH: Thank you,
25 Mr. Kline.
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1780 PESEAU (X)
Micron Technology
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1 Q BY MR. KLINE: Regardless of that, I'm
2 really mostly interested in the recommendation that you
3 made and the other representatives of the high load
4 factor customers made to have what you called a neutral
5 third party come in and present testimony and I'm trying
6 to understand how that's going to help the process and,
7 again, I believe, and that's how I'm going to represent
8 it, that Staff and the Company don't have an economic
9 stake in the outcome of the rate design controversy. The
10 other folks do. Now, if we bring in this third party at
11 considerable cost, I would assume, because consultants
12 don't come cheaply, what exactly are they going to do to
13 aid in the decision making process? Is the idea that
14 they're going to come in and convince the Staff and the
15 Company that they're wrong? You know, what are we going
16 to get from that?
17 A Well, I don't know that the third party is
18 the only way to do it, but I'll answer your question
19 directly from. page 45 of my testimony and that's the
20 table I referred people to. I can tell you that cost of
21 service studies that were developed through PURPA and
22 through consultants that Idaho Power hired in the 1980s
23 and was eventually adopted by all parties produced
24 results similar to the 2003 decision that were more
25 favorable and there's reasons that that's changed.
CSB REPORTING
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1781 PESEAU (X)
Micron Technology
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1 I'm not saying that we should go back and
2 whatever the rate spread was in 1990, it's not true. The
3 system has changed and as long as we have a cost of
4 service methodology that reflects those changes over
5 time, I think that's fine, but I would begin with saying
6 we need to explain how in one rate case this thing has
7 turned around completely and customers that were
8 legi timately spread at less than an average rate increase
9 in 2003 now have a 250 percent recommended increase if
10 it's not capped today, but I think, you know, that's one
11 thing.
12 We're talking about warring of models, but
13 I think either through a third party or maybe the parties
14 here if we can, you know, lay down our advocate hats need
15 to understand why this Company is continuing to invest in
16 DSM proj ects and at the same time allocating costs out of
17 the peak saying that -- and that's the heartburn. You
18 know, it can't be both ways, come in and, you know, I
19 don't want to strive modus, but come in and say the
20 system has changed, the peak costs are no longer as high
21 they are, they're lower and your data shows that and I
22 think that's the place to start.
23 It's maybe this top-down is to say look,
24 isn't this a summer peaking system. By your own records,
25 aren't most of the costs of demand or capacity and energy
CSB REPORTING
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1782 PESEAU (X)
Micron Technology
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1 incurred in the summer and why are you, you know, doing
2 this what I claim is a double allocation, but it is a
3 calculation of costs into energy and off peak. I think
4 we need -- I don't know how the Commission decides and,
5 you know, we're not getting anywhere with proceedings
6 like this, I think, because it's, they're complex. No
7 one can understand why you go 49 rather than some other
8 number or 1C or a 12CP and we all know, the experts know
9 what hurts and what doesn't and so we're aware of that
10 and push, but I think we just need to go to the top and
11 say what are we going to do to curb this price or, excuse
12 me, peak load increases that are twice. You know, that
13 doesn't do the Company any good and it doesn't do
14 customers any. good, so let's get to the bottom of it.
15 Q You participated in the workshops that
16 came out of the 2003 rate case, did you not?
17 A On what issue?
18 Q I'm sorry, at the conclusion of the 2003
19 rate case, the Commission directed us to participate in
20 workshops to see if we could address some of these cost
21 of service issues and we had several meetings. I believe
22 you participated in those, didn't you?
23 A I think by telephone. I don't think any
24 other way.
25 Q And, of course, I think it was well
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1783 PESEAU (X)
Micron Technology
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1 described yesterday everybody kind of sat around and said
2 well, I'm not going to say anything that's going to
3 disadvantage my client. I won't get employed again if
4 that happens and we really didn't make an awful lot of
5 progress. Do you think bringing in a third party is
6 really going to change that, Dr. Peseau?
7 A Well, I was talking during the recess with
8 Mr. Lobb and I think there may be other ways that we
9 float a trial balloon and see whether the parties really
10 want to solve this or not. You know, I always feel like
11 I'm standing in the middle. I haven't changed my cost of
12 service methodology, the Company has, and my cost of
13 service methodology has been the Company's for 18 or 20
14 years and I would like to understand what I'm not
15 understanding about the nature of the system and how it's
16 changed that could possibly cause that, so maybe getting
17 together prior to that, but I just don't know.
18 The Commission, how can they understand
19 every facet of this and you go to the thing, well, I'll
20 either flip a coin or, you know, I'll go on who performs
21 best. You know, that's just not the reason and there's
22 dire consequences to the high load factor customers, not
23 to residentials and potentially to irrigators, but every
24 cost of service study other than the irrigators' has
25 always shown they're below and I understand that, but
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1784 PESEAU (X)
Micron Technology
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20
1 we've made pragmatic decisions in the past to say we
2 can't go raise rates for irrigators 60 percent and I
3 think my client would probably agree with that. It would
4 be nice for everybody else, so I think we can work this
5 thing out. I don't think we should run the risk of
6 changing cost studies to suit our needs and we may be
7 doing that, all parties in this case.
8 Q Let me address a couple of other things
9 and maybe we can wrap it up. One of the things you said
10 today in your testimony was that maybe the best thing to
11 do would be just have an across-the-board increase and
12 let everything settle down. By going that route, doesn't
13 that suggest that the cost of service from 2003 which is
14 the last cost of service that this Commission dealt with
15 in a final Order is better than any of the cost of
16 service proposals presented in this case?
17 A Yes.
18 MR. KLINE: One second.
19 (Pause in proceedings.)
Q BY MR. KLINE: Yeah, one final question.
21 You reside in Salem, Oregon, do you not?
22
23
A Yes, I do.
Q And you used to be employed by the Oregon
24 Public Utilities Commission?
25 A True.
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1785 PESEAU (X)
Micron Technology
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17
18
1 Q The Oregon utilities, Portland General
2 Electric, PacifiCorp, what kind of test years do they
3 use?
4 A Future test years, but not on my
5 recommendation.
6 MR. KLINE: Thank you. That's all I have.
7 COMMISSIONER SMITH: Do we have questions
8 from the Commission? Commissioner Kempton.
9 COMMISSIONER KEMPTON: One quick question.
10
11 EXAMINATION
12
13 BY COMMISSIONER KEMPTON:
14 Q You know , it isn't impossible to remember
15 this, but it's awful close. Sierra Nevada is a Nevada
16 power company; right?
A Sierra Pacific, yes.
Q And I should refer to Nevada in this
19 handout, what was it, Exhibit 88, Idaho Power?
20
21
A Yes.
Q Did Sierra Nevada engage in an IGCC
22 experimental plant, development of an experimental
23 plant?
24
25
A Pinon Pine.
Q Was that done as a CWIP proj ect, do you
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1786 PESEAU (Com)
Micron Technology
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1 know? In other words, my understanding was that the
2 ratepayers had a considerable portion of that to pay and
3 I never did understand whether that was something that
4 was--
5 A The Pinon Pine IGCC proj ect was a joint
6 investment by the DOE and Sierra Pacific, so half the
7 cost, capital cost, I don't believe any of the operating
8 cost, half the capital cost was and that's what sold
9 the thing . Given how difficult it is in Nevada to get
10 CWIP in rate base and the fact that I do recall that that
11 was kind of a colossal failure for a lot of reasons, even
12 wi th the technology aside and that a huge portion of that
13 was taken out, so to my knowledge, Commissioner, it's
14 been awhile, but I did participate in those cases and I
15 don't think it was construction work in progress. It was
16 not in rate base, I'm sorry, I misspoke.
17 COMMISSIONER KEMPTON: That's all I
18 have.
19
20
COMMISSIONER SMITH: Commissioner Redford.
21 couple of questions.
COMMISSIONER REDFORD: I just have a
22
23
24
25
CSB REPORTING
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1787 PESEAU (Com)
Micron Technology
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16
1 EXAMINATION
2
3 BY COMMISSIONER REDFORD:
4 Q Dr. Goins was very critical of the cost of
5 service study and the allocation and notwithstanding the
6 fact that you discussed this today, is it your opinion
7 that Dr. Goins is pretty well on mark as to his testimony
8 wi th regard to the cost of service and also allocation?
9 A We have different approaches to some of
10 the allocators, but I think his testimony was right on
11 task, frankly.
12 Q So if we take Dr. Goins' and your
13 testimony, then, we must draw the conclusion that in fact
14 the allocation method for all classes of customers is
15 also in error?
A The changes made from the 2003 case to
17 this case, the changes are in error, yes.
18 Q And your response to that is to simply
19 calculate the. cost of service generally and allocate the
20 resulting costs over all classes of customers?
21 A All classes of customers equally, but it's
22 based in part because the last litigated case, no one's
23 single case was adopted. It's the typical well, this is
24 the way we've done it and there's some good suggestions
25 and some bad suggestions, so the Commission came out and
CSB REPORTING
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1788 PESEAU (Com)
Micron Technology
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1 said this is the cost of service study that's
2 appropriate.
3 Q So every class of customer in your opinion
4 is it must bear its responsibility for the cost of
5 service?
6 A To the extent it's practical,
7 Commissioner, and in some states where it's so far out of
8 whack you can't move to cost of service, even though -- I
9 don't know of a Commission that doesn't say that i s
10 relevant and probably the most important factor to begin
11 wi th, cost causation and cost, but I think according to
12 my table on page 45, all the classes but irrigators are
13 close to cost of service, some slightly below, and rather
M than hash that out, I think that's a slam dunk. The
15 question is irrigators, they come out pretty well on a
16 proposal like that because, you know, they are the
17 deepest in the hole in terms of cost of service, which
18 you'd expect with a summer peaking system, so I think
19 that the last complete study that was thoroughly looked
20 at by the Commission would suggest that that's a fair
21 conclusion in this case.
22 Q Thank you. Dr. Avera and others who have
23 testified as consultants and experts on return on equity
24 have used proxy companies. Have you ever used proxy
25 companies to calculate or demonstrate return on equity?
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1789 PESEAU (Com)
Micron Technology
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1 A I have used samples in various cases. The
2 proxy company I began, as someone pointed out, with
3 the Public Utility Commission of Oregon and my assignment
4 was rate of return. At that time in the late '7 Os there
5 weren't the models that are available now and so I did
6 use a comparable, but with financial training, it wasn't
7 very terribly satisfying because I found out that if I
8 used different samples I got different results. You
9 know, that becomes pretty apparent.
10 Q Well, Dr. Avera used these proxy companies
11 and, quite frankly, it's kind of mystifying to me and
12 maybe you can clear it up from the standpoint of is it
13 simply contacting or reading about the return on equity
14 of these proxy companies or, in the al ternati ve, is there
15 a more in-depth study of these proxies to demonstrate
16 other factors' which would mitigate or actually increase
17 the return on equity? I'm just -- how does the process
18 work?
19 A The process usually works in a way that
20 you would identify your proxies as being in the same
21 industry. Financially, frankly, that doesn't make any
22 sense. It should be a risk return analysis because all
23 utilities aren't the same and there are companies out
24 there with the same risk profiles as, say, Idaho Power
25 that might arguably make it better, but it would be size,
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1790 PESEAU (Com)
Micron Technology
.1 it would be type of regulation, you know, maybe bond
2 ratings. It's certainly subjective to do so and, you
3 know, it goes to the credibility of the witness, and at
4 one point I pointed out in my testimony that while I've
5 observed Dr. Avera's testimony in the last several cases
6 here and elsewhere, samples do tend to change and you
7 wonder why that happens sometimes, you know, for an
8 advocate and I'm not accusing Dr. Avera of anything, but
9 it' s arbitrary for a short answer.
10 Q Well, it seems to me that each of these
11 companies has. different financial structures and unless
12 you go into the structure of the company that you're.13 using for a proxy, your proxy statement is really subj ect
14 to, as you've said, arbitrary and capriciousness.
15 A It is and, you know, on the other hand,
16 you know, the Company doesn't stand on its own in the
17 financial markets. They need to demonstrate to Wall
18 Street that they're in the ball park and Wall Street
19 tends to group, same procedure group, companies together
20 and they need to make their case that they're strong or
21 likely to be as strong as other companies, so it's not
22 irrelevant and I don't want to be unfair to the Company,
23 you need samples, but any time you get -- in this case,
24 you know, when your utility isn't exactly IDACORP and.25 other utili ties or comparables maybe much -- you know, I
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1791 PESEAU (Com)
Micron Technology
1 mean, look back at Idaho Power or IDACORP a few years ago.2 when they had the trading and so forth, you're not sure
3 whether the market data you're looking at is, even from
4 your own parent is, particularly applicable, so it's
5 difficult. That's why I don't do much rate of return
6 anymore.
7 Q The exhibit which, and I can't recall what
8 the exhibit number was, that the Company proposed that
9 showed those companies that are triple B and those
10 companies that are A rated, the vast majority of the
11 companies are triple B rated and I'm wondering as opposed
12 to Idaho Power or any other companies specifically that.13 these ratings are simply a sign of the times and that the
14 analysts are really grading utilities en masse, the
15 industry.
16 A That's absolutely correct, but there are
17 two facets. One is financial risk and integrity of the
18 company as a stand-alone and the bond rating agencies are
19 going to look at that, what is the risk, but probably
20 equally true is the fact that when we're in more
21 uncertain times, you know, look at the ratio of
22 downgrades to upgrades and look at the utility industry
23 in general. I think when I started in Idaho, Idaho Power
24 was a triple A, as I recall..25 . MR. KLINE: At least double. It's been a
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1792 PESEAU (Com)
Micron Technology
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1 long time.
2 THE WITNESS: I think it was a triple A at
3 one time, which is unheard of today, so nobody makes that
4 grade anymore, so it's trendy and bond rating agencies
5 want to protect their bond holders, so it's an art as
6 much as a science.
7 Q BY COMMISSIONER REDFORD: I had a couple
8 of questions about CWIP and I recall the nuclear fiasco
9 in Washington and elsewhere and probably the Sierra
10 Pacific, but ~ouldn' t you agree that there are certain
11 proj ects or studies or, for instance, the Hells Canyon
12 relicensing that are used and useful and that they're so
13 expensive that in order to smooth out the ultimate cost
14 or the rate shock when we start adding those into the
15 rate base that it is appropriate to consider some of
16 those construction proj ects in progress?
17 A I don't think it's inappropriate to do
18 that. I think the Commission needs to act responsibly to
19 maintain the balance of the Company's financial
20 interests, certainly, with ratepayers. My point in this
21 case is that given the other improvements that I'm sure
22 the Company would claim with the use of the future test
23 year doesn't hecessi tate that, but it's a matter of
24 opinion.
25 Q Finally, in dealing with a stock and bond
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PESEAU (Com)
Micron Technology
1793
1 analyst and some of the industry folks, they really like.2 to use the word "regulatory lag" and for me as a
3 Commissioner, I kind of take offense to that because it
4 seems to indicate that it's because of the lag from the
5 time the application is filed until the rates go into
6 effect, that in fact we somehow are not acting
7 appropriately or speedy, and regulatory lag, certainly by
8 its definition, involves regulation.
9 A Correct.
10 Q Mr. Gale, on the other hand, in his
11 testimony says well, regulatory lag really starts when a
12 cost is, when a cost is incurred, even much before the.13 time that there is a rate proceeding. How can that
14 possibly be?
15 A The argument for regulatory lag has been
16 around as long as I've been in this business and at times
17 it's a concern and at times such as when the open access
18 transmission occurred in 1996 is where utilities were
19 happy to have -- it wouldn't be a regulatory lag, it
20 would be a regulatory lead, because wholesale prices went
21 through the -- bottomed out considerably and everyone was
22 in for a rate freeze voluntarily. Well, that's because
23 costs are going down. Regulatory lag at this time is of
24 great concern for the Company because they're in a large.25 building program. I've come to the conclusion after
CSB REPORTING
[phone]
1794 PESEAU (Com)
Micron Technology
.
.
. 25
1 thinking about this for years, the best solution for
2 regulatory lag in these times is to have annual rate
3 cases until you're off of it and that gives Staff and
4 others the ability to audit and become more comfortable
5 on a year-to-year basis, but I'm not sympathetic to the
6 regulatory lag that someone complains when they haven't
7 been in for a rate case.
8 They have the choice and so I think the
9 Commission should take into account in its decisions
10 overall that there are going to be opportunities to
11 review this for the next few years, and when they're
12 building some size, if it does, you know, the Company
13 shouldn't come in, there's no need to. No one wants to
14 have annual rate cases, I understand that, but they're
15 necessary as opposed to going out so far in the future
16 with forecasts that you're taking care of it. I mean,
17 there's two ways to do that.
18 COMMISSIONER REDFORD: Well, thank you
19 very much. I appreciate your testimony.
20 THE WITNESS: Thank you.
21
22
23
24
CSB REPORTING
[phone]
1795 PESEAU (Com)
Micron Technology
.
.
.
1 EXAMINATION
2
3 BY COMMISSIONER SMITH:
4 Q Well, Commissioner Redford touched on the
5 two areas that I wanted to ask you about, but, of course,
6 a lawyer is never satisfied with the way another lawyer
7 asked his question, so just bear with me, but cost
8 causation is one of the things that has been raised in
9 this case and that we've talked about and it occurred to
10 me a long time ago, mostly the first time in a water
11 case, that there's two ways to think about cost
12 causation: You can think about it like the problem is
13 the peak and every drop of water, every kilowatt-hour
14 that's used, contributes to the peak, so everyone is
15 equally responsible for the costs of the peak, so that
16 was one way; and the other way is you had a system that
17 was working perfectly fine and suddenly there was growth
18 and it's all those new people that caused the problem,
19 because if you didn't have the new people, everything
20 would have continued on and nothing new would have had to
21 have been built, so are these equally valid ways of
22 thinking of cost causation or is one better than the
23 other?
24 A Well, Commissioner, as you know, I'm an
25 economist and I think I spoke earlier that the efficient
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PESEAU (Com)
Micron Technology
1796
.1 way, I think, to look at cost causation is at the point
2 where you have to change your system to accommodate and
3 there are arguments in the past that every penny of
4 capaci ty cost for expansion should be allocated to the
5 single peak hour of the year and see who's on board
6 there, because capacity, and it's true, capacity the rest
7 of the year is in an economic sense free and we don't do
8 it that way. We do spread it out, but I don't think that
9 growth in a customer class you know, I mean, wi thin
10 each customer' class you have people who move across the
11 street, are they new customers or not? You know, I don't
12 know, or irrigators who are changing meters or selling.13
14
their place, I'm just not compelled that classes of
growth, I mean, everyone at the margin still have the
15 choice at peak if they've got a proper price signal, and
16 demand meters help as well, has a choice to contribute to
17 that peak and cause that next power plant or expansion of
18 a loop in the water system or not and that's the way I'm
19 obviously looking at it, but the argument for the new guy
20 on the block, and I'm certainly sympathetic to hearing
21 the Company say that there are a lot of people out there
22 that want to become new people on the block, you know,
23 I'm sympathetic to that, because at a six-cent rate for
24 residential and three-cent rates for industrials, you.25 know, you hate to see it go away, frankly, but I don't
CSB REPORTING.
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1797 PESEAU (Com)
Micron Technology
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1 know how you discriminate. I'd like to think of a way
2 frankly sometimes, but...
3 COMMISSIONER SMITH: Okay, thank you for
4 your thoughts. Mr. Ward, do you have any redirect?
5 MR. WARD: Just quickly.
6
7 REDIRECT EXAMINATION
8
9 BY MR. WARD:
10 Q Dr. Peseau, when you were drafting
11 testimony, I noticed neither you nor any other economist
12 uses this terminology, but with regard to the question of
13 tracking costs to their cause and we typically talk about
14 that in terms of "price signals," but isn't the real term
15 for that in economics consumer rationing?
16 A Yeah, and rationing is not a very pleasant
17 sounding word, but all our resources are rationed, but,
18 fortunately, by a market and not by other determinations
19 by whose interest it is to ration, so yeah, you know, my
20 consumption is rationed according to prices and I'm going
21 to back off a little bit from those things that are
22 higher priced and go to those that are lesser priced.
23 Q Right, and you jumped about three
24 questions ahead of me, which you often do, but the gist
25 of that rationale is that the reason why it's termed that
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1798 PESEAU (Di)
Micron Technology
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1 way is not because, as you said, we're actually
2 forbidding anybody from buying wheat above a certain
3 allotment, it's that when prices are very expensive, as
4 an economic view, we want every customer to know that
5 fact and to act accordingly, in which case it is assumed
6 that they will act efficiently and do their best to
7 ration their own consumption.
8 Yes, that's the economic fundamentalA
9 behind the whole thing.
10 And does that apply to peak consumption onQ
11 utility systems?
12 A I believe it does.
13 MR. WARD: That's all I have.
14 COMMISSIONER SMITH: Thank you, Mr. Ward,
15 and Dr. Peseau.
16 COMMISSIONER REDFORD: Thank you, Doctor.
17 (The witness left the stand.)
18 COMMISSIONER SMITH: So Mr. Kline, would
19 we like to go to your witness now?
20 MR. KLINE: I'm going to have Lisa
21 Nordstrom spread Dr. Avera's testimony, Madam Chair.
22 COMMISSIONER SMITH: Mr. Ward.
23 MR. WARD: I think Dr. Peseau intends to
24 stay through day anyway, but before I forget, I would
25 like to have pim excused if we go into tomorrow.
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1799 PESEAU (Di)
Micron Technology
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18
19
1 COMMISSIONER SMITH: Is there any
2 objection to excusing him? Seeing none, he's excused.
3 MR. WARD: Than k you.
4 COMMISSIONER SMITH: Maybe he can book a
5 dog sled to Salem.
6 MR. KLINE: Snow is a good thing.
7 COMMISSIONER SMITH: Yes, it is. I didn't
8 say it was a bad thing. Ms. Nordstrom.
9 MS. NORDSTROM: Thank you. Idaho Power
10 calls Dr. William Avera, Avera, excuse me, as its next
11 witness.
12
13 WILLIAM E. AVERA,
14 produced as a telephonic witness at the instance of the
15 Idaho Power Company, having been first duly sworn, was
16 examined and testified as follows:
17
DIRECT EXAMINATION
20 BY MS. NORDSTROM:
21 Q Dr. Avera, please state your name and
22 spell your last name for the record.
23
24.25
A William E. Avera, A-v-e-r-a.
Q By whom are you employed and in what
capacity?
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1800 AVERA (Di)
Idaho Power Company
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1 A I'm the president of FINCAP, Incorporated,
2 economic and financial consulting firm in Austin,
6 A
3 Texas.
4 Q Are you the same William Avera that filed
5 direct testimony on June 27th, 2008?
7 Q
Yes.
And prepared Exhibit Nos. 16 through 26?
Yes.
Did you also file rebuttal testimony on
10 December 3rd, 2008?
8 A
I did.
Did you also prepare Exhibit Nos. 81 and
Yes.
Do you have any corrections, changes or
16 updates to your testimony or exhibits?
20
9 Q
I have one small correction to my
And what is that?
At 12, at the end of that line the word
21 "or" appears. "Or" should be stricken and inserted
11 A
22 should be "compared to."
23
12 Q
If I were to ask you the questions set out
24 in your corrected prefiled testimony today, would your
25
13 82?
answers be the same?
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14 A
15 Q
17 A
18 rebuttal, page 7.
19 Q
A
Q
1801 AVERA (Di)
Idaho Power Company
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1 A They would be.
2 MS. NORDSTROM: I would move that the
3 prefiled direct and rebuttal testimony of William Avera
4 be spread upon the record as if read and Exhibit Nos. 16
5 through 26 and 81 through 82 be marked for
6 identification.
7 COMMISSIONER SMITH: If there is no
8 obj ection, it is so ordered.
9 (The following prefiled direct and
10 rebuttal testimony of Mr. William Avera is spread upon
11 the record.)
12
13
14
15
16
17
18
19
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1802 AVERA (Di)
Idaho Power Company
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.
1 I.INTRODUCTION
2 Q.Please state your name and business address.
3 A.William E. Avera, 3907 Red River, Austin,
4 Texas, 78751.
5 Q.In what capacity are you employed?
6 A.I am the President of FINCAP, Inc., a firm
7 providing financial, economic, and policy consulting
8 services to business and government.
9 Q.Please describe your educational background and
10 professional experience.
11 A.I received a B.A. degree with a major in
12 economics from Emory Uni versi ty. After serving in the
13
14
U. S. Navy, I entered the doctoral program in economics at
the Uni versi ty of North Carolina at Chapel Hill. Upon
15 receiving my Ph. D., I joined the faculty at the
16 University of' North Carolina and taught finance in the
17 Graduate School of Business. I subsequently accepted a
18 position at the University of Texas at Austin where I
19 taught courses in financial management and investment
20 analysis. I then went to work for International Paper
21 Company in New York City as Manager of Financial
22 Education, a position in which I had responsibility for
23 all corporate education programs in finance, accounting,
24 and economics~
25 In 1977, I joined the staff of the Public
1803 AVERA, DI 1
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1 Utili ty Commission of Texas (" PUCT") as Director of the
2 Economic
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5
6 /
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8 /
9
1804 AVERA, DI 1a
Idaho Power Company
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1 Research Division. During my tenure at the PUCT, I
2 managed a division responsible for financial analysis,
3 cost allocation and rate design, economic and financial
4 research, and data processing systems, and I testified in
5 cases on a variety of financial and economic issues.
6 Since leaving the PUCT, I have been engaged as a
7 consul tant. I have participated in a wide range of
8 assignments involving utility-related matters on behalf
9 of utilities, industrial customers , municipalities, and
10 regulatory commissions. I have previously testified
11 before the Federal Energy Regulatory Commission ("FERC"),
12 as well as the Federal Communications Commission, the
13 Surface Transportation Board (and its predecessor, the
14 Interstate Commerce Commission), the Canadian
15 Radio-Television and Telecommunications Commission, and
16 regulatory agencies, courts, and legislative committees
17 in 40 states.'
18 In 1995, I was appointed by the PUCT to the
19 Synchronous Interconnection Committee to advise the Texas
20 legislature on the costs and benefits of connecting Texas
21 to the national electric transmission grid. In addition,
22 I served as an outside director of Georgia System
23 Operations Corporation, the system operator for electric
24 cooperatives in Georgia.
25 I have served as Lecturer in the Finance
1805 AVERA, DI 2
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1 Department at the Uni versi ty of Texas at Austin and
2 taught in the evening graduate program at St. Edward's
3 Uni versi ty for twenty years. In addition, I have
4 lectured on economic and
5
6 /
7
8 /
9
10 /
1806 AVERA, DI 2a
Idaho Power Company
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1 regulatory topics in programs sponsored by uni versi ties
2 and industry groups. I have taught in hundreds of
3 educational programs for financial analysts in programs
4 sponsored by the Association for Investment Management
5 and Research, the Financial Analysts Review, and local
6 financial analysts societies. These programs have been
7 presented in Asia, Europe, and North America, including
8 the Financial Analysts Seminar at Northwestern
9 Uni versi ty. I hold the Chartered Financial Analyst
10 (CFA~) designation and have served as Vice President for
11 Membership of the Financial Management Association. I
12 have also served on the Board of Directors of the North
13 Carolina Society of Financial Analysts. I was elected
14 Vice Chairman of the National Association of Regulatory
15 Commissioners ("NARUC") Subcommittee on Economics and
16 appointed to NARUC' s Technical Subcommittee on the
17 National Energy Act. I have also served as an officer of
18 various other professional organizations and societies.
19 A resume containing the details of my experience and
20 qualifications is attached as Exhibit No. 16.
21
22
A.Overview
Q.What is the purpose of your testimony in this
23 case?
24
25
A.The purpose of my testimony is to present to
the Idaho Public Utilities Commission (the "Commission"
1807 AVERA, DI 3
Idaho Power Company
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1 or "IPUC") my independent evaluation of the fair rate of
2 return on equity ("ROE") for the jurisdictional utility
3 operations
4
5 /
6
7 /
8
9 /
1808 AVERA, DI 3a
Idaho Power Company
.
.
.
1 of Idaho Power Company (" Idaho Power" or "the Company").
2 The overall rate of return applied to Idaho Power's 2008
3 test year rate base is developed in the testimony of Mr.
4 Steve Keen.
5 Q.Please summarize the basis of your knowledge
6 and conclusions concerning the issues to which you are
7 testifying in this case.
8 A.As is common and generally accepted in my field
9 of expertise, I have accessed and used information from a
10 variety of sources. I am familiar with the organization,
11 operations, finances, and operation of Idaho Power from
12 my participation in prior proceedings before the IPUC,
13 the Oregon Public Utility Commission, and the FERC. In
14 connection with the present filing, I considered and
15 relied upon corporate disclosures and management
16 discussions, publicly available financial reports and
17 filings, and other published information relating to the
18 Company and its parent, IDACORP, Inc. ("IDACORP"). I
19 also reviewed information relating generally to current
20 capi tal market conditions and specifically to current
21 investor perceptions, requirements, and expectations for
22 Idaho Power's electric utility operations. These
23 sources, coupled with my experience in the fields of
24 finance and utility regulation, have given me a working
25 knowledge of investors' ROE requirements for Idaho Power
1809 AVERA, DI 4
Idaho Power Company
1 as it competes to attract capital,and form the basis of.2 my analyses and conclusions.
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
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24.25
1810 AVERA,DI 4a
Idaho Power Company
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1 Q.What is the role of ROE in setting a utility's
2 rates?
3 A.The ROE serves to compensate investors for the
4 use of their capital to finance the plant and equipment
5 necessary to provide utility service. Investors commit
6 capi tal only if they expect to earn a return on their
7 investment commensurate with returns available from
8 alternative investments with comparable risks. To be
9 consistent with sound regulatory economics and the
10 standards set forth by the Supreme Court in the
11 Bluefield1 and Hope2 cases, a utility's allowed ROE should
12 be sufficient to: 1) fairly compensate the utility's
13 investors, 2) enable the utility to offer a return
14 adequate to attract new capital on reasonable terms, and
15 3) maintain the utility's financial integrity.
16 Q.How' did you go about developing your
17 conclusions regarding a fair rate of return for Idaho
18 Power?
19 A.I first reviewed the operations and finances of
20 Idaho Power and the general conditions in the utility
21 industry and the economy. With this as a background, I
22 conducted various well-accepted quantitative analyses to
23 estimate the current cost of equity, including
24 al ternati ve applications of the discounted cash flow
25 ( "DCF") model and
1811 AVERA, DI 5
Idaho Power Company
1.2
3 /
4
5 /
6
7 /
8
9
10
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12.13
14
15
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17
18
19
20
21
22
23 i Bluefield Water Works & Improvement Co. v.Pub. Serv. Comm' n,262
u.s.679 (1923) .
24 2 Fed.Power Comm' n v. Hope Natural Gas Co.,320 u.s.591 (1944) ..25
1812 AVERA, DI 5a
Idaho Power Company
1 the Capital Asset Pricing Model ("CAPM"), as well as.2 reference to comparable earned rates of return expected
3 for utili ties. Based on the cost of equity estimates
4 indicated by my analyses, the Company's ROE was evaluated
5 taking into account the specific risks and economic
6 requirements for Idaho Power consistent with preservation
7 of its financial integrity.
8 B.Sumary of Conclusions
9 Q.What are your findings regarding the fair rate
10 of return on equity for Idaho Power?
11 A.Based on the results of my analyses and the
12 economic requirements necessary to support continuous.13 access to capital, I recommend that Idaho Power be
14 authorized a fair rate of return on equity in the 10.8
15 percent to 11.8 percent range. The bases for my
16 conclusion are summarized below:
17 In order to reflect the risks and prospects
associated with Idaho Power's jurisdictional18 utility operations, my analyses focused on a
proxy group of twenty-seven electric utili ties19 with comparable investment risks. Consistent
with the fact that utili ties must compete for20 capi tal with firms outside their own industry,
I also referenced a proxy group of comparable21 risk companies in the non-utility sector of the
economy;
22
23 .I applied both the DCF and CAPM methods, as
well as the comparable earnings approach, to
estimate a fair ROE for Idaho Power:24.25 o My application of the constant growth DCF model
1813 AVERA, DI 6
Idaho Power Company
1.2
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
considered three alternative growth measures
based on proj ected earnings growth, as well as
the sustainable, "br+sv" growth rate for each
firm in the respective proxy groups;
1814 AVERA, DI 6a
Idaho Power Company
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10
11
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20
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25
1
2
3
4
5
6
7
8
9
o After eliminating low- and high-end outliers,
my DCF analyses implied a cost of equity of
11.0 percent for the proxy group of electric
utili ties and 12.6 percent for the group of
non-utility companies;
o Application of the CAPM approach using
forward-looking data that best reflects the
underlying assumptions of this approach implied
a cost of equity of 12.3 percent for the
electric utilities and 11.5 percent for the
non-utili ty companies;
o Applying the CAPM method using historical
realized rates of return resulted in a cost of
equi ty of 10.8 percent for the proxy group of
utili ties and 10.2 percent for the firms in the
non-utili ty proxy group;
o My evaluation of comparable earned rates of
return expected for utili ties suggested a cost
of equity on the order of at least 11.1 percent
for the proxy group of electric utili ties;
o Considering these results, and conservativelygi ving less weight to the upper end of the
range, I concluded that the cost of equity for
the proxy groups of electric utili ties and
non-utility companies is on the order of 10.8
percent to 11.8 percent;
o Considering investors' expectations for capital
markets and the need to support financial
integri ty and fund crucial capital investment
even under adverse circumstances, it is my
opinion that this 10.8 percent to 11.8 percent
range bounds a reasonable rate of return on
common equity for Idaho Power; and,
o While this "bare-bones" cost of equity range
does not consider issuance costs, a flotation
cost adder is properly considered in
establishing an allowed ROE for Idaho Power
from wi thin this range.
Q.What is your conclusion as to the
reasonableness of the Company's capital structure?
1815 AVERA, DI 7
Idaho Power Company
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10 /
16
17
18
19
20
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25
1 A.Based on my evaluation, I concluded that a
2 common equity ratio of approximately 49 percent
3 represents a reasonable basis from which to calculate
4 Idaho Power's
5
6 /
7
8 /
9
11
12
13
14
15
1816 AVERA, DI 7a
Idaho Power Company
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10
11
12
13
14
20
21
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23
24
25
1 overall rate of return. This conclusion was based on the
2 following findings:
3 Idaho Power's proposed common equity ratio is
entirely consistent with range of
capitalizations maintained by the firms in the
proxy group of electric utilities at year-end
2007 and based on investors' expectations;
4
5
6 My conclusion is reinforced by the investment
community's focus on the need for a greater
equi ty cushion to accommodate higher operating
risks, including the uncertainties posed by
exposure to variable hydro conditions, and the
pressures of capital investments. Financial
flexibility plays a crucial role in ensuring
the wherewithal to meet the needs of customers,
and Idaho Power' s capital structure reflects
the Company's ongoing efforts to support its
credit standing and maintain access to capital
on reasonable terms.
7
8
9
Q. What other evidence did you consider in
evaluating your recommendation in this case?
15 My recommendation was reinforced by theA.
16 following findings:
17 Sensi ti vi ty to regulatory uncertainties has
increased dramatically and investors recognize
that constructive regulation is a key
ingredient in supporting utility credit
standing, and financial integrity;
.
18
19
Because of Idaho Power's reliance on
hydroelectric generation, the Company is
exposed to relatively greater risks of powercost volatility;
.Investors recognize that Idaho Power's Power
Cost Adj ustment Mechanism (" PCA") provides some
level of support for the Company's financial
integri ty, but they understand that the PCA
does not apply to 100 percent of power costs;
nor does it insulate Idaho Power from the need
1817 AVERA, DI 8
Idaho Power Company
1 to finance accrued power production and supply.costs or shield the Company from potential
2 regulatory disallowances.
3 .Idaho Power must compete for investors'capital
wi th other utili ties and businesses of
4 comparable
5
6 /
7
8 /
9
10 /
11
12
13.14
15
16
17
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23
24.25
1818 AVERA,DI 8a
Idaho Power Company
.1 risk. If Idaho Power is not provided an
opportuni ty to earn a return that is sufficient
to compensate for the underlying risks,
investors will be unwilling to supply capital;
2
3
4
Providing Idaho Power with the opportunity to
earn a return that reflects these realities is
an essential ingredient to support the
Company's financial position, which ultimately
benefits customers by ensuring reliable service
at lower long-run costs;
5
6
7 Past challenges confronting the utility
industry illustrate the need to ensure that
Idaho Power has the ability to respond
effectively to unforeseen events.
8
9
10 Ultimately, it is customers and the service area economy
11 that enjoy the rewards that come from ensuring that the
12 utility has the financial wherewithal to take whatever.13
.
actions are necessary to provide a reliable energy
14 supply.
15 II. FUAMNTAL ANALYSES
16 What is the purpose of this section?Q.
17 As a predicate to my economic and capitalA.
18 market analyses, this section examines conditions in the
19 utili ty industry generally, and for Idaho Power
20 specifically, that investors consider in evaluating their
21 required rate. of return. An understanding of these
22 fundamental factors, which drive the risks and prospects
23 for Idaho Power, is essential to develop an informed
24 opinion about investor expectations and requirements that
25 form the basis of a fair rate of return on equity.
1819 AVERA, DI 9
Idaho Power Company
.
.
.
1 A. Idaho Power Company
2 Q.Briefly describe Idaho Power.
3 Idaho Power is a wholly-owned subsidiary ofA.
4 IDACORP, Inc. ("IDACORP") and is principally engaged in
5 providing integrated retail electric utility service in a
6 24,000 square mile area in southern Idaho and eastern
7 Oregon. During 2007, Idaho Power's energy deliveries
8 totaled 17.3 million megawatt hours ("MWh"). Sales to
9 residential customers comprised 36 percent of retail
10 sales, with 27 percent to commercial, 24 percent to
11 industrial end-users, and 13 percent attributable to
12 irrigation pumping. Idaho Power also supplies firm
13 wholesale power service to various utili ties and large
14 customers under sales contracts. IPC' s service terri tory
15 experienced record-setting high temperatures during 2007
16 and due to these weather conditions and continued
17 customer growth, IPC set three newall-time system peaks.
18 At year-end 2007, Idaho Power had total assets of $3.5
19 billion, with total revenues amounting to approximately
20 $875 million.
21 In addition to its thermal baseload and peaking
22 uni ts located in Wyoming, Nevada and Idaho, Idaho Power's
23 existing generating units include 17 hydroelectric
24 generating plants located in southern Idaho and eastern
25 Oregon. The electrical output of these hydro plants,
1820 AVERA, DI 10
Idaho Power Company
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.
1 which has a significant impact on total energy costs, is
2 dependent on streamflows. Although Idaho Power estimates
3 that
4
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25
1821 AVERA, DI lOa
Idaho Power Company
.
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1 hydroelectric generation is capable of supplying
2 approximately 55 percent of total system requirements
~ under normal conditions, the Company has experienced
4 prolonged periods of persistent below-normal water
5 condi tions in the past.
6 Because approximately one-half of Idaho Power's
7 total energy requirements are provided by hydroelectric
8 facilities, the Company is exposed to a level of
9 uncertainty not faced by most utilities. While
10 hydropower confers advantages in terms of fuel cost
11 savings and diversity, reduced hydroelectric generation
12 due to below-average water conditions forces Idaho Power
13 to rely more heavily on wholesale power markets or more
14 costly thermal generating capacity to meet its resource
15 needs. As Standard & Poor's Corporation ("S&P") recently
16 observed:
1 7 A reduction in hydro generation typically increases
an electric utility's costs by requiring it to buy
18 replacement power or run more expensive generation
to serve customer loads. Low hydro generation can19 also reduce utilities' opportunity to make
off-system sales. At the same time, low hydro years20 increase regional wholesale power prices, creating
potentially a double impact - companies have to buy
21 more power than under normal conditions, paying
higher prices. 3
22
23 Investors recognize that uncertainties over water
24 conditions are a persistent operational risk associated
25 with Idaho
1822 AVERA, DIll
Idaho Power Company
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21
22
23
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2
3
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5
6 /
7
8 /
9
10
11
12
13
14
15
24 3 Standard & Poor's Corporation, "Pacific Northwest Hydrology And Its Impact
On Investor-Owned Utilities' Credit Quality," RatingsDirect (Jan. 28, 2008).
25
1823 AVERA, DI l1a
Idaho Power Company
.
.
.
1 Power. In addition to weather-related fluctuations in
2 water flows, Idaho Power is also exposed to uncertainties
3 regarding water rights and the administration of those
4 rights.
5 Idaho Power's retail electric operations are
6 subj ect to the jurisdiction of the IPUC and the Oregon
7 Public Utility Commission, with the interstate
8 jurisdiction regulated by FERC. Additionally, Idaho
9 Power's hydroelectric facilities are subj ect to licensing
10 under the Federal Power Act, which is administered by
11 FERC, as well as the Oregon Hydroelectric Act.
12 Relicensing is not automatic under federal law, and Idaho
13 Power must demonstrate that it has operated its
14 facilities in the public interest, which includes
15 adequately addressing environmental concerns. The most
16 significant of Idaho Power's relicensing efforts concerns
17 its Hells Canyon Complex ("Hells Canyon"), which
18 represents 68' percent of the Company's hydro capacity and
19 40 percent of its total generating capability.
20 In June 2003, after a prolonged period of
21 planning and consultation with interested parties, Idaho
22 Power submitted a license application for Hells Canyon
23 that included various protection, mitigation, and
24 enhancement measures in order to address environmental
25 concerns while preserving the peak and load following
1824 AVERA, DI 12
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
i operations of the facilities. The current license for
2 Hells Canyon expired at the end of July 2005 and until
3 the new multi-year license is issued, Idaho Power will
4
5 /
6
7 /
8
9 /
1825 AVERA, DI 12a
Idaho Power Company
.
.
.
1 operate the proj ect under an annual license issued by
2 FERC. Apart from significant ongoing expenditures
3 associated with proposed environmental measures, the
4 relicensing process is complex, protracted, and
5 expensi ve. As of December 31, 2007, Idaho Power had
6 accumulated $96 million of construction work in progress
7 associated with its Hells Canyon relicensing efforts.
8 Q.How are fluctuations in Idaho Power's operating
9 expenses caused by varying hydro and power market
10 condi tions accommodated in its rates?
11 A.Beginning in May 1993, Idaho Power implemented
12 a PCA, under which rates are adjusted annually to reflect
13 changes in variable power production and supply costs.
14 When hydroelectric generation is reduced and power supply
15 costs rise above those included in base rates, the PCA
16 allows Idaho Power to increase rates to recover a portion
17 of its additional costs. Conversely, rates are reduced
18 when increased hydroelectric generation leads to lower
19 power supply costs. Although the PCA provides for rates
20 to be adjusted annually, it applies to 90 percent of the
21 deviation between actual power supply costs and
22 normalized rates.
23 Q.Are there other mechanisms that affect Idaho
24 Power's rates for utility service?
25 A.Yes. Included in the provisions of Idaho
1826 AVERA, DI 13
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Power's PCA is a Load Growth Adjustment Rate ("LGAR").
2 The LGAR subtracts the cost of serving new Idaho retail
3 customers
4
5 /
6
7 /
8
9 /
1827 AVERA, DI 13a
Idaho Power Company
.
.
.
1 from the power supply costs that the Company is allowed
2 to include in its PCA. The IPUC has recognized that
3 Idaho Power would nevertheless continue to be exposed to
4 the risks of shortfalls associated with load growth. The
5 IPUC specifically noted that these uncertainties are
6 properly considered in establishing a fair ROE for Idaho
7 Power:
8 Because this process puts the Company at some
business and financial risk, it is awarded a
9 commensurate equity return. Idaho Power's current
equi ty return was set in a process that recognized
10 it would not recover the power supply costs of load
growth in the PCA mechanism. 4
11
12 In 2007 the IPUC also approved a Fixed Cost Adjustment
13 Mechanism ("FCA") for Idaho Power under a three-year
14 pilot program applicable to residential and small
15 commercial customer classes. The FCA adjusts rates
16 upward or downward to insulate the recovery of fixed
17 costs from the volume of Idaho Power's energy sales. The
18 pilot program includes various provisions related to
19 customer count and weather normalization methodology,
20 reporting requirements, and detailed disclosure of
21 demand-side management acti vi ties.
22 Q.What credit ratings have been assigned to Idaho
23 Power?
24 A.Ci ting concerns over deteriorating financial
25 metrics and the outcome of Idaho Power's last rate
1828 AVERA, DI 14
Idaho Power Company
1 proceeding before the IPUC,S&P lowered Idaho Power's.2
3 /
4
5 /
6
7 /
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25 4 Order No.30215 at 10.
1829 AVERA, DI 14a
Idaho Power Company
.
.
.
1 corporate credit rating from "BBB+" to "BBB" in January
2 2 008.5 While Moody's Investors Service ("Moody's) has so
3 far maintained the Company's issuer rating at "Baal", it
4 recently revised its outlook for Idaho Power to
5 "negative" based on similar concerns, warning investors
6 of the potential for a downgrade in the Company's credit
7 standing going forward. 6 Fitch Ratings Ltd. (" Fitch")
8 has assigned the Company an issuer default rating of
9 "BBB" and, like Moody's, has revised Idaho Power's
10 Ratings Outlook to "negative. "7
11 Q.Does Idaho Power anticipate the need to access
12 the capital markets going forward?
13 A.Most definitely. Idaho Power will require
14 capi tal investment to meet customer growth, provide for
15 necessary maintenance and replacements of its utility
16 infrastructure, as well as fund new investment in
17 electric generation, transmission and distribution
18 facili ties. Idaho Power's service area has experienced
19 strong population growth, and the Company's most recent
20 resource plan anticipates the addition of 11,000 to
21 12,000 new customers annually. 8 In
22
23 /
24
25 /
1830 AVERA, DI 15
Idaho Power Company
.
.
.
19
20
21
22
23
24
25
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
5 Standard & Poor's Corporation, "IDACORP, Idaho Power Co. Ratings
Lowered One Notch To 'BBB'; Outlook Stable, RatingsDirect (Jan. 31,
2008) .
6 Moody's Investors Service, "Moody's Changes Outlook Of Idacorp And
Sub To Negative,." Press Release (June 3, 2008).
7 Fitch Ratings Ltd., "Idaho Power Company," Global Power U. S. and
Canada Credit Analysis (Apr. 10, 2008).
8 Idaho Power Company, 2006 Integrated Resource Plan (Oct. 12, 2006)
at 1.
1831 AVERA, DI 15a
Idaho Power Company
.
.
.
20
21
22
23
24
25
1 order to keep pace with customer growth, enhance
2 transmission infrastructure, and balance generation
3 resource uncertainty Idaho Power anticipates construction
4 expenditures of approximately $900 million over the
5 period 2008-2010.9
6 Over the ten-year planning period, Idaho
7 Power's Integrated Resource Plan has identified the
8 potential need for the Company to obtain 1,063 MW of
9 supply-side capacity, which will entail additional
10 purchased power commitments and financing construction of
11 addi tional baseload generation, in addition to other
12 system upgrades. 10 Moreover, as indicated earlier, Idaho
13 Power must also bear the costs of protection, mitigation,
14 and enhancement measures associated with Hells Canyon
15 relicensing. Considering the unfavorable outlook for the
16 Company's credit standing, support for Idaho Power's
17 financial integrity and flexibility will be instrumental
18 in attracting the capital necessary to fund these
19 proj ects in an effective manner.
9 IDACORP, Inc., 2007 Form-10K Report at 27. This amount excludes
expenditures for a 250-NW combined cycle combustion turbine expected
to be operational in mid-2012 as well as any estimated costs
attributable to the Gateway West Project, which contemplates
construction of .two 500-kV transmission lines with an estimated cost
to Idaho Power of between $800 million and $1.2 billion.
10 Idaho Power Company, 2006 Integrated Resource Plan (Oct. 12, 2006)
at 95.
1832 AVERA, DI 16
Idaho Power Company
.
.
.
1 B.Utili ty Industry
2 Q.How have investors' risk perceptions for firms
3 involved in the utility industry evolved?
4 A.Since the 1990s, the industry has experienced
5 significant structural change resulting from market
6 forces and legislative and regulatory ini tiati ves.
7 Implementation of structural change and related events
8 caused investors to rethink their assessment of the
9 relati ve risks associated with the utility industry. The
10 past decade witnessed steady erosion in credit quality
11 throughout the utility industry, both as a result of
12 revised perceptions of the risks in the industry and the
13 weakened finances of the utilities themselves. S&P
14 recently reported that the maj ori ty of the companies in
15 the utility sector now fall in the triple-B rating
16 category, 11 with Fitch recently concluding that "the
17 long-term outlook is negative" for investor-owned
18 electric utilities. 12 Similarly, Moody's observed,
19 "Material negative bias appears to be developing over the
20 intermediate and longer term due to rapidly rising
21 business and operating risks. "13
22
23 /
24 /
25 /
1833 AVERA, DI 17
Idaho Power Company
.
.
.
16
17
18
19
20
21
22
23
24
25
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
11 Standard & Poor's Corporation, "U. S. Electric Utility Sector
Continues To Benefit From Strong Liquidity Amid Current Credit
Crunch," Ra tingsDirect (Mar. 27, 2008).
12 Fitch Ratings, Ltd., "U. S. Utilities, Power and Gas 2008 Outlook,"
Global Power North America Special Report (Dec. 11, 2007).
13 Moody's Investors Service, "U. S. Electric Utility Sector,"
Industry Outlook (Jan. 2008).
1834 AVERA, DI 17a
Idaho Power Company
.
.
.
1 Q.What other key factors are of concern to
2 investors?
3 A.In recent years, utili ties and their customers
4 have also had to contend with dramatic fluctuations in
5 energy costs due to ongoing price volatility in the spot
6 markets. Investors recognize that the prospect of
7 further turmoil in energy markets is an ongoing concern.
8 S&P has reported continued spikes in wholesale energy
9 market prices, 14 with Moody's warning investors of
10 ongoing exposure to "extremely volatile" energy commodity
11 costs, including purchased power prices, which are
12 heavily influenced by fuel costs. 15 Similarly, the FERC
13 Staff has continued to recognize the ongoing potential
14 for market disruption. A 2008 market assessment report
15 recognized ongoing concerns regarding tight supply and
16 congestion and observed that wholesale power prices
17 across the nation are likely to be significantly higher
18 than the previous year. 16 FERC continues to warn of load
19 pockets vulnerable to periods of high peak demand and
20 unplanned outages of generation or transmission capacity
21 and ongoing reliability concerns that
22 /
23 /
24 /
25 /
1835 AVERA, DI 18
Idaho Power Company
.
.
.
16
17
18
19
20
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
21 14 Standard & Poor's Corporation, "Fuel and Purchased Power Cost
Recovery in the Wake of Volatile Gas and Power Markets - U. s.
22 Electric Utilities to Watch" RatingsDirect (Mar. 22, 2006).
15 Moody's Investors Service, "Storm Clouds Gathering on the Horizon
23 for the North American Electric Utility Sector," Special Comment at 6
(Aug. 2007).
24 16 FERC, Office of Market Oversight and Investigations, "2008 Summer
Market and Reliability Assessment," (May 15, 2008).
25
1836 AVERA, DI 18a
Idaho Power Company
.
.
.
19
20
21
22
23
1 led FERC to establish mandatory standards for the bulk
2 power system. 17
3 Additionally, in recent years, utilities and their
4 customers have also had to contend with dramatic
5 fluctuations in natural gas costs due to ongoing price
6 volatili ty in the spot markets. 1S S&P observed that
7 "natural gas prices have proven to be very volatile,"
8 warning of a "turbulent journey" due to the uncertainty
9 associated with future fluctuations in energy costs, 19
10 and concluding: "Cost pressures from natural gas are not
11 likely to recede in the near future. "20 Fitch also
12 highlighted the challenges that fluctuations in commodity
13 prices can have for utili ties and their investors,
14 concluding that gas prices are subject to near-term and
15 longer-term fluctuations that contribute to an "adverse
16 environment" for electric utilities. 21
17 In addition, while coal-fired generation has
18 historically provided relative stability with respect to
17 See Open Commission Meeting Statement of Chairman Joseph T.
24 Kelliher, Item E-13: Mandatory Reliability Standards for the
Bulk-Power System (Docket No. RM06-16-000) (Mar. 15, 2007).
25
1837 AVERA, DI 19
Idaho Power Company
.
.
.
15
16
17
18
19
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
18 For example, the Department of Energy's Energy Information
20 Administration ("EIA") reported that the average price of gas used
by electricity generators (regulated utilities and non-regulated
21 power producers) spiked from an average price of $7.18 per Mcf for
the first eight months of 2005 to over $11.00 per Mcf in Septemer and
22 October 2005 (http://tonto.eia.doe.gov/dnav/ng/hist/n3045us3m. htm) .19 Standard & Poor's Corporation, "Top Ten Credit Issues Facing U. s.
23 Utilities," RatingsDirect (Jan. 29, 2007).
20 Id.
24 21 Fitch Ratings, Ltd., "U.S. Power and Gas 2008 Outlook," Global
Power North American Special Report, at 3 (Dec. 11, 2007).
25
1838 AVERA, DI 19a
Idaho Power Company
.
.
.
1 fuel costs, higher prices have raised investors'
2 concerns. In a 2004 article entitled "Rising Coal Prices
3 May Threaten U. s. Utility Credit Profiles," S&P noted
4 that:
5 More recently, several current and structural
developments for the coal mining industry have
6 resul ted in a dramatic increase in spot coal
prices.22
7
8 The EIA reported that average delivered coal prices for
9 electric utilities increased 9.7 percent in 2006, the
10 sixth consecutive annual rise,23 while Reuters Inc.
11 reported in May 2008 that benchmark coal prices exceeded
12 $100 per ton,. or over twice the levels of the previous
13 fall.24
14 Q.What are the key uncertainties considered by
15 investors in assessing their required rate of return for
16 Idaho Power?
17 A.Because roughly one-half of Idaho Power's total
18 energy requirements are provided by hydroelectric
19 facilities, the Company is exposed to a level of
20 uncertainty not faced by most utilities. While
21 hydropower confers advantages in terms of fuel cost
22 savings and di versi ty, reduced hydroelectric generation
23 due to below-average water conditions forces Idaho Power
24 to rely more heavily on
25 /
1839 AVERA, DI 20
Idaho Power Company
.
.
.
15
16
17
18
19
20
21
1
2
3
4 /
5
6 /
7
8 /
9
10
11
12
13
14
22 22 Standard & Poor's Corporation, "Rising Coal Prices May Threaten
U.S. Utility Credit Profiles," RatingsDirect (Aug. 12, 2004).
23 23 Energy Information Administration, Annual Coal Report 2006 at 9
(Nov. 2007).
24 24 Nichols, Bruce, "US coal prices pass $100 a ton, twice last
fall's," Reuters (May 9, 2008).
25
1840 AVERA, DI 20a
Idaho Power Company
.
.
.
1 purchased power or more costly thermal generating
2 capaci ty to meet its resource needs.
3 The prolonged drought conditions experienced in
4 the recent past have only deepened concerns over power
5 prices and fluctuations in gas costs. As S&P noted,
6 "hydro resources expose the company to substantial
7 replacement power price risk in the event of low water
8 flows. "25 S&P concluded that Idaho Power "has the
9 greatest hydro exposure" of any utility and faces "the
10 most substantial risks. "26 Investors recognize the
11 significant financial burden that constrained hydro
12 generation imposes on Idaho Power, as Moody's summarized:
13 The company's recent financial metrics, including
its coverage of interest and debt by cash flow from
operations exclusive Df working capital changes (CFO
Pre-W/C), have been pressured to a level we often
see for a regulated electric utility in the Ba
rating c~tegory. These recent metrics are the result
of unfavorable hydro conditions and the adverse
effects the recent increase to the load growth
adj ustment rate (LGAR) has had on net power supply
cost recovery under the power cost adj ustment (PCA)
mechanism. 27
14
15
16
17
18
19 Similarly, Fitch concluded that its negative outlook on
20 Idaho Power's ratings "primarily reflect persistent
21 drought
22
23
24
25
25 Standard & Poor's Corporation, "IDACORP, Idaho Power Co. Ratings
Lowered One Notch to 'BBB'; Outlook Stable," RatingsDirect (Jan. 31,
2008) .
1841 AVERA, DI 21
Idaho Power Company
.
.
.
17
18
19
20
21
22
23
24
25
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
26 Standard & PQor' s Corporation, "Pacific Northwest Hydrology And
Its Impact On Investor-Owned Utilities' Credit Quality," RatingsDirect
(Jan. 28, 2008).
27 Moody's Investors Service, "Credit Opinion: Idaho Power Company,"
Global Credi t Research (June 4, 2008).
1842 AVERA, DI 21a
Idaho Power Company
.
.
.
1 condi tions in recent years and their adverse impact on
2 the utility's cash flows, earnings and credit metrics. "28
3 Volatile energy markets, unpredictable stream
4 flows, and Idaho Power's reliance on wholesale purchases
5 to meet a portion of its resource needs expose the
6 Company to the risk of reduced cash flows and unrecovered
7 power supply costs. The IPUC has recognized "the unique
8 circumstances of Idaho Power's highly variable power
9 supply costs. "29 The Company's reliance on purchased
10 power to meet shortfalls in hydroelectric generation
11 magnifies the importance of strengthening financial
12 flexibili ty to ensure access to the cash resources and
13 interim financing required to meet any shortfall in
14 operating cash flows, as well as fund required
15 investments in the utility system.
16 Q.Does the PCA remove the risk associated with
17 fluctuations in power supply costs?
18 A.No. While the PCA provides some level of
19 support for the Company's financial integrity, it does
20 not apply to 100 percent of power costs. Moreover, even
21 for utili ties with permanent energy cost adj ustment
22 mechanisms in place, there can be a significant lag
23 between the time the utility actually incurs the
24 expenditure and when it is recovered from ratepayers.
25 This lag can impinge on the utility's
1843 AVERA, DI 22
Idaho Power Company
.
.
.
15
16
17
18
19
20
21
22
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
23 28 Fitch Ratings, Ltd., "Idaho Power Company," Global Power U. S. and
Canada Credit Analysis (Apr. 10, 2008).
24 29 Order No. 302;5 at 9.
25
1844 AVERA, DI 22a
Idaho Power Company
.
.
.
1 financial strength through reduced liquidity and higher
2 borrowings. As S&P observed:
3 Because increased purchases and higher prices are
not immediately met by increased retail revenues
4 from customers, cash flows can decline in low water
years. While PCAs and annual power cost updates can
5 mi tigate these effects, they are not designed to
completely insulate a utility from poor hydro
6 condi tions. As a result, a large annual deviation
from normal streamflow typically weakens cash7 coverage of debt and interest for a utility. 30
8 S&P recently cited exposure to high deferred
9 power costs resulting from "extremely variable" hydro
10 generation as a key challenge facing Idaho Power. 31
11 Similarly, Moody's observed that the Company's financial
12 metrics" are pressured relative to the current Baal
13 rating and we expect that the company's financial
14 performance will remain subject to the vagaries of water
15 flow conditions. "32 Moreover, even with an energy cost
16 adjustment mechanism, investors continue to recognize the
17 ongoing potential for regulatory disallowances if the
18 IPUC determines that the amounts were not prudently
19 incurred.
20
21
22 30 Standard & Poor's Corporation, "Pacific Northest Hydrology And Its
Impact On Investor-Owned Utilities' Credit Quality," RatingsDirect23 (Jan. 28, 2008).
31 Standard & Poor's Corporation, "Idaho Power Co.," Ra tingsDirect
24 (Feb. 1, 2008).
32 Moody's investors Service, "Credit Opinion: Idaho Power Company,"
Global Credit Research (June 4, 2008).25
1845 AVERA, DI 23
Idaho Power Company
.
.
.
1 Q.What other considerations affect investors'
2 evaluation of Idaho Power?
3 A.Investors are aware of the financial and
4 regulatory pressures faced by utili ties associated with
5 rising costs and the need to undertake significant
6 capi tal investments. As Moody's observed:
7 (T) here are concerns arising from the sector's
sizeable infrastructure investment plans in the face
8 of an environment of steadily rising operating
costs. Combined, these costs and investments can
9 create a continuous need for regulatory rate relief,
which in turn can increase the likelihood for
10 political and/or regulatory intervention. 33
11 Similarly, S&P noted that "onerous construction
12 programs", along with rising operating and maintenance
13 costs and volatile fuel costs, were a significant
14 challenge to the utility industry. 34 Moody's recently
15 echoed this assessment, concluding, "There are
16 significant negative trends developing over the
17 longer-term horizon. "35
18 While providing the infrastructure necessary to
19 meet the energy needs of customers is certainly
20 desirable, it imposes additional financial
21 responsibili ties on Idaho Power. As noted earlier, the
22 Company's plans include
23 /
24 /
25 /
1846 AVERA, DI 24
Idaho Power Company
.
.
.
15
16
17
18
19
20
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
21 33 Moody's Investors Service, "Storm Clouds Gathering on the Horizon
for the North American Electric Utility Sector," Special Comment
22 (Aug. 2007).
34 Standard & Poor's Corporation, "u. S. Electric Utilities Continued
23 Their Long Shift To Stability In Third Quarter," RatingsDirect (Oct.
23, 2007).
24 35 Moody's Investors Service, "u. S. Utility Sector," Industry Outlook
(Jan. 2008).
25
1847 AVERA, DI 24a
Idaho Power Company
.
.
.
1 substantial capital expenditures, including enhancements
2 to its transmission and distribution system and
3 investment in generating resources. Investors are aware
4 that the challenge of achieving timely regulatory
5 recovery associated with rising costs and burdensome
6 capi tal expenditure requirements impacts the Company's
7 abili ty to earn a fair rate of return. For example, S&P
8 cited" (rJ egulatory challenges in meeting rising costs
9 and a large capital expenditure program, resulting from
10 high customer growth," as a key weakness for Idaho
11 Power, 36 while Fitch noted that the inability to increase
12 base rates to recover anticipated capital investment
13 could lead to a downgrade in the Company's credit
14 standing.37
15 In addition, electric utili ties are confronting
16 increased environmental pressures that are imposing
17 significant uncertainties and costs. Utili ties required
18 to meet renewable portfolio standards and carbon
19 reduction goals generally must embrace energy efficiency
20 and conservation ini tiati ves that lead to decreased
21 demand and revenue erosion. In early 2007, S&P cited
22 environmental mandates, including emissions,
23 conservation,. and renewable resources, as one of the top
24 ten credit issues facing u.s.
25 /
1848 AVERA, DI 25
Idaho Power Company
.
.
.
14
15
16
17
18
19
20
21
22
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
23 36 Standard & Poor's Corporation, "Idaho Power Co.," Ra tingsDirect
(Feb. 1, 2008).
24 37 Fitch Ratings, Ltd., "Idaho Power Company," Global Power U.S. and
Canada Credit Analysis (Apr. 10, 2008).
25
1849 AVERA, DI 25a
Idaho Power Company
.
.
.
1 utili ties. 38 More recently, S&P cited the long-term
2 challenge posed by climate change legislation and
3 observed that:
4 What the ultimate outcome will be is cloudy right
now, but legislation addressing carbon emissions and
5 other greenhouse gases is extremely probable in the
near future. The credit implications of any policy
6 will be vast due to the compliance costs involved. 39
7 Similarly, Moody's noted that "increasingly
8 stringent environmental compliance mandates will elevate
9 cash outflow recovery risk", 40 while Fitch noted that the
10 electric utility industry would be "a primary target" of
11 new environmental legislation, and concluded:"The
12 murkiness of the future policies and regulations on
13 carbon emissions is another factor clouding Fitch's
14 long-term view of electric utili ties. "41 Compliance with
15 these evolving standards almost certainty will mean
16 significant capital expenditures.
17
18
19
20
21 38 Standard & Poor's Corporation, "Top Ten Credit Issues Facing u. S.
Utilities," RatíngsDirect (Jan. 29, 2007).
22 39 Standard & Poor's Corporation, "Upgrades Lead In u. S. Electric
Utility Industry In 2007," RatíngsDirect (Jan. 17, 2008).
23 40 Moody's Investors Service, "U.S. Electric Utility Sector,"
Industry Outlook (Jan. 2008).
24 41 Fitch Ratingsi Ltd., "U.S. Utilities, Power and Gas 2008 Outlook,"
Global Power North America Special Report (Dec. 11, 2007).
25
1850 AVERA, DI 26
Idaho Power Company
.
.
.
1 Q.Have investors recognized that electric
2 utilities face additional risks because of the impact of
3 industry restructuring on transmission operations?
4 A.Yes. Policy evolution in the transmission area
5 has been wide reaching and Idaho Power must address
6 changes in the electric transmission function of its
7 business. S&P confirmed a "continued lack of clarity from
8 lawmakers and regulators on the regulatory framework
9 surrounding transmission proj ects. "42 Transmission
10 operations have become increasingly complex and investors
11 have recognized that difficulties in obtaining permits
12 and uncertainty over the adequacy of allowed rates of
13 return have contributed to heightened risk and fueled
14 concerns regarding the need for additional investment in
15 the transmission sector of the electric power industry.
16 III. CAITAL MAT ESTIMATES
17
18
Q.What is the purpose of this section?
A.This section presents capital market estimates
19 of the cost of equity. First, I examine the concept of
20 the cost of equity, along with the risk-return tradeoff
21 principle fundamental to capital markets. Next, I
22 describe DCF and CAPM analyses conducted to estimate the
23 cost of equity for benchmark groups of comparable risk
24 firms and
25 /
1851 AVERA, DI 27
Idaho Power Company
1.2
3 /
4
5 /
6
7 /
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24 42 Standard & Poor's Corporation,"Capital Spending On Electric
Transmission Is On The Upswing Around The World," RatingsDirect (Aug..25 7,2006) .
1852 AVERA, DI 27a
Idaho Power Company
.
.
.
10
1 evaluate comparable earned rates of return expected for
2 utili ties. Finally, I examine other factors (e. g. ,
3 flotation costs) that are properly considered in
4 evaluating a fair rate of return on equity.
5 A.Overview
6 Q.What role does the rate of return on common
7 equi ty play in a utility's rates?
8 A.The return on common equity is the cost of
9 inducing and retaining investment in the utility's
physical plant and assets.This investment is necessary
11 to finance the asset base needed to provide utility
12 service. Investors will commit money to a particular
13 investment only if they expect it to produce a return
14 commensurate with those from other investments with
15 comparable risks. Moreover, the return on common equity
16 is integral in achieving the sound regulatory obj ecti ves
17 of rates that are sufficient to: 1) fairly compensate
18 capi tal investment in the utility, 2) enable the utility
19 to offer a return adequate to attract new capital on
20 reasonable terms, and 3) maintain the utility's financial
21 integrity. Meeting these obj ecti ves allows the utility
22 to fulfill its obligation to provide reliable service
23 while meeting the needs of customers through necessary
24 system expansion.
25
1853 AVERA, DI 28
Idaho Power Company
.
.
.
1 Q.What fundamental economic principle underlies
2 any evaluation of investors' required return on equity?
3 A.The fundamental economic principle underlying
4 the cost of equity concept is the notion that investors
5 are risk averse. In capital markets where relatively
6 risk-free assets are available (e.g., u.s. Treasury
7 securi ties), investors can be induced to hold riskier
8 assets only if they are offered a premium, or additional
9 return, above the rate of return on a risk-free asset.
10 Because all assets compete with each other for investor
11 funds, riskier assets must yield a higher expected rate
12 of return than safer assets to induce investors to invest
13 and hold them.
14 Given this risk-return tradeoff, the required
15 rate of return (k) from an asset (i) can be generally
16 expressed as:
17 ki Rf + RPi
18 where:Rf Risk-free rate of return; and
19 RPi Risk premium required to holdrisky asset i.
20
21 Thus, the required rate of return for a particular asset
22 at any point in time is a function of: 1) the yield on
23 risk-free assets, and 2) i ts relative risk, with
24 investors demanding correspondingly larger risk premiums
25 for assets bearing greater risk.
1854 AVERA, DI 29
Idaho Power Company
.
.
.
1 Q.Is there evidence that the risk-return tradeoff
2 principle actually operates in the capital markets?
3 A.Yes~ The risk-return tradeoff can be readily
4 documented in segments of the capital markets where
5 required rates of return can be directly inferred from
6 market data and where generally accepted measures of risk
7 exist. Bond yields, for example, reflect investors'
8 expected rates of return, and bond ratings measure the
9 risk of individual bond issues. The observed yields on
10 government securities, which are considered free of
11 default risk, and bonds of various rating categories
12 demonstrate that the risk-return tradeoff does, in fact,
13 exist in the capital markets.
14 Q.Does the risk-return tradeoff observed with
15 fixed income securities extend to common stocks and other
16 assets?
17 A.It is generally accepted that the risk-return
18 tradeoff evidenced with long-term debt extends to all
19 assets. Documenting the risk-return tradeoff for assets
20 other than fixed income securities, however, is
21 complicated by two factors. First, there is no standard
22 measure of risk applicable to all assets. Second, for
23 most assets - including common stock - required rates of
24 return cannot. be directly observed. Yet there is every
25 reason to believe that investors exhibit risk aversion in
1855 AVERA, DI 30
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 deciding whether or not to hold common stocks and other
2 assets, just as when choosing among fixed-income
3 securi ties.
4
5 /
6
7 /
8
9 /
1856 AVERA, DI 30a
Idaho Power Company
.
.
.
1 Q.Is this risk-return tradeoff limited to
2 differences between firms?
3 A.No. The risk-return tradeoff principle applies
4 not only to investments in different firms, but also to
5 different securities issued by the same firm. The
6 securities issued by a utility vary considerably in risk
7 because they have different characteristics and
8 priori ties. Long-term debt secured by a mortgage on
9 property is senior among all capital in its claim on a
10 utility's net revenues and is, therefore, the least
11 risky. Following bonds are other debt instruments also
12 holding contractual claims on the utility's net revenues,
13 such as subordinated debentures. The last investors in
14 line are common shareholders. They receive only the net
15 revenues, if any, remaining after all other claimants
16 have been paid. As a result, the rate of return that
17 investors require from a utility's common stock, the most
18 junior and riskiest of its securities, must be
19 considerably higher than the yield offered by the
20 utili ty' s senior, long-term debt.
21 Q.What does the above discussion imply with
22 respect to estimating the cost of equity for a utility?
23 A.Al though the cost of equity cannot be observed
24 directly, it is a function of the returns available from
25 other investment alternatives and the risks to which the
1857 AVERA, DI 31
Idaho Power Company
1 equi ty capital is exposed.Because it is unobservable,.2 the cost of equity for a particular utility must be
3 estimated by
4
5 /
6
7 /
8
9 /
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
1858 AVERA,DI 31a
Idaho Power Company
.
.
.
1 analyzing information about capital market conditions
2 generally, assessing the relative risks of the company
3 specifically, and employing various quanti tati ve methods
4 that focus on investors' required rates of return. These
5 various quantitative methods typically attempt to infer
6 investors' required rates of return from stock prices,
7 interest rates, or other capital market data.
8 Q.Did you rely on a single method to estimate the
9 cost of equity for Idaho Power?
10 A.No. I used both the DCF and CAPM methods to
11 estimate the cost of equity, as well as referencing
12 comparable earned rates of return expected for utilities.
13 In my opinion, comparing estimates produced by one method
14 wi th those produced by other approaches ensures that
15 estimates of the cost of equity pass fundamental tests of
16 reasonableness and economic logic. In addition, I
17 applied the DÇF and CAPM to alternative proxy groups of
18 comparable risk firms.
19 Q.Are you aware that the IPUC has traditionally
20 relied primarily on the DCF and comparable earnings
21 methods?
22 A.Yes, although the Commission has also evidenced
23 a willingness to weigh al ternati ves in evaluating an
24 allowed ROE. For example, while noting that it had not
25 focused on the CAPM for determining the cost of equity,
1859 AVERA, DI 32
Idaho Power Company
1 the IPUC recognized in Order No.29505 that "methods to.2 evaluate a common equity rate of return are imperfect
3 predictors"and
4
5 /
6
7 /
8
9 /
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
1860 AVERA,DI 32a
Idaho Power Company
.
.
.
13
14
1 emphasized "that by evaluating all the methods presented
2 in this case and using each as a check on the other," the
3 Commission had avoided the pitfalls associated with
4 reliance on a single method. 43
5 B.Discounted Cash Flow Anaiyses
6 Q.How are DCF models used to estimate the cost of
7 equity?
8 A.DCF models attempt to replicate the market
9 valuation process that sets the price investors are
10 willing to pay for a share of a company's stock. The
11 model rests on the assumption that investors evaluate the
12 risks and expected rates of return from all securities in
the capital markets. Gi ven these expectations, the price
of each stock is adjusted by the market until investors
15 are adequately compensated for the risks they bear.
16 Therefore, we can look to the market to determine what
17 investors believe a share of common stock is worth. By
18 estimating the cash flows investors expect to receive
19 from the stock in the way of future dividends and capital
20 gains, we can calculate their required rate of return.
21 In other words, the cash flows that investors expect from
22 a stock are estimated, and given its current market
23 price, we can. "back-into" the discount rate, or cost of
24 equi ty, that investors implicitly used in bidding the
25 stock to that price.
1861 AVERA, DI 33
Idaho Power Company
.
.
.
18
19
20
21
22
23
24
25
1 Q.What market valuation process underlies DCF
2 models?
3 A.DCF models assume that the price of a share of
4 common stock is equal to the present value of the
5 expected cash flows (i. e., future dividends and stock
6 price) that will be received while holding the stock,
7 discounted at investors' required rate of return. Thus,
8 the cost of equity is the discount rate that equates the
9 current price of a share of stock with the present value
10 of all expected cash flows from the stock. Notationally,
11 the general form of the DCF model is as follows:
12 Po =Di D2 Dt+. . . + +
(1 + ke) t
Pt
13
+
( 1 + ke) i (l + ke )2 (1 + ke) t
14 where:Po Current price per share;Pt =Expected future price per share inperiodt;
Dt Expected dividend per share in period t;ke =Cost of equity.
15
16
17
43 Order No. 29505 at 38 (emphasis added).
1862 AVERA, DI 34
Idaho Power Company
.
.
.
15
1 Q.What form of the DCF model is customarily used
2 to estimate the cost of equity in rate cases?
3 A.Rather than developing annual estimates of cash
4 flows into perpetuity, the DCF model can be simplified to
5 a "constant growth" form: 44
6 Po =Di
7 ke-g
8 where: Po = Current price per share;
Di = Expected dividend per share in coming
year;
ke = Cost of equity;
g = Investors' long-term growthexpectations.
9
10
11
12 The cost of equity (ke) can be isolated by rearranging
13 terms:
14 Dike = -+g
- Po
16 This constant growth form of the DCF model recognizes
17 that the rate. of return to stockholders consists of two
18 parts: 1) dividend yield (Di/Po), and 2) growth (g). In
19 other words, investors expect to receive a portion of
20 their total return in the form of current dividends and
21 the remainder. through price appreciation.
22
23
24
25
44 The constant growth DCF model is dependent on a number of strict
assumptions, which in practice are never strictly met. These include
a constant growth rate for both dividends and earnings; a stable
1863 AVERA, DI 35
Idaho Power Company
.
.
.
15
16
17
18
19
20
21
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
22 dividend payout ratio; the discount rate exceeds the growth rate; a
constant growth rate for book value and price; a constant earned rate
23 of return on book value; no sales of stock at a price above or below
book value; a constant price-earnings ratio; a constant discount rate
24 (i.e., no changes in risk or interest rate levels and a flat yield
curve); and all of the above extend to infinity.
25
1864 AVERA, DI 35a
Idaho Power Company
.
.
..
1 Q.How did you define the utility proxy group you
2 used to implement the DCF model?
3 A.In estimating the cost of equity, the DCF model
4 is typically applied to publicly traded firms engaged in
5 similar business acti vi ties. In order to reflect the
6 risks and prospects associated with Idaho Power's
7 electric utility operations, my utility proxy group was
8 composed of those dividend-paying companies included by
9 The Value Line Investment Survey ("Value Line") in its
10 Electric Utilities Industry groups with: (1) S&P
11 corporate credit ratings between "BBB-" and "BBB+", (2) a
12 Value Line Safety Rank of "2" or "3", and (3) a Value
13 Line Financial Strength Rating of "B" to "B++". I
14 excluded three firms that otherwise would have been in
15 the proxy group, but are not appropriate for inclusion
16 because they either do not pay common dividends (El Paso
17 Electric Company) or are in the process of being acquired
18 (Energy East Corporation and Puget Energy, Inc.). These
19 criteria resulted in a proxy group composed of 27
20 comparable risk utilities. I refer to this group as the
21 "Utility Proxy Group."
22 Q.Do these criteria provide obj ecti ve evidence
23 that investors would view the firms in your Utility Proxy
24 Group as risk-comparable?
25 A.Yes~ Credit ratings are assigned by
1865 AVERA, DI 36
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 independent rating agencies for the purpose of providing
2 investors with a broad assessment of the creditworthiness
3 of a firm.
4
5 /
6
7 /
8
9 /
1866 AVERA, DI 36a
Idaho Power Company
.
.
.
1 Because the rating agencies' evaluation includes
2 virtually all of the factors normally considered
3 important in assessing a firm' s relative credit standing,
4 corporate credit ratings provide a broad measure of
5 overall investment risk that is readily available to
6 investors. Widely cited in the investment community and
7 referenced by investors as an obj ecti ve measure of risk,
8 credi t ratings are also frequently used as a primary risk
9 indicator in establishing proxy groups to estimate the
10 cost of equity.
11 While credit ratings provide the most widely
12 referenced bepchmark for investment risks, other quality
13 rankings published by investment advisory services also
14 provide relative assessments of risk that are considered
15 by investors in forming their expectations. Value Line's
16 primary risk indicator is its Safety Rank, which ranges
17 from "1" (Safest) to "5" (Riskiest). This overall risk
18 measure is intended to capture the total risk of a stock,
19 and incorporates elements of stock price stability and
20 financial strength . Given that Value Line is perhaps the
21 most widely available source of investment advisory
22 information, its Safety Rank provides a useful guide to
23 the likely risk perceptions of investors.
24 The Financial Strength Rating is designed as a
25 guide to overall financial strength and creditworthiness,
1867 AVERA, DI 37
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 with the key inputs including financial leverage,
2 business volatility measures, and company size. Value
3 Line's Financial Strength
4
5 /
6
7 /
8
9 /
1868 AVERA, DI 37a
Idaho Power Company
.
.
.
1 Ratings range from "A++" (strongest) down to "C"
2 (weakest) in nine steps.
3 As discussed earlier, Idaho Power is rated
4 "BBB" by S&P, which is identical to the average for the
5 firms in the Utility Proxy Group. Meanwhile, Value Line
6 has assigned IDACORP a Safety Rank of "3" and a Financial
7 Strength Rating of "B+". 45 Based on these criteria, which
8 reflect obj ecti ve, published indicators that incorporate
9 consideration of a broad spectrum of risks, including
10 financial and business position, relative size, and
11 exposure to company specific factors, investors are
12 likely to regard this group as having comparable risks
13 and prospects.
14 Q.What steps are required to apply the DCF model?
15 A.The first step in implementing the constant
16 growth DCF model is to determine the expected dividend
17 yield (Di/Po) for the firm in question. This is usually
18 calculated based on an estimate of dividends to be paid
19 in the coming year divided by the current price of the
20 stock. The second, and more controversial, step is to
21 estimate investors' long-term growth expectations (g) for
22 the firm. The final step is to sum the firm' s dividend
23 yield and estimated growth rate to arrive at an estimate
24 of its cost of equity.
25 /
1869 AVERA, DI 38
Idaho Power Company
.
.
.
15
16
17
18
19
20
21
22
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
23 45 As noted ealrier, Idaho Power is a wholly-owned subsidiary of
IDACORP. Because Value Line's risk indicators apply to publicly
24 traded common stock, I referenced published values for IDACORP in
selecting a risk-comparable proxy group.
25
1870 AVERA, DI 38a
Idaho Power Company
.
.
.
1 Q.How was the dividend yield for the Utility
2 Proxy Group determined?
3 A.Estimates of dividends to be paid by each of
4 these utili ties over the next twelve months, obtained
5 from Value Line, served as Di. This annual dividend was
6 then divided by the corresponding stock price for each
7 utili ty to arrive at the expected dividend yield. The
8 expected dividends, stock prices, and resulting dividend
9 yields for the firms in the Utility Proxy Group are
10 presented on Exhibit No. 17. As shown there, dividend
11 yields for the firms in the Utility Proxy Group ranged
12 from 1.2 percent to 6.1 percent.
13 Q. What is the next step in applying the constant
14 growth DCF model?
15 A.The next step is to evaluate long-term growth
16 expectations, or "g", for the firm in question. In
1 7 constant growth DCF theory, earnings, dividends, book
18 value, and market price are all assumed to grow in
19 lockstep, and the growth horizon of the DCF model is
20 infini te. But implementation of the DCF model is more
21 than just a theoretical exercise; it is an attempt to
22 replicate the mechanism investors used to arrive at
23 observable stock prices. A wide variety of techniques
24 can be used to derive growth rates, but the only "g" that
25 matters in applying the DCF model is the value that
investors expect.
1871 AVERA, DI 39
Idaho Power Company
.
.
.
1 Q.Are historical growth rates likely to be
2 representati ve of investors' expectations for utili ties?
3 A.No. If past trends in earnings, dividends, and
4 book value are to be representative of investors'
5 expectations for the future, then the historical
6 condi tions giving rise to these growth rates should be
7 expected to continue. That is clearly not the case for
8 utili ties, where structural and industry changes have led
9 to declining dividends, earnings pressure, and, in many
10 cases, significant write-offs. While these conditions
11 serve to depress historical growth measures, they are not
12 representative of long-term expectations for the utility
13 industry. Moreover, to the extent historical trends for
14 utilities are meaningful, they are also captured in
15 proj ected growth rates, since securities analysts also
16 routinely examine and assess the impact and continued
17 relevance (if any) of historical trends.
18 Q.What are investors most likely to consider in
19 developing their long-term growth expectations?
20 A.While the DCF model is technically concerned
21 with growth in dividend cash flows, implementation of
22 this DCF model is solely concerned with replicating the
23 forward-looking evaluation of real-world investors. In
24 the case of utilities, dividend growth rates are not
25 likely to provide a meaningful guide to investors'
1872 AVERA, DI 40
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 current growth expectations. This is because utilities
2 have significantly altered their
3
4 /
5
6 /
7
8 /
9
1873 AVERA, DI 40a
Idaho Power Company
.
.
.
1 di vidend policies in response to more accentuated
2 business risks in the industry. 46 As a result of this
3 trend towards a more conservative payout ratio, dividend
4 growth in the utility industry has remained largely
5 stagnant as utili ties conserve financial resources to
6 provide a hedge against heightened uncertainties.
7 As payout ratios for firms in the utility
8 industry trended downward, investors' focus has
9 increasingly shifted from dividends to earnings as a
10 measure of long-term growth. Future trends in earnings,
11 which provide the source for future dividends and
12 ul timately support share prices, play a pivotal role in
13 determining investors' long-term growth expectations.
14 The importance of earnings in evaluating investors'
15 expectations and requirements is well accepted in the
16 investment community. As noted in Finding Reality in
17 Reported Earnings published by the Association for
18 Investment Management and Research:
19 (E) arnings, presumably, are the basis for the
investment benefits that we all seek. "Healthy20 earnings equal healthy investment benefits"
seems a logical equation, but earnings are also21 a scorecard by which we compare companies, a
filter through which we assess management, and22 a crystal ball in which we try to foretell
future performance. 4723 /
24 /
25 /
1874 AVERA, DI 41
Idaho Power Company
.
.
.
15
16
17
18
19
20
21
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
22 46 For example, the payout ratio for electric utilities fell from
approximately 80 percent historically to on the order of 60 percent.
23 The Value Line Investment Survey (Sep. 15, 1995 at 161, Dec. 28, 2007
at 695).
24 47 Association for Investment Management and Research, "Finding
Reality in Reported Earnings: An Overview", p. 1 (Dec. 4, 1996).
25
1875 AVERA, DI 41a
Idaho Power Company
.
.
.
1 Value Line's near-term proj ections and its Timeliness
2 Rank,48 which is the principal investment rating assigned
3 to each individual stock, are also based primarily on
4 various quanti tati ve analyses of earnings. As Value Line
5 explained:
6 The future earnings rank accounts for 65% in
the determination of relative price change in7 the future; the other two variables (current
earnings rank and current price rank) explain8 35%.49
9 The fact that investment advisory services focus on
10 growth in earnings indicates that the investment
11 community regards this as a superior indicator of future
12 long-term growth. Indeed, "A Study of Financial
13 Analysts: Practice and Theory," published in the
14 Financial Analysts Journal, reported the results of a
15 survey conducted to determine what analytical techniques
16 investment analysts actually use. 50 Respondents were
17 asked to rank' the relative importance of earnings,
18 dividends, cash flow, and book value in analyzing
19 securi ties. Of the 297 analysts that responded, only 3
20 ranked dividends first while 276 ranked it last. The
21 article concluded:
22 Earnings and cash flow are considered far more
important than book value and dividends. 51
23
24 /
25 /
1876 AVERA, DI 42
Idaho Power Company
.
.
.
14
15
16
17
18
19
20
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
21 48 The Timeliness Rank presents Value Line's assessment of relative
price performance during the next six to twelve months based on a22 five point scale.
49 The Value Line Investment Survey, Subscriber's Guide, p. 53.
23 50 Block, Stanley B., "A Study of Financial Analysts: Practice and
Theory", Financial Analysts Journal (July/August 1999).24 51 Id. at 88.
25
1877 AVERA, DI 42a
Idaho Power Company
.
.
.
14
1 More recently, the Financial Analysts Journal reported
2 the results of a study of the relationship between
3 valuations based on al ternati ve multiples and actual
4 market prices, which concluded, "In all cases studied,
5 earnings dominated operating cash flows and dividends. "52
6 Q .What are security analysts currently proj ecting
7 in the way of growth for the firms in the Utility Proxy
8 Group?
9 A.The earnings growth proj ections for each of the
10 firms in the Utility Proxy Group reported by Value Line,
11 Thomson Financial ("Thomson"), 53 and Zacks Investment
12 Research ("Zacks") are displayed on Exhibit No. 17.
13 Q.How else are investors' expectations of future
long-term growth prospects often estimated for use in the
15 constant growth DCF model?
16 A.Based on the assumptions underlying constant
17 growth theory, conventional applications of the constant
18 growth DCF model often examine the relationship between
19 retained earnings and earned rates of return as an
20 indication of the sustainable growth investors might
21 expect from the reinvestment of earnings within a firm.
22 The sustainable growth rate is calculated by the
23 following formula:
24 /
25 /
1878 AVERA, DI 43
Idaho Power Company
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.
.
16
17
18
19
20
21
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
22 52 Liu, Jing, Nissim, Doron, & Thomas, Jacob, "Is Cash Flow King in
Valuations?," Financial Analysts Journal, Vol. 63, No. 2 (March/April
23 2007) at 56.
53 Thomson Financial, an arm of The Thomson Corporation, compiles and
24 publishes consensus securities analyst growth rates under the IBES
and First Call brands.
25
1879 AVERA, DI 43a
Idaho Power Company
.
.
.
1
2
g br +sv
where:g =investors'expected long-term growthrate;
b expected retention ratio;r =expected earned return on equity;s percent of common equity expected tobeissuedannuallyasnewcommonstock;and,
v =expected equity accretion rate.
3
4
5
6
7 Q.What is the purpose of the "sv" term?
8 A.Under DCF theory, the "sv" factor is a
9 component of the growth rate designed to capture the
10 impact of issuing new common stock at a price above, or
11 below, book value. When a company's stock price is
12 greater than its book value per share, the per-share
13 contribution in excess of book value associated with new
14 stock issues will accrue to the current shareholders.
15 This increase to the book value of existing shareholders
16 leads to higher expected earnings and dividends, with the
17 "sv" factor incorporating this additional growth
18 component.
19 Q.What growth rate does the earnings retention
20 method suggest for the Utility Proxy Group?
21 A.The sustainable , "br+sv" growth rates for each
22 firm in the Utility Proxy Group are summarized on Exhibit
23 No. 17, with the underlying details being presented on
24 Exhibit No. 18. For each firm, the expected retention
25 ratio (b) was calculated based on Value Line's proj ected
1880 AVERA, DI 44
Idaho Power Company
.
.
.
1 earnings per share by projected net book value. Because
2 Value Line reports end-of-year book values, an adjustment
3 was incorporated to compute an average rate of return
4 over the year, consistent with the theory underlying this
5 approach to estimating investors' growth expectations.
6 Meanwhile, the percent of common equity expected to be
7 issued annually as new common stock (s) was equal to the
8 product of the proj ected market-to-book ratio and growth
9 in common shares outstanding, while the equity accretion
10 rate (v) was computed as 1 minus the inverse of the
11 proj ected market-to-book ratio.
12 Q.What cost of equity estimates were implied for
13 the Utility Proxy Group using the DCF model?
14 A. After combining the dividend yields and
15 respecti ve growth proj ections for each utility, the
16 resul ting cost of equity estimates are shown on Exhibit
17 No. 17.
18 Q.In evaluating the results of the constant
19 growth DCF model, is it appropriate to eliminate cost of
20 equity estimates that fail to meet threshold tests of
21 economic logic?
22 A.Yes. It is a basic economic principle that
23 investors can be induced to hold more risky assets only
24 if they expect to earn a return to compensate them for
25 their risk bearing. As a result, the rate of return that
1882 AVERA, DI 45
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 investors require from a utility's common stock, the most
2 junior and highest risk of its securities, must be
3
4 /
5
6 /
7
8 /
9
1883 AVERA, DI 45a
Idaho Power Company
.
.
.
1 considerably higher than the yield offered by senior,
2 long-term debt. Consistent with this principle, the DCF
3 range for the Utility Proxy Group must be adjusted to
4 eliminate cost of equity estimates that fail fundamental
5 tests of economic logic.
6 Q.Hav~ similar tests been applied by regulators?
7 A.Yes. The FERC has noted that adjustments are
8 justified where applications of the DCF approach produce
9 illogical results. FERC evaluates DCF results against
10 observable yields on long-term public utility debt and
11 has recognized that it is appropriate to eliminate cost
12 of equity estimates that do not sufficiently exceed this
13 threshold. In a 2000 opinion establishing its current
14 precedent for determining ROEs for electric utili ties,
15 for example, FERC concluded:
16 An adjustment to this data is appropriate in
the case of PG&E' s low-end return of 8.42%,
17 which is comparable to the average Moody's "A"
grade public utility bond yield of 8.06%, for
18 October 1999. Because investors cannot be
expected to purchase stock if debt, which has19 less risk than stock, yields essentially the
same return, this low-end return cannot be20 considered reliable in this case. 54
21 Similarly, in its October 2006 decision in Kern River Gas
22 Transmission Company, FERC noted that:
23 (T)he 7.31 and 7.32% costs of equity for El
Paso and Williams found by the ALJ are only 11024 and 122
25 54 Southern California Edison Company, 92 FERC ~ 61,070 (2000) at
p. 22.
1884 AVERA, DI 46
Idaho Power Company
.
.
.
1
2
basis points above that average yield for
public utility debt. 55
3 FERC upheld the opinion of Staff and the Administrative
4 Law Judge that cost of equity estimates for these two
5 proxy group companies "were too low to be credible." 56
6 Q.What does this test of logic imply with respect
7 to the DCF results for the Utility Proxy Group?
8 A.The average credit rating associated with the
9 firms in the Utility Proxy group is "BBB". Corporate
10 credit ratings of "BBB-", "BBB", and "BBB+" are all
11 considered part of the triple-B rating category, with
12 Moody's monthly yields on triple-B bonds averaging
13 approximately 6.9 percent in May 2008.57 As highlighted
14 on Exhibit No. 17, eight of the individual equity
15 estimates for the firms in the Utility Proxy Group fell
16 below 8 percent. 58 In light of the risk-return tradeoff
17 principle, it is inconceivable that investors are not
18 requiring a substantially higher rate of return for
19 holding common stock, which is the riskiest of a
20 utility's securities. As a result, these values provide
21 little guidance as to the returns investors require from
22 the common stock of an electric utility.
23 /
24 /
25 /
1885 AVERA, DI 47
Idaho Power Company
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15
16
17
18
19
20
21
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
22 55 Kern River Gas Transmission Company, Opinion No. 486 117 FERC 1
61,077 at P 140 & n. 227 (2006).23 56 Id.
57 Moody's Investors Service, www.CreditTrends.com
24 58 As highlighted on Exhibit 2, these DCF estimates ranged from 6.2
percent to 7. 8 percent.
25
1886 AVERA, DI 47a
Idaho Power Company
.
.
.
1 Q.Do you also recommend excluding cost of equity
2 estimates at the high end of the range of DCF results?
3 A.Yes. The upper end of the cost of equity range
4 produced by the DCF analysis presented in Exhibit No. 17
5 was set by a cost of equity estimate of 23.0 percent for
6 Allegheny Energy, with eleven other DCF estimates ranging
7 from 17. 1 percent to 22. 7 percent. Compared with the
8 balance of the remaining estimates, these results are
9 extreme outliers and should also be excluded in
10 evaluating the results of the DCF model for the Utility
11 Proxy Group. This is also consistent with the threshold
12 adopted by FERC, which established that a 17. 7 percent
13 DCF estimate for was "an extreme outlier" and should be
14 disregarded. 59
15 Q.What cost of equity is implied by your DCF
16 resul ts for the Utility Proxy Group?
17 A.As shown on Exhibit No. 17 and summarized in
18 Table 1, below, after eliminating illogical low- and
19 high-end values, application of the constant growth DCF
20 model resulted in the following cost of equity estimates:
21
22
23
24
25
DCF RESULTS
Growth Rate
Value Line
IBES
Zacks
br+sv
TABLE i
- UTILITY PROXY GROUP
Average Cost of Equity
11.7%
11.6%
11.1%
9.5%
59 iso New England, Inc., 109 FERC ~ 61,147 at P 205 (2004).
1887 AVERA, DI 48
Idaho Power Company
.
.
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1 Q.What did you conclude based on the results of
2 the DCF analyses for the Utility Proxy Group?
3 A.Taken together, and considering the relative
4 strengths and weaknesses associated with the al ternati ve
5 growth measures, I concluded that the constant growth DCF
6 resul ts for the Electric Utility Proxy Group implied a
7 cost of equity of 11.0 percent.
8 Q.How else can the DCF model be applied to
9 estimate the ROE for Idaho Power?
10 A.Under the regulatory standards established by
11 Hope and Bluefield, the salient criteria in establishing
12 a meaningful benchmark to evaluate a fair rate of return
13 is relative risk, not the particular business acti vi ty or
14 degree of regulation . Utilities must compete for
15 capital, not just against firms in their own industry,
16 but with other investment opportunities of comparable
17 risk. With regulation taking the place of competi ti ve
18 market forces, required returns for utilities should be
19 in line with those of non-utility firms of comparable
20 risk operating under the constraints of free competition.
21 Consistent with this accepted regulatory standard, I also
22 applied the DCF model to a reference group of comparable
23 risk companies in the non-utility sectors of the economy.
24 I refer to this group as the "Non-Utility Proxy Group".
25
1888 AVERA, DI 49
Idaho Power Company
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1 Q.What criteria did you apply to develop the
2 Non-Utili ty Proxy Group?
3 A.To reflect investors' risk perceptions in
4 developing the Non-Utility Proxy Group, my assessment of
5 comparable risk relied on three objective benchmarks for
6 the risks associated with common stocks - Value Line's
7 Safety Rank, Financial Strength Rating, and beta. Gi ven
8 that Value Line is perhaps the most widely available
9 source of investment advisory information, its Safety
10 Rank and Financial Strength Rating provide useful
11 guidance regarding the risk perceptions of investors.
12 These obj ecti ve, published indicators incorporate
13 consideration of a broad spectrum of risks, including
14 financial and business position, relative size, and
15 exposure to company-specific factors.
16 My comparable risk proxy group was composed of
17 those U. S. companies followed by Value Line that: 1) pay
18 common dividends; 2) have a Safety Rank of "1"; 3) have a
19 Financial Strength Rating of "A" or above; and 4) have
20 beta values of 0.90 or less. 60 Consistent with the
21 development ot my Utility Proxy Group, I also eliminated
22 firms with below-investment grade credit ratings. Table
23 2 compares the Non-
24
25
60 This threshold corresponds to the average betas for the Electric
Utility Proxy Group of 0.88.
1889 AVERA, DI 50
Idaho Power Company
.
.
.
14
15
1 Utili ty Proxy Group with the Utility Proxy Group and
2 Idaho Power across four key indicators of investment
3 risk:614 TABLE 2
COMPARISON OF RISK INDICATORS
5
6
S&P Value Line
Credit Safety Financial
Rating Rank Strength BetaNon-Utility Group A+i A+0.79
Utili ty Proxy Group BBB 3 B+0.88IdahoPowerBBB3B+0.90
7
8
9
10 Considered along with S&P's corporate credit ratings, a
11 comparison of these Value Line indicators suggests that
12 the investment risks associated with the Non-Utility
13 Proxy Group are below those of the group of utili ties and
Idaho Power.
Q.What were the results of your DCF analysis for
16 the Non-Utility Proxy Group?
17 A.As shown on Exhibit No. 19, I applied the DCF
18 model to the Non-Utility Proxy Group in exactly the same
19 manner described earlier for the Utility Proxy Group. 62
20 As summarized in Table 3, below, after eliminating
21 illogical low- and high-end values, application of the
22 constant growth DCF model resulted in the following cost
23 of equity estimates:
24 /
25
1890 AVERA, DI 51
Idaho Power Company
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15
16
17
18
19
20
1
2 /
3
4 /
5
6 /
7
8
9
10
11
12
13
14
21 61 Because Idaho Power has no publicly traded common stock, the Value
Lihe risk measures shown reflect those published for its parent,
22 IDACORP. As explained earlier, in my opinion these risk measures are
indicati ve of the risk of Idaho Power.
23 62 Exhibit 5 contains the details underlying the calculation of the
br+sv growth rates for the Non-Utility Proxy Group.
24
25
1891 AVERA, DI 51a
Idaho Power Company
.
.
.
16
1
2
TABLE 3
DCF RESULTS - NON-UTILITY PROXY GROUP
3
Growth Rate
Value Line
IBES
Zacks
br+sv
Average Cost of Equity
12.3%
12.8%
12.5%
12.7%
4
5
6 Q.What did you conclude based on the results of
7 the DCF analyses for the Non-Utility Proxy Group?
8 A.Taken together, I concluded that the constant
9 growth DCF results for the Non-Utility Proxy Group
10 implied a cost of equity of 12.6 percent. As discussed
11 earlier, reference to the Non-Utility Proxy Group is
12 consistent with established regulatory principles and
13 required returns for utilities should be in line with
14 those of non utility firms of comparable risk operating
15 under the constraints of free competition.
Q.Do you believe the DCF model should be relied
17 on exclusively to evaluate a reasonable ROE for the proxy
18 groups or Idaho Power?
19 A.No. Because the cost of equity is
20 unobservable, no single method should be viewed in
21 isolation. While the DCF model has been routinely relied
22 on in regulatory proceedings as one guide to investors'
23 required return, it is widely recognized that no single
24 method can be regarded as definitive. For example, a
25 publication of the Society of Utility and Financial
1892 AVERA, DI 52
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10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Analysts (formerly the National Society of Rate of Return
2 Analysts), concluded that:
3
4 /
5
6 /
7
8 /
9
1893 AVERA, DI 52a
Idaho Power Company
.
.
.
14
15
1
2
Each model requires the exercise of judgment as
to the reasonableness of the underlying
assumptions of the methodology and on the
reasonableness of the proxies used to validate
the theory. Each model has its own way of
examining investor behavior, its own premises,
and its own set of simplifications of reality.
Each method proceeds from different fundamental
premises, most of which cannot be validated
empirically. Investors clearly do not
subscribe to any singular method, nor does the
stock price reflect the application of anyone
single method by investors. 63
3
4
5
6
7
8 Moreover, evidence suggests that reliance on the DCF
9 model as a tool for estimating investors' required rate
10 of return has declined outside the regulatory sphere,
11 with the CAPM' being "the dominant model for estimating
12 the cost of equity. "64
13 C. Capi tal Asset Pricing Model
Q.Please describe the CAPM.
A.The' CAPM is generally considered to be the most
16 widely referenced method for estimating the cost of
17 equi ty both among academicians and professional
18 practitioners, with the pioneering researchers of this
19 method receiving the Nobel Prize in 1990. The CAPM is a
20 theory of market equilibrium that measures risk using the
21 beta coefficient. Because investors are assumed to be
22 fully diversified, the
23 /
24 /
25 /
1894 AVERA, DI 53
Idaho Power Company
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14
15
16
17
18
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
19 63 Parcell, David c., "The Cost of Capital - A Practitioner's Guide,"
Society of Utility and Regulatory Financial Analysts (1997) at Part20 2, p. 4.
64 See e.g., Bruner, R.F., Eades, K.M., Harris, R.S., and Higgins,
21 R. C., "Best Practices in Estimating Cost of Capital: Survey and
Synthesis," Financial Practice and Education (1998).
22
23
24
25
1895 AVERA, DI 53a
Idaho Power Company
.
.
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17
1 relevant risk of an individual asset (e. g., common stock)
2 is its volatility relative to the market as a whole, with
3 beta reflecting the tendency of a stock's price to follow
4 changes in the market. The CAPM is mathematically
5 expressed as:
6 Rj = Rf + ß j (Rm - Rf)Rj = required rate of return for stock j;Rf = risk-free rate;
Rm = expected return on the market
portfolio; and,
ßj beta, or systematic risk, for stock
j .
where:
7
8
9
10 Like the DCF model, the CAPM is an ex-ante, or
11 forward-looking model based on expectations of the
12 future. As a result, in order to produce a meaningful
13 estimate of investors' required rate of return, the CAPM
14 should be applied using estimates that reflect the
15 expectations of actual investors in the market, not with
16 backward-looking, historical data.
Q.How did you apply the CAPM to estimate the cost
18 of equity?
19 A.App~ication of the CAPM to the utility proxy
20 group based on a forward-looking estimate for investors'
21 required rate of return from common stocks is presented
22 on Exhibit No. 21. In order to capture the expectations
23 of today' s investors in current capital markets, the
24 expected market rate of return was estimated by
25 conducting a DCF analysis on the dividend paying firms in
the S&P 500 Composite Index ("S&P 500").
1896 AVERA, DI 54
Idaho Power Company
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1 The dividend yield for each firm was obtained
2 from Value Line, with the growth rate being equal to the
3 average of the earnings growth proj ections for each firm
4 published by IBES and Value Line, with each firm's
5 di vidend yield and growth rate being weighted by its
6 proportionate share of total market value. Based on the
7 weighted average of the projections for the 350
8 indi vidual firms, current estimates imply an average
9 growth rate over the next five years of 10.6 percent.
10 Combining this average growth rate with a dividend yìeld
11 of 2.4 percent results in a current cost of equity
12 estimate for the market as a whole of approximately 12.9
13 percent. Subtracting a 4.6 percent risk-free rate based
14 on the average yield on 20 year Treasury bonds for May
15 2008 produced a market equity risk premium of 8.3
16 percent. As shown on Exhibit No. 21, multiplying this
17 risk premium by the average Value Line beta of 0.88 for
18 the Utility Proxy Group, and then adding the resulting
19 7.3 percent risk premium to the average long-term
20 Treasury bond yield, indicated an ROE of approximately
21 11.9 percent.
22 Q.What cost of equity was indicated for the
23 Non-Utility Proxy Group based on this forward-looking
24 application of the CAPM?
25 A.As shown on Exhibit No. 22, applying the
1897 AVERA, DI 55
Idaho Power Company
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11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 forward-looking CAPM approach to the firms in the
2 Non-Utili ty Proxy Group implied a cost of equity estimate
3 of 11.2 percent.
4
5 /
6
7 /
8
9 /
1898 AVERA, DI 55a
Idaho Power Company
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14
15
1 Q.What other CAPM analyses did you conduct to
2 estimate the cost of equity?
3 A.In addition, because it is frequently
4 referenced in regulatory proceedings, I also applied the
5 CAPM using risk premiums based on historical realized
6 rates of return published by Ibbotson Associates (now
7 Morningstar). Reference to historical data represents
8 one way to apply the CAPM, but these realized rates of
9 return reflect, at best, an indirect estimate of
10 investors' current requirements. As a result,
11 forward-looking applications of the CAPM that look
12 directly at investors' expectations in the capital
13 markets are apt to provide a more meaningful guide to
investors' required rate of return.
Q.What CAPM cost of equity is produced based on
16 historical realized rates of return for stocks and
17 long-term government bonds?
18 A.Application of the CAPM to the firms in the
19 utili ty and non-utility proxy groups using risk premiums
20 based on historical realized rates of return published by
21 Ibbotson Associates is presented on Exhibits Nos. 23 and
22 24, respectively. As shown there, this historical CAPM
23 approach implied a cost of equity of 10.8 percent for the
24 Utility Proxy Group and 10.2 percent for the firms in the
25 Non-Utili ty Proxy Group.
1899 AVERA, DI 56
Idaho Power Company
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.
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1 D.Comparable Earnings Method
2 Q.What other analyses did you conduct to estimate
3 the cost of equity?
4 A.As I noted earlier, I also evaluated the cost
5 of equity using the comparable earnings method.
6 Reference to rates of return available from al ternati ve
7 investments of comparable risk can provide an important
8 benchmark in assessing the return necessary to assure
9 confidence in the financial integrity of a firm and its
10 ability to attract capital. This comparable earnings
11 approach is consistent with the economic underpinnings
12 for a fair rate of return established by the United
13 States Supreme Court and has been traditionally relied on
14 by the IPUC. Moreover, it avoids the complexities and
15 limi tations of capital market methods and instead focuses
16 on the returns earned on book equity, which are readily
17 available to investors.
18 Q.What rates of return on equity are indicated
19 for utili ties' based on this approach?
20 A.Wi th respect to expectations for electric
21 utili ties generally, Value Line reports that its analysts
22 anticipate an average rate of return on common equity for
23 the electric utility industry of 11.5 percent in 2008 and
24 2009 and 13.0 percent over its three-to-five year
25 forecast horizon.65 Meanwhile, Value Line expects that
1900 AVERA, DI 57
Idaho Power Company
1 natural gas.2
3 /
4
5 /
6
7 /
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24 65 The Value Line Investment Survey at 1S0 (May 30, 2008)..25
1901 AVERA,DI 57a
Idaho Power Company
.
.
.
20
21
1 distribution utili ties will earn an average rate of
2 return on common equity of 11.5 percent in 2008 and 12.0
3 percent in 2009, and 12.5 percent over the years
4 2011-2013.66
5 For the firms in the Utility Proxy Group
6 specifically, the returns on common equity proj ected by
7 Value Line over its three-to-fi ve year forecast horizon
8 are shown on Exhibit No. 25. Consistent with the
9 rational underlying the development of the br+sv growth
10 rates discussed earlier, these year-end values were
11 converted to average returns using the same adjustment
12 factor developed in Exhibit No. 18. As shown on Exhibit
13 No. 25, after' eliminating extreme outliers, Value Line's
14 proj ections suggested an average ROE of 11.1 percent.
15 Q.What return on equity is indicated by the
16 resul ts of the comparable earnings approach?
17 A.Bas~d on the results discussed above, I
18 concluded that the comparable earnings approach implies a
19 fair rate of return on equity of at least 11.1 percent.
E.Sumary of Results
Q.Please summarize the results of your
22 quanti tati ve analyses.
23 A.The cost of equity estimates implied by my
24 quanti tati ve analyses are summarized in Table 4 below:
25
66 The Value Line Investment Survey at 446 (Mar. 14, 2008).
1902 AVERA, DI 58
Idaho Power Company
.
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14
1
2
TABLE 4
SUMMARY OF QUANTITATIVE RESULTS
3
Method
DCF
CAPM
Forward-LookingHistorical
Comparable Earnings
11.2%
10.2%
Utility
11. 0%
Non-Utili ty
12.6%
4 11. 9%
10.8%
11.1%5
6 F.Flotation Costs
7 Q.What other considerations are relevant in
8 setting the return on equity for a utility?
9 A.The common equity used to finance the
10 investment in utility assets is provided from either the
11 sale of stock in the capital markets or from retained
12 earnings not paid out as dividends. When equity is
13 raised through the sale of common stock, there are costs
associated with "floating" the new equity securities.
15 These flotation costs include services such as legal,
16 accounting, and printing, as well as the fees and
17 discounts paid to compensate brokers for selling the
18 stock to the public. Also, some argue that the "market
19 pressure" from the additional supply of common stock and
20 other market factors may further reduce the amount of
21 funds a utility nets when it issues common equity.
22 Q.Is there an established mechanism for a utility
23 to recognize equity issuance costs?
24
25
A.No.' While debt flotation costs are recorded on
the books of the utility, amortized over the life of the
1903 AVERA, DI 59
Idaho Power Company
.
.
.
1 issue, and thus increase the effective cost of debt
2 capi tal, there is no similar accounting treatment to
3 ensure that equity flotation costs are recorded and
4 ultimately recognized. Alternatively, no rate of return
5 is authorized on flotation costs necessarily incurred to
6 obtain a portion of the equity capital used to finance
7 plant. In other words, equity flotation costs are not
8 included in a utility's rate base because neither that
9 portion of the gross proceeds from the sale of common
10 stock used to pay flotation costs is available to invest
11 in plant and equipment, nor are flotation costs
12 capi tali zed as an intangible asset. Unless some
13 provision is made to recognize these issuance costs, a
14 utili ty' s revenue requirements will not fully reflect all
15 of the costs incurred for the use of investors' funds.
16 Because there is no accounting convention to accumulate
17 the flotation. costs associated with equity issues, they
18 must be accounted for indirectly, with an upward
19 adjustment to the cost of equity being the most logical
20 mechanism.
21 Q.What is the magnitude of the adjustment to the
22 "bare bones" cost of equity to account for issuance
23 costs?
24 A.There are any number of ways in which a
25 flotation cost adjustment can be calculated, and the
1904 AVERA, DI 60
Idaho Power Company
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10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 adj ustment can range from just a few basis points to more
2 than a full percent. One of the most common methods used
3 to account for flotation costs in regulatory proceedings
4 is to apply an average flotation-cost percentage to a
5 utili ty' s dividend
6
7 /
8
9 /
1905 AVERA, DI 60a
Idaho Power Company
.
.
.
1 yield. Based on a review of the finance literature,
2 Regulatory Finance: Utilities' Cost of Capital concluded:
3 The flotation cost allowance requires an
estimated adjustment to the return on equity of
approximately 5% to 10%, depending on the size
and risk of the issue. 67
4
5
6 Al ternati vely, a study of data from Morgan Stanley
7 regarding issuance costs associated with utility common
8 stock issuances suggests an average flotation cost
9 percentage of 3.6 percent. 68 Applying these expense
10 percentages to a representati ve dividend yield for a
11 utili ty of 3.9 percent implies a flotation cost
12 adj ustment on the order of 14 to 39 basis points.
13 Q. Has the IPUC Staff previously considered
14 flotation costs in establishing a fair ROE for Idaho
15 Power?
16 A.Yes. For example, in Case No. IPC-E-07-8, IPUC
17 Staff witness Terri Carlock noted that she had adj usted
18 her DCF analysis to incorporate an allowance for
19 flotation costs. 69 While issuance costs are a legitimate
20 consideration in setting the return on equity for a
21 utility,
22
23
24 67 Roger A. Morin, Regulatory Finance: Utilities' Cost of Capital,
1994, at 166.
25
1906 AVERA, DI 61
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12
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16
17
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2
3 /
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7 /
8
9
18 68 Application of Yankee Gas Services Company for a Rate Increase,
DPUC Docket No. 04-06-01, Direct Testimony of George J. Eckenroth
19 (Jul. 2, 2004) at Exhibit GJE-11.1. Updating the results presented
by Mr. Eckenroth through April 2005 also resulted in an average20 flotation cost percentage of 3.6 percent.
69 Case No. IPC-E-07-8, Direct Testimony of Terri Carlock at 10 (Dec.
21 10, 2007).
22
23
24
25
1907 AVERA, DI 61a
Idaho Power Company
.
.
.
1 a specific adjustment for flotation costs was not
2 included in defining my recommended ROE range.
3 iv. RETUR ON EQUITY FOR IDAHO POWER COMPANY
4 Q. What is the purpose of this section?
5 A. In addition to presenting the conclusions of my
6 evaluation of. a fair rate of return on equity for Idaho
7 Power, this section also discusses the relationship
8 between ROE and preservation of a utility's financial
9 integrity and the ability to attract capital under
10 reasonable terms on a sustainable basis.
11 A. Implications for Financial Integrity
12 Q. Why is it important to allow Idaho Power an
13 adequate ROE?
14 A. Given the social and economic importance of the
15 utili ty industry, it is essential to maintain reliable
16 and economical service to all consumers. While Idaho
17 Power remains committed to deliver reliable service, a
18 utility's ability to fulfill its mandate can be
19 compromised if it lacks the necessary financial
20 wherewi thal. Coupled with the ongoing potential for
21 energy market volatility, Idaho Power's exposure to
22 variations in hydroelectric generation and plans for
23 significant infrastructure investment pose a number of
24 potential challenges that might require the relatively
25 swift commitment of significant capital resources
1908 AVERA, DI 62
Idaho Power Company
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.
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17
1 in order to maintain the high level of service that
2 customers have come to expect.
3 As documented earlier, the maj or rating
4 agencies have warned of exposure to uncertainties
5 associated with political and regulatory developments,
6 especially in view of the potential for high and volatile
7 commodi ty costs in competitive energy markets. Investors
8 understand how swiftly unforeseen circumstances can lead
9 to deterioration in a utility's financial condition, and
10 stakeholders have discovered first hand how difficult and
11 complex it can be to remedy the situation after the fact.
12 For a utility with an obligation to provide reliable
13 service, investors' increased reticence to supply
14 addi tional capital during times of crisis highlights the
15 necessi ty of preserving the flexibility necessary to
16 overcome periods of adverse capital market conditions.
Q.What role does regulation play in ensuring
18 Idaho Power's access to capital?
19 A.Considering investors' heightened awareness of
20 the risks associated with the utility industry and the
21 damage that results when a utility's financial
22 flexibili ty is compromised, supportive regulation remains
23 crucial to Idaho Power's access to capital. Investors
24 recognize that regulation has its own risks, and that
25 constructive regulation is a key ingredient in supporting
1909 AVERA, DI 63
Idaho Power Company
1 utili ty credit ratings and financial integrity,.2 particularly during times
3
4 /
5
6 /
7
8 /
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
1910 AVERA, DI 63a
Idaho Power Company
.
.
.
1 of adverse conditions. S&P concluded, "The political
2 atmosphere will remain highly charged, fostering
3 uncertainty. "70 Moody's echoed these sentiments, noting
4 that "regulatory relationships are becoming more
5 important" in an era of broadly rising costs and
6 uncertainties, 71 and concluding:
7 (T) here are concerns arising from the sector's
sizeable infrastructure investment plans in the
face of an environment of steadily rising
operating costs. Combined, these costs and
investments can create a continuous need for
regulatory rate relief, which in turn can
increase the likelihood for political and/or
regulatory intervention. 72
8
9
10
11
12 The rapid rise in wholesale energy prices has
13 heightened investor concerns over the implications for
14 regulatory uncertainty. The Wall Street Journal reported
15 in May 2008 that escalating fuel costs were leading to
16 soaring utility bills across the nation, raising the
17 specter that social pressures could impact the outcome of
18 regulatory proceedings. 73 S&P noted that, while timely
19 cost recovery was paramount to maintaining credit quality
20 in the utility sector, an "environment of rising customer
21 tariffs, coupled
22
23
24
25 70 Standard & Poor's Corporation, "Top Ten Credit Issues Facing U. S.
Utilities," RatingsDirect (Jan. 29, 2007).
1911 AVERA, DI 64
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18
19
20
21
22
23
24
25
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
71 Moody's Investors Service, "Regulatory Pressures Increase for U. S.
Electric Utilities," Special Comment (March 2007).
72 Moody's Investors Service, "Storm Clouds Gathering on the Horizon
for the North American Electric Utility Sector," Special Comment
(Aug. 2007).
73 Smith, Rebecca, "Expect a Jolt When Opening The Electric Bill,"
Wall Street Journal at D1 (May 7, 2008).
1912 AVERA, DI 64a
Idaho Power Company
.
.
.
1 with a sluggish economy, portend a difficult regulatory
2 environment in coming years. "74
3 Q.What danger does an inadequate rate of return
4 pose to Idaho Power?
5 A.Gi ven the pressure on Idaho Power's financial
6 metrics and its declining credit standing, which is
7 exemplified by the negative outlook assigned by Moody's
8 and Fitch, the perception of a lack of regulatory support
9 would almost certainly lead to further downgrades. As
10 Moody's concluded, "A key consideration in order for
11 (Idaho Power) to stabilize its rating outlook and
12 maintain its Baal senior unsecured rating will be the
13 extent to which the IPUC is supportive in any future
14 regulatory filings. "75
15 At the same time, Idaho Power's plans include
16 significant plant investment to ensure that the energy
17 needs of its service terri tory are met in a reliable and
18 cost-effective manner. Fitch noted that '(m) eaningful
19 price increases will be required to recover planned
20 capi tal expenditures to meet infrastructure and growth
21 requirements,76 while S&P cited" (r) egulatory challenges
22 in meeting rising costs and a large capital expenditure
23
24
25 74 Standard & Poor's Corporation, "Top 10 U. S. Electric Utility
Credit Issues For 2008 And Beyond," RatingsDirect (Jan. 28, 2008).
1913 AVERA, DI 65
Idaho Power Company
1.2
3 /
4
/
5
6
/
7
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23 75 Moody's Investors Service,"Credit Opinion:Idaho Power Company,"
Global Credi t Research (June 4,2008) .
24 76 Fitch Ratings,Ltd. ,"Idaho Power Company,"Global Power u. S.and
Canada Credi t Analysis (Apr.10,2008) ..25
1914 AVERA, DI 65a
Idaho Power Company
.
.
.
1 program" as a key risk exposure. 77 While providing the
2 infrastructure necessary to meet the energy needs of
3 customers is certainly desirable, it imposes additional
4 financial responsibilities on Idaho Power. To continue
5 to meet these challenges successfully and economically,
6 it is crucial. that Idaho Power receive adequate support
7 to buttress its credit standing.
8 Q.Do customers benefit by enhancing the utility's
9 financial flexibility?
10 A.Yes. While providing an ROE that is sufficient
11 to maintain Idaho Power's ability to attract capital,
12 even in times of financial and market stress, is
13 consistent with the economic requirements embodied in the
14 Supreme Court's Hope and Bluefield decisions, it is also
15 in customers' best interests. Ultimately, it is
I16 customers ~nd the service area economy that enjoy the
17 benefi ts that come from ensuring that the utility has the
18 financial wherewithal to take whatever actions are
19 required to ensure reliable service. By the same token,
20 customers also bear a significant burden when the ability
21 of the utility to attract necessary capital is impaired
22 and service quality is compromised.
23
24
25
77 Standard & Poor's Corporation, "Idaho Power Co.," Ra tingsDirect
(Feb. 1, 2008).
1915 AVERA, DI 66
Idaho Power Company
.
.
.
1 B.Capi tal Structure
2 Q.Is an evaluation of the capital structure
3 maintained by a utility relevant in assessing its return
4 on equity?
5 A.Yes. Other things equal, a higher debt ratio,
6 or lower common equity ratio, translates into increased
7 financial risk for all investors. A greater amount of
8 debt means more investors have a senior claim on
9 available cash flow, thereby reducing the certainty that
10 each will receive his contractual payments. This
11 increases the risks to which lenders are exposed, and
12 they require correspondingly higher rates of interest.
13 From common shareholders' standpoint, a higher debt ratio
14 means that there are proportionately more investors ahead
15 of them, thereby increasing the uncertainty as to the
16 amount of cash flow, if any, that will remain.
17 Q.What common equity ratio is implicit in Idaho
18 Power's requested capital structure?
19 A.Idaho Power's capital structure is presented in
20 the testimony of Mr. Steve Keen. As summarized in his
21 testimony, the common equity ratio used to compute Idaho
22 Power's overall rate of return was approximately 49
23 percent in this filing.
24 Q.What was the average capitalization maintained
25 by the Utility Proxy Group?
1916 AVERA, DI 67
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 A.As shown on Exhibit No. 26, for the firms in
2 the Utility Proxy Group, common equity ratios at December
3 31,
4
5 /
6
7 /
8
9 /
1917 AVERA, DI 67a
Idaho Power Company
.
.
.
1 2007 ranged from 13.8 percent to 57.9 percent and
2 averaged 43.3 percent. Value Line expects that the
3 average common equity ratio for the proxy group of
4 electric utili ties will average 47.6 percent over the
5 next three to five years, with the individual common
6 equity ratios ranging from 29.0 percent to 59.5 percent.
7 Q.What implication do the uncertainties facing
8 the utility industry have for the capital structures
9 maintained by electric utili ties?
10 A.As discussed earlier, utili ties are facing
11 energy market volatility, rising cost structures, the
12 need to finance significant capital investment plans,
13 uncertainties over accommodating future environmental
14 mandates, and' ongoing regulatory risks. Coupled with a
15 decline in credit quality, these considerations warrant a
16 stronger balance sheet to deal with an increasingly
17 uncertain and competi ti ve market. A more conservative
18 financial profile, in the form of a higher common equity
19 ratio, is consistent with increasing uncertainties and
20 the need to maintain the continuous access to capital
21 that is required to fund operations and necessary system
22 investment, even during times of adverse capital market
23 conditions.
24 Moody's has warned investors of the risks
25 associated with debt leverage and fixed obligations and
1918 AVERA, DI 68
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 advised utilities not to squander the opportunity to
2 strengthen the
3
4 /
5
6 /
7
8 /
9
1919 AVERA, DI 68a
Idaho Power Company
1 balance sheet as a buffer against future uncertainties. 78.2 Moody's recently noted that, absent a stronger equity
3 cushion, utili ties would be faced with lower credit
4 ratings in the face of rising business and operating
5 risks:
6 There are significant negative trends
developing over the longer-term horizon. This
7 developing negative concern primarily relates
to our view that the sector's overall business
8 and operating risks are rising - at an
increasingly fast pace - but that the overall9 financial profile remains relatively steady. A
rising risk profile accompanied by a relatively10 stable balance sheet profile would ultimately
resul t in credit quality deterioration. 79
11
12 This is especially the case for electric utili ties that
13 are exposed to potential significant fluctuations in.14 power supply costs, such as Idaho Power.
15 Q.What other factors do investors consider in
16 their assessment of a company's capital structure?
17 A.Because power purchase agreements (" PPAs") and
18 other contractual commitments typically obligate the
19 utility to make specified minimum payments akin to those
20 associated with traditional debt financing, investors
21 consider a portion of these obligations as debt in
22 evaluating total financial risks. Similarly, when a
23 utility enters into a mandated PPA with a Qualifying
24 Facili ty under PURPA, the.25
1920 AVERA, DI 69
Idaho Power Company
.
.
.
14
15
16
17
18
19
20
21
22
23
24
25
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
78 Moody's Investors Service,
Horizon for the North American
Comment (Aug. 2007).
79 Moody's Investors Service,
Industry Outlook (Jan. 2008).
"Storm Clouds Gathering on the
Electric Utility Sector," Special
"U. S. Electric Utility Sector,"
1921 AVERA, DI 69a
Idaho Power Company
.
.
.
1 fixed charges associated with the contract increase the
2 utili ty' s financial risk in the same way that long-term
3 debt and other financial obligations increase financial
4 leverage.
5 Reflecting the longstanding perception of
6 investors that the fixed obligations associated with
7 off-balance sheet obligations diminish a utility's
8 credi tworthiness and financial flexibility, the
9 implications of these commitments have been repeatedly
10 cited by major bond rating agencies in connection with
11 assessments of utility financial risks. For example, in
12 explaining its evaluation of the credit implications of
13 off-balance sheet obligations, S&P affirmed its position
14 that such agreements give rise to "debt equivalents" and
15 that the incr~ased financial risk must be considered in
16 evaluating a utility's credit risks.so
17 Q.What did you conclude with respect to the
18 Company's capital structure?
19 A.Based on my evaluation, I concluded that Idaho
20 Power's requested capital structure represents a
21 reasonable mix of capital sources from which to calculate
22 the Company's overall rate of return. Idaho Power's
23 requested common equity ratio of approximately 49 percent
24 is consistent with the range of capitalizations implied
25 for the Utility Proxy
1922 AVERA, DI 70
Idaho Power Company
.
.
.
14
15
16
17
18
19
20
21
22
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
23 80 Standard & Poor's Corporation, "Standard & Poor's Methodology For
Imputing Debt For u. S. Utili ties' Power Purchase Agreements,"
24 RatingsDirect (May 7, 2007).
25
1923 AVERA, DI 70a
Idaho Power Company
.
.
.
i Group based on year-end 2007 data and Value Line's Line's
2 near-term proj ections.
3 While industry averages provide one benchmark
4 for comparison, each firm must select its capitalization
5 based on the risks and prospects it faces, as well its
6 specific needs to access the capital markets. A public
7 utili ty with an obligation to serve must maintain ready
8 access to capital under reasonable terms so that it can
9 meet the service requirements of its customers. The need
10 for access becomes even more important when the company
11 has capital requirements over a period of years, and
12 financing must be continuously available, even during
13 unfavorable capital market conditions.
14 The decline in Idaho Power's credit standing
15 and the heightened uncertainty associated with energy
16 market volatility magnifies the importance of preserving
17 financial flexibility. Idaho Power's capital structure
18 reflects the Company's ongoing efforts to support its
19 financial integrity and maintain access to capital on
20 reasonable terms. As indicated earlier, the challenges
21 posed by significant capital requirements, volatile
22 energy prices, and reliance on hydro generation and
23 wholesale markets magnifies the importance of preserving
24 financial flexibility. The rating agencies have observed
25 that Idaho Power's financial metrics have been under
1924 AVERA, DI 71
Idaho Power Company
.
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
1 pressure, and utilities with higher leverage may be
2 foreclosed from additional borrowing, especially
3
4 /
5
6 /
7
8 /
9
1925 AVERA, DI 71a
Idaho Power Company
.
.
.
1 during times of stress. In this regard, Idaho Power's
2 equity ratio reflects the challenges posed by its
3 resource mix, as well as the burden of significant
4 capi tal spending requirements.
5 c.Return on Equity Recommendation
6 Q.Please summarize the results of your analyses.
7 A.Reflecting the fact that investors' required
8 ROE is unobservable and no single method should be viewed
9 in isolation, I considered the results of both the DCF
10 and CAPM methods and evaluated comparable earned rates of
11 return expected for utilities. In order to reflect the
12 risks and prospects associated with Idaho Power's
13 jurisdictional electric utility operations, my analyses
14 focused on a proxy group of twenty-seven comparable risk
15 electric utili ties. Consistent with the fact that
16 utili ties must compete for capital with firms outside
17 their own industry, I also referenced a proxy group of
18 comparable risk companies in the non-utility sectors of
19 the economy.
20 My application of the constant growth DCF model
21 considered three alternative growth measures based on
22 proj ected earnings growth, as well as the sustainable,
23 "br+sv" growth rate for each firm in the respective proxy
24 groups. In addition, I evaluated the reasonableness of
25 the resulting DCF estimates and eliminated low- and
1926 AVERA, DI 72
Idaho Power Company
.
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
1 high-end outliers that failed to meet threshold tests of
2 economic logic. My CAPM analyses focused on
3 forward-looking data
4
5 /
6
7 /
8
9 /
1927 AVERA, DI 72a
Idaho Power Company
.
.
1 that best reflects the underlying assumptions of this
2 approach, as well as considering historical risk
3 premiums. The results of my al ternati ve analyses were
4 summarized earlier in Table 4, which is reproduced below:5 TABLE 4
SUMY OF QUANTITATIVE RESULTS
6
7
Method
DCF
CAPM
Forward-LookingHistorical
Comparable Earnings
11. 2%
10.2%
Utility
11. 0%
Non-Utili ty
12.6%
8
9
11.9%
10.8%
11.1%
10 Based on my assessment of the relative strengths and
11 weaknesses inherent in each method, and conservatively
12 gi ving less emphasis to the upper-most end of the range
13 of results, I concluded that the cost of equity indicated
14 by my analyses is in the 10.8 percent to 11.8 percent
15 range.
16 Q.What then is your conclusion as to a fair ROE
17 range for Idaho Power?
18 A.In evaluating the rate of return for Idaho
19 Power , it is important to consider investors' continued
20 focus on the unsettled conditions in restructured
21 wholesale energy markets, the Company's ongoing exposure
22 to these markets to meet a portion of its energy supply,
23 as well as other risks associated with the utility
24 industry, such as heightened exposure to regulatory.25 uncertainties.
1928 AVERA, DI 73
Idaho Power Company
.
.
20
21
22
23
24.25
1 As explained above, I concluded that the fair
2 rate of return on equity range was 10.8 percent to 11.8
3 percent. Considering capital market expectations, the
4 potential uncertainties faced by Idaho Power, the
5 Company's unique exposure to fluctuations in
6 hydroelectric generation, and the economic requirements
7 necessary to maintain financial integrity and support
8 addi tional capital investment even under adverse
9 circumstances, it is my opinion that this represents a
10 fair and reasonable ROE range for Idaho Power. While
11 this "bare-bones" cost of equity range does not consider
12 issuance costs, a flotation cost adjustment is properly
13 considered in establishing an allowed ROE for Idaho Power
14 from wi thin this range.
15 Q.Does this conclude your pre-filed direct
16 testimony?
17 A.Yes~
18
19
1929 AVERA, DI 74
Idaho Power Company
.
.
20
1 Q.Please state your name and business address.
2 A.William E. Avera, 3907 Red River, Austin,
3 Texas, 78751.
4 Q.Are you the same William E. Avera that
5 previously submitted direct testimony in this case?
6 A.Yes, I am.
7 Q.What is the purpose of your rebuttal?
8 A.The purpose of my testimony is to respond to
9 the direct testimony of Terri Carlock, submitted on
10 behalf of the Staff of the Idaho Public Utilities
11 Commission (" IPUC"). In addition, I will also rebut the
12 recommendations contained in the direct testimony of
13 Matthew I. Kahal, on behalf of the United States
14 Department of Energy, and Dennis E. Peseau, on behalf of
15 Micron Technology, Inc., concerning the return on equity
16 ("ROE") for the jurisdictional utility operations of
17 Idaho Power Company (" Idaho Power" or "the Company").
18 Q.Please summarize the conclusions of your
19 testimony.
A.Wi th respect to the testimony of Ms. Carlock, I
21 concluded that her recommendations were understated
22 because of her failure to consider the implications of
23 current capital market conditions, as well as the fact
24 that her discounted cash flow ("DCF") analysis focused.25 primarily
1930 AVERA, DI REB 1
Idaho Power Company
1 on a single firm and her evaluation ignored the results.2 of other accepted methods of estimating the cost of
3 equity. Additionally, Ms. Carlock's assessment of
4 relative risks focused exclusively on Idaho Power's
5 relatively low rates, while ignoring the substantial
6 uncertainties and higher investment risks that investors
7 must bear to provide the benefits of lower electricity
8 costs to customers. The dramatic increase in the cost of
9 long-term capital, the upward shift in investors' risk
10 perceptions, and the results of the Capital Asset Pricing
11 Model ("CAPM") all support a rate of return above the
12 upper end of Ms. Carlock's recommended ROE range.
.13 Similarly, Mr. Kahal' s recommendations are
14 biased downward because he failed to reflect current
15 capi tal market conditions or exclude illogical estimates
16 in evaluating the results of his analyses. Similarly,
17 there is no basis for Mr. Kahal' s criticisms of my proxy
18 group and his al ternati ve application of the CAPM is
19 flawed and should be rejected. Meanwhile, Dr.Peseau
20 mischaracterized the implications of bond yield trends
21 and - like Ms. Carlock and Mr. Kahal - ignored the higher
22 risks now associated with Idaho Power. Considering the
23 adverse conditions in today's capital markets, the ROE
24 recommendations of Ms. Carlock, Mr. Kahal, and Dr. Peseau.25 portend further deterioration in Idaho Power's finances
if adopted.
1931 AVERA, DI REB 2
Idaho Power Company
1 II. THRESHOLD ISSUE.2 Q.Dr. Avera, is it possible to distill the many
3 complexi ties associated with estimating investors'
4 required rate of return into a single, threshold issue?
5 A.Yes. While the details underlying a
6 determination of the cost of equity are all significant
7 to a rate of return analyst, there is one fundamental
8 requirement that any ROE recommendation must satisfy
9 before it can be considered reasonable . Competition for
10 capital is intense, and utilities such as Idaho Power
11 must be granted the opportunity to earn an ROE comparable
12 to contemporaneous returns available from al ternati ve
13 investments if they are to maintain their financial.14 flexibili ty arid ability to attract capital.
15 Rather than becoming bogged down in lengthy,
16 academic arguments over the merits of one quantitative
17 approach versus another, the Commission can make a
18 determination on the key, threshold question: "Do the ROE
19 recommendations of Ms. Carlock, Mr. Kahal, and Dr. Peseau
20 meet the threshold test of reasonableness required by
21 established regulatory and economic standards governing a
22 fair rate of return on equity?" Based on the evidence
23 discussed subsequently, the answer is, "No."
24 Q.What role does regulation play in ensuring.25 Idaho Power's access to capital?
1932 AVERA, DI REB 3
Idaho Power Company
.
.
.
1 A.Considering investors' heightened awareness of
2 the risks associated with the electric power industry and
3 the implications of ongoing volatility in the markets for
4 long-term capi tal, supportive regulation remains crucial
5 in preserving Idaho Power's access to capital. Capital
6 markets recog~ize that constructive regulation is a key
7 ingredient in supporting utility credit ratings and
8 financial integrity, particularly during times of adverse
9 condi tions. Moreover, considering the magnitude of the
10 events that have recently occurred, investors'
11 sensi ti vi ty to market and regulatory uncertainties has
12 increased dramatically.
13 Q. Is it widely accepted that a utility's ability
14 to attract capital must be considered in establishing a
15 fair rate of return?
16 A.Yes. Ms. Carlock and I agree that the
17 authorized rate of return should be competitive with
18 returns available to investors from investments of
19 corresponding' risk, as directed by landmark Supreme Court
20 decisions. Ms. Carlock also recognized that the
21 opportunity to earn a return at least equal to those
22 expected in the capital markets for comparable
23 investments is required if a utility is to be able to
24 attract capital. Ms. Carlock also noted the importance
25 of testing any cost of equity estimate against applicablestandards:
1933 AVERA, DI REB 4
Idaho Power Company
.1
2
. . . three standards have evolved for
determining a fair and reasonable rate of
return: (1) the Financial Integrity or Credit
Maintenance Standard; (2) the Capital
Attraction Standard; and (3) the Comparable
Earnings Standard. i
3
4
5 This is absolutely correct. If Idaho Power's
6 return on equity does not fully reflect the level of
7 investment risks that investors perceive, it will violate
8 the risk-return tradeoff, breach applicable standards,
9 and impair the Company's ability to attract necessary
10 capital.
11 Q.What benchmarks are useful in evaluating the
12 extent to which the ROE recommendations meet this.13
14
fundamental regulatory requirement?
A. The comparable earnings standard recognizes
15 that Idaho Power must compete for capital with all firms
16 in the capital markets generally, and against firms in
17 its own industry specifically. The Value Line Investment
18 Survey ("Value Line") reports that electric utilities as
19 a whole are anticipated to earn a return of 11.5 percent
20 in 2008, 2009, and over its 2011-2013 forecast horizon.2
21 A return that is significantly below the level that Value
22 Line expects for electric utili ties generally would
23 undermine confidence in the financial integrity of the
24 firm and its ability to attract capital..25 /
1934 AVERA, DI REB 5
Idaho Power Company
.
.
.
15
16
17
18
19
20
21
22
23
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
24 i Carlock Direct at 5.
25 2 The Value Line Investment Survey at 2230 (Nov. 7, 2008).
1935 AVERA, DI REB 5a
Idaho Power Company
.
.
15
1 Q.What are the potential consequences of
2 authorizing a rate of return less than what is required
3 to meet the financial end-result test?
4 A.Considering the risks faced by Idaho Power, the
5 need to fund substantial investment in utility
6 infrastructure, and the imperative of maintaining access
7 to capital during times of adversity, setting an ROE that
8 fails to provide investors with an opportunity to earn
9 returns commensurate with companies of comparable risk
10 would weaken Idaho Power's financial integrity, violate
11 the capital attraction standard, and send the wrong
12 signal to investors at a time when access to capital
13 markets is crucial for the Company.
14 III . CHAGES IN CAITAL MAT CONDITIONS
Q.What are the implications of recent capital
16 market conditions?
17 A.Recent volatility in the debt and equity
18 markets linked to the ongoing financial crisis and the
19 weakening economy evidences investors' trepidation to
20 commit capital and marks a significant upward revision in
21 their perceptions of risk and required returns.
22 Bloomberg rep?rted that the CBOE Volatility Index,
23 commonly know as the VIX, recently surged 26 percent to
24 almost triple its average during the past year,.25 indicating unprecedented price
1936 AVERA, DI REB 6
Idaho Power Company
.
.
.
1 fluctuations and uncertainty. 3 With respect to utili ties
2 specifically, as of November 14, 2008, the Dow Jones
3 Utility Average stock index has declined over 28 percent
4 since June 2008, while yields on utility bonds have
5 increased precipitously. Figure 1 below plots the yields
6 on triple-B utility bonds reported by Moody's Investors
7 Service ("Moody's") from June 2008 through November 20,
8 2008 :
9
__ _- FIGUR 1
MOODY'S TRIPLE-B PUBLIC UTILITY BOND YIELDS
10 9.5%
9.0%
8.5%
8.0% -
7.5% -
7.0%
6.5%
6.0% -
~Q; 'd~ ~~ ~Q; 'fQ;",\V ~.. 'd'?~ tY''- ,,'(
11
12
13
14
. ~Q; ~~ ~~Q; ~~Q;
Q;n,'O O¡~ O¡'" ..~~~%
~~,"
~~Q;
,'10,
~
:V~~'15
16 At the time my direct testimony was prepared, the average
17 yield on triple-B rated utility bonds was 6.9 percent, or
18 approximately 6.8 percent in May 2004, when the IPUC
19 issued its decision in Case No. IPC-E-03-13. Meanwhile,
20 Moody's reported that for the month of October 2008, the
21 average yield on triple-B utility bonds had climbed to
22 8.6 percent, with the month-average yield as of November
23 20, 2008 being approximately 9.0 percent.
24
25
3 Kearns, Jeff, "VIX 'Exploding' as Stocks Plunge on Growing
Recession Concern," Bloomberg (Oct. 15, 2008).
1937 AVERA, DI REB 7
Idaho Power Company
.
.
.
16
17
18
1 Q.What does this evidence indicate with respect
2 to establishing a fair ROE for Idaho Power?
3 A.The recent sell-off in common stocks and sharp
4 increase in utility bond yields are indicative of higher
5 costs for long-term capital, and the ongoing credit
6 crisis has spilled over into the utility industry. For
7 example, utilities have been forced to draw on short-term
8 credit lines to meet debt retirement obligations because
9 of uncertainties regarding the availability of long-term
10 capital.4 As the Edison Electric Insti tute ("EEI") noted
11 in a recent letter to congressional representatives, the
12 financial crisis has serious implications for utilities
13 and their customers:
14 In the wake of the continuing upheaval on Wall
Street, capital markets are all butimmobilized, and short-term borrowing costs to
utili ties have already increased substantially.
If the financial crisis is not resolvedquickly, financial pressures on utili ties will
intensify sharply, resulting in higher costs to
our customers and, ultimately, could compromise
seryice reliability. 5
15
19 Similarly, an October 1, 2008, Wall Street
20 Journal report confirmed that dislocations in credit
21 markets were also impacting the utility sector:
22
23
4 Riddell, Kelly, "Cash-Starved Companies Scrap Dividends, Tap
24 Credit," Pittsburgh Post-Gazette (Oct. 2, 2008).
25 5 Letter to House of Representatives, Thomas R. Kuhn, President,
Edison Electric Institute (Sep. 24, 2008).
1938 AVERA, DI REB 8
Idaho Power Company
.
.
16
17
1
2
Disruptions in credit markets are j ol ting the
capi tal-hungry utility sector, forcing
companies to delay new borrowing or come up
wi th different-often more costly-ways of
raising cash. 63
4 An October 2008 report on the implications of
5 credit market upheaval for utili ties noted that, while
6 high-quality companies can still issue debt, "they now
7 have to pay an unusually high risk premium over
8 Treasuries. "7 Meanwhile, a Managing Director with Fitch
9 Ratings, Ltd. ("Fitch") recently observed that with debt
10 costs at present levels, "significantly higher regulated
11 returns will be required to attract equity capital. "8
12 As Fitch concluded:
13 The collapse in secondary market debt pricing
and in equity valuations is worrisome. We see
new debt now priced at around 9% or higher
pushing up against average authorized ROEs for
utilities of around 10.25% to 10.50%. Thus,
raising new equity, which is now priced closeto book value, is likely to be diluti ve. 9
14
15
Q.Do the recommendations of Ms. Carlock and Mr.
18 Kahal reflect these economic realities?
19 A.No. While Ms. Carlock and Mr. Kahal both touch
20 on conditions. in the capital markets, they either seek to
21 diminish the importance of the recent financial crisis or
22 /
23 /
24 /.25 /
1939 AVERA, DI REB 9
Idaho Power Company
.
.
.
13
14
15
16
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
6 Wall Street Journal "Turmoil in Credit Markets Send Jolt to Utility
Sector" (Oct. 1, 2008), p. B4.
7 Rudden's Energy Strategy Report (Oct. 1, 2008).
8 Fitch Ratings Ltd., "EEl 2008 Wrap-Up: Cost of Capital Rising,"
1 7 Global Power North America Special Report (Nov. 17, 2008).
18 9 Fitch Ratings 'Ltd "Investing In An Unpredictable World," Fitch
Ratings' 20th Annual Global Power Breakfast (Nov. 10, 2008).
19
20
21
22
23
24
25
1940 AVERA, DI REB 9a
Idaho Power Company
.
.
1 mischaracterize the implications of the resulting
2 economic threats. For example, Ms. Carlock noted (p. 10)
3 that current market trends "are making capitalization
4 difficult for all," but her assessment of short-term
5 interest rate trends leaves the false impression that
6 capi tal costs have somehow decreased.
7 For his part, Mr. Kahal grants (p. 9) that
8 "financial markets distress and equity market volatility
9 has increased drastically, with credit markets beginning
10 in last September freezing up," but nevertheless
11 concludes that the implications are "difficult to
12 predict. " Rather than account for the economic realities
13 facing today' s investors, he simply asserts that "cost of
14 capi tal data in this case have not changed
15 substantially, "10 and that the present crisis "likely
16 will be temporary". 11 As a result, he recommends
17 ignoring it altogether.
18 Q.Do the interest rate benchmarks cited by Ms.
19 Carlock and Mr. Kahal accurately reflect the current
20 expectations and requirements of Idaho Power's equity
21 investors?
22 A.No. In evaluating trends in interest rates,
23 Ms. Carlock concluded in her testimony that interest
24 rates have decreased, based solely on her observation.25 that the
1941 AVERA, DI REB 10
Idaho Power Company
1.2
3 /
4
5 /
6
7 /
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24 10 Kahal Direct at 6..25 11 Kahal Direct 'at 10.
1942 AVERA,DI REB lOa
Idaho Power Company
.
.
.
1 prime rate and the federal funds rate have declined. 12
2 Of course, the decline in the federal funds rate and
3 prime lending rate are a function of the Federal
4 Reserve's actions to increase liquidity in the face of a
5 profound crisis in credit markets. Moreover these
6 interest rate benchmarks have virtually no relevance in
7 an evaluation of long-term capital costs for a utility
8 such as Idaho Power.
9 While Mr. Kahal grants that trends in long-term
10 interest rates are indicative of the cost of equity, 13 he
11 concludes that "favorable trends" in long-term debt cost
12 rates support his recommendation. 14 As documented above,
13 however, Mr. Kahal' s conclusion is directly at odds with
14 the capital market realities faced by investors. Yields
15 on triple-B utility bonds are on the order of at least
16 200 basis points higher than those prevailing at the time
17 the IPUC issued its decision in Idaho Power's last
18 litigated rate proceeding. In contrast to the
19 recommendations of Ms. Carlock and Mr. Kahal, this
20 implies a significant increase the ROE for Idaho Power.
21
22
12 In response to IPC Request No. 22, which asked if Ms. Carlock had
evaluated trends in public utility bond yields from the time of Idaho
Power's last rate case until the present, she indicated that "Public
Utility bond yields floated within a closer range (versus prime
rate), decreasing at times and increasing at others. With the market
uncertainty this fall, they increased."
13 Kahal Direct at 9.
14 Kahal Direct at 10.
23
24
25
1943 AVERA, DI REB 11
Idaho Power Company
1 Q.What increase in ROE is indicated by the upward.2 trend in long-term utility bond yields?
3 A.While the cost of equity generally moves in the
4 same direction as interest rates , it is widely accepted
5 that the cost of equity does not increase or decrease in
6 lockstep with. changes in bond yields. Indeed, there is
7 substantial evidence that equity risk premiums tend to
8 move inversely with interest rates. In other words, when
9 interest rate levels are relatively high, equity risk
10 premiums narrow, and when interest rates are relatively
11 low, equity risk premiums widen. This inverse
12 relationship has been recognized in the financial.13 li terature and by regulators. Based on a review of the
14 financial literature, Regula tory Finance: Utili ties Cost
15 of Capi tal concluded that: "These studies imply that the
16 cost of equity changes only half as much as interest
17 rates change. "15
18 Considering this inverse relationship and the
19 fact that triple-B utility bond yields have increased at
20 least 200 basis points since the IPUC issued its decision
21 in Case No. IPC-E-03-13 implies a minimum upward
22 adjustment to the approved ROE of 100 basis points.
23 Q.Does it make sense to ignore current capital
24 market conditions, as Mr. Kahal recommends?.25 /
1944 AVERA, DI REB 12
Idaho Power Company
.
.
.
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16
17
18
19
20
21
22
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2
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4
5 /
6
7 /
8
9
10
11
12
13
14
23 15 Morin, Roger~., "Regulatory Finance: Utilities' Cost of Capital,"
Public Utilities Reports, Inc. (1994) at 292.
24
25
1945 AVERA, DI REB 12a
Idaho Power Company
.
.
1 A.Absolutely not. Mr. Kahal may have gazed into
2 his crystal ball and determined that the demonstrable
3 increase in long-term capital costs "will be temporary,"
4 but his personal opinions have no bearing on the
5 reali ties that Idaho Power faces in raising capital. In
6 fact, most of the investment community are far less
7 sanguine than Mr. Kahal and there is very little
8 indication that the dire conditions confronting the
9 economy and financial markets will be resolved quickly.
10 In contrast to Mr. Kahal' s rosy outlook, in a review of
11 the impact of. the financial crisis for utilities, a
12 Managing Director for Fitch recently concluded, "I do not
13 believe that borrowing costs will come down from current
14 levels. "16 Even Mr. Kahal was forced to grant that "it
15 is difficult to predict when normal conditions will
16 return to financial markets. "17
1 7 As noted earlier, the standards underlying a
18 fair rate of return require that Idaho Power's authorized
19 ROE reflect a return competitive with other investments
20 of comparable risk and preserve the Company's ability to
21 maintain access to capital on reasonable terms. This
22 standard can only be met by considering the requirements
23 of investors in today' scapi tal markets. Past trends in
.24
25
16 Grabelsky, Glen, "Surviving the Present, Preparing fo the Future,"
Fi tch Ratings' 20th Annual Global Power Breakfast (Nov. 10, 2008).
17 Kahal Direct at 9.
1946 AVERA, DI REB 13
Idaho Power Company
.
.
.
1 interest rates or Mr. Kahal' s vague sense that conditions
2 may soon return to "normal" are irrelevant.
3 Similarly, contrary to Mr. Kahal' s contention, 18
4 the fact that the current crisis may complicate the
5 application of the DCF model or CAPM to estimate the cost
6 of equity provides no basis to ignore the dramatic upward
7 shift in investors' risk perceptions and required rates
8 of return for long-term capital. Moreover, the fact that
9 yields on long-term utility bonds have increased over 200
10 basis points since the IPUC' s decision in Case No.
11 IPC-E-03-13 is directly observable in the capital
12 markets. This evidence alone - which does not depend on
13 the DCF or CAPM approaches - demonstrates that Idaho
14 Power's ROE must be increased substantially if the
15 Supreme Court's standards underlying a fair rate of
16 return are to be met in today' s economic environment.
17 Q.What other evidence supports a finding that
18 Idaho Power's cost of equity capital has increased?
19 A.Apart from the dramatic upward shift in
20 investors' required rates of return generally, the
21 investment risks specific to Idaho Power have also
22 increased. Ms. Carlock's recommended ROE of 10.25
23 percent is equal to that authorized by the IPUC in Case
24
25 18 Kahal Direct at 10.
1947 AVERA, DI REB 14
Idaho Power Company
.1 No. IPC-E-03-13, which Mr. Kahal cites as a benchmark.
2 What both these witnesses fail to address is the fact
3 that Idaho Power's bond ratings have declined since that
4 time, indicating higher risks and a higher required rate
5 of return on equity.
6 Based in large part on concerns stemming from
7 the outcome of Idaho Power's past rate proceedings and
8 the pressures of ongoing capital requirements, Standard &
9 Poor's Corporation ("S&P") lowered the Company's
10 corporate credit rating from "A-" to "BBB+" in November
11 2004,19 and again from "BBB+" to "BBB" in January 2008.20
12 Q.Is there any direct capital market evidence.13 regarding the amount of the premium investors require
14 from a firm that is rated triple-B, versus one with Idaho
15 Power's former single-A rating?
16 A.Al though rates of return on equity cannot be
17 directly observed, the observed yields on long-term bonds
18 provide direct evidence of the additional return that
19 investors require to bear the risks associated with
20 weaker credit ratings. Moody's recently reported an
21 average yield on single-A rated public utility bonds for
22 October 2008 of 7.56 percent, versus an average yield of
23 8.58 percent for
24 /.25 /
1948 AVERA, DI REB 15
Idaho Power Company
.
.
17
18
19
20
21
1
2
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4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
22 19 Standard & Poor's Corporation, "IDACORP and Unit Ratings Lowered,
Removed From Cr~ditWatch Negative, RatingsDirect (Nov. 29, 2004).
23
20 Standard & Poor's Corporation, "IDACORP, Idaho Power Co. Ratings
2 4 Lowered One Notch to 'BBB'; Outlook Stable," Ra tingsDirect (Jan. 3 i,
2008) ..25
1949 AVERA, DI REB 15a
Idaho Power Company
.
.
.
1 bonds rated triple-B. Based on this evidence, the debt
2 markets would now require approximately 100 basis points
3 in additional return in order to compensate for the
4 greater risks associated with Idaho Power's current
5 triple-B rating. Equity investors would undoubtedly
6 require a significantly greater premium for bearing the
7 higher risk associated with the more junior common stock
8 of a utility with a triple-B rated company, versus one
9 that is rated single-A.
10 Coupled with the significant increase in
11 long-term capital costs discussed earlier, the higher
12 risks that investors associate with Idaho Power provide
13 further evidence that the ROE recommendations of Ms.
14 Carlock and Mr. Kahal are inadequate. Since the 19308,
15 there has not. been a time when the domestic and global
16 financial markets have experienced as much turmoil and
17 uncertainty as they are now undergoing. For a utility
18 with an obligation to provide reliable service,
19 investors' increased reticence to supply additional
20 capital during times of crisis highlights the necessity
21 of preserving the flexibility necessary to overcome
22 periods of adverse capital market conditions. The
23 investment risks faced by utilities and their investors
24 have only been exacerbated in this uncertain environment.
25 In turn, the need for supportive regulation and an
adequate ROE may never have been greater.
1950 AVERA, DI REB 16
Idaho Power Company
.
.
1 Q.What are the implications of disregarding
2 the Company's higher investment risks in setting the
3 allowed rate of return on equity?
4 A.If the greater risks associated with Idaho
5 Power's weakened credit standing are not incorporated in
6 the allowed rate of return on equity, the results will
7 fail to meet the comparable earnings standard that Ms.
8 Carlock agrees is fundamental in determining the cost of
9 capi tal. From a more practical perspective, failing to
10 provide investors with the opportunity to earn a rate of
11 return commensurate with Idaho Power's risks will only
12 serve to further weaken its financial integrity, while
13 hampering the Company's ability to attract the capital
14 needed to meet the economic and reliability needs of its
15 service area.
16 Q.Does the importance of an adequate return to
17 attract investors' capital diminish if the utility is not
18 planning to issue new equity?
19 A.Not at all. First, it is not always wi thin the
20 utility's control when it will have to access equity
21 markets. Due to its obligation to serve, a utility may
22 have to invest new capital even during adverse market
23 conditions and its ability to withstand such periods of
24 stress depends to a large degree on investors' confidence.25 in supportive regulation, including an adequate ROE.
1951 AVERA, DI REB 17
Idaho Power Company
.
.
.
1 In the current crisis there has been much
2 discussion of the problems created for homeowners who
3 were induced into buying too much house by "teaser"
4 interest rates that were very low at the outset, but then
5 reset to higher rates after the first few years of the
6 mortgage. Many problems could have been avoided if, at
7 the outset, homeowners and lenders had looked beyond the
8 low initial payments and focused on the long-term costs
9 and implications of their mortgage terms. The long-term
10 perspecti ve is similarly important for regulators. The
11 cost to customers in the long-term may be much higher if
12 the allowed return in the near term limits the financial
13 resiliency of the utility and renders it unable to raise
14 capi talon reasonable terms to fund crucial
15 infrastructure investments, especially in times of
16 financial stress.
17 If regulators opportunistically approve
18 inadequate returns when the utility seems to be
19 financially sound, then investor confidence is lost. As
20 the western energy crisis of 2000-2001 demonstrated, it
21 cannot be easily or quickly regained by simply granting
22 higher returns in later years. It would be both unfair
23 to Idaho Power and against the long-term interest of
24 customers to adopt a downward-biased ROE, such as those
25 proposed by Ms. Carlock and Mr. Kahal.
1952 AVERA, DI REB 18
Idaho Power Company
.
.
1 iv. TERRI CAOCK
2 Q.How did Ms. Carlock arrive at her 10.25 percent
3 cost of equity recommendation for Idaho Power?
4 A.Ms. Carlock estimated the cost of equity by
5 applying the constant growth DCF model to Idaho Power's
6 parent, IDACORP, Inc. ("IDACORP") .21 She concluded that
7 the results of this DCF application indicated a cost of
8 equi ty in the 8.9 percent to 9.8 percent range. Ms.
9 Carlock also conducted a comparable earnings analysis,
10 which resulted in an indicated cost of equity in the 9.5
11 percent to 10~ 5 percent range. Based on these two
12 analyses, Ms. Carlock concluded that the cost of equity
13 was in the 9.5 to 10.5 percent range, selecting 10.25
14 percent as her point estimate ROE recommendation for
15 Idaho Power.
16 Q.Do you believe it is reasonable to rely on the
17 DCF results for a single company in evaluating a fair ROE
18 for Idaho Power?
19 A.No. Even for a firm with publicly traded
20 stock, such as IDACORP, the cost of equity is inherently
21 unobservable and can only be inferred indirectly by
22 reference to available capital market data. As a result,
23 applying quantitative models using observable market data
24 only produces' an estimate that inherently includes some.25 /
1953 AVERA, DI REB 19
Idaho Power Company
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17
18
19
20
21
22
23
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25
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2
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5 /
6
7 /
8
9
10
11
12
13
14
15
21 In response to IPC Request No. 27, Ms. Carlock noted that, in
addi tion to her independent DCF analysis for IDACORP, she also
reviewed my DCF results.
1954 AVERA, DI REB 19a
Idaho Power Company
.1 degree of observation error. Because any form of
2 analysis that depends on estimates is subject to
3 measurement error, the accepted approach to increase
4 confidence in the results is to apply the DCF model and
5 other quanti tati ve methods to a proxy group of publicly
6 traded companies that investors regard as risk
7 comparable. The results of the analysis on the sample of
8 companies are relied upon to establish a range of
9 reasonableness for the cost of equity for the specific
10 company at issue.
11 To the extent that the data used to apply the
12 DCF model does not capture the expectations that.13 investors have incorporated into current stock prices,
14 the resulting cost of equity estimate will be biased and
15 unreliable. Conceptually, the issue of proxy group size
16 is directly analogous to the use of sampling in
17 statistical analyses. In statistics, a "true" value is
18 often estimated by reference to sample observations, with
19 the analyst having greater confidence in the
20 applicability of the estimated results as the size of the
21 sample increases. As Mr. Kahal noted, "I believe that an
22 appropriately selected proxy group (preferably one
23 reasonable in size) is likely to be more reliable than a
24 single company study. "22 By relying on a single DCF.25 value for IDACORP, Ms. Carlock unnecessarily
1955 AVERA, DI REB 20
Idaho Power Company
.
.
1 compromises the ability of the DCF analysis to reflect
2 investors' actual expectations and requirements.
3 Q.Is there evidence of bias in Ms. Carlock's DCF
4 analysis for IDACORP?
5 A.Yes. Despite the fact that common equity is
6 considerably more risky than an investment in long-term
7 debt, the low end of Ms. Carlock's DCF range falls below
8 current yields on triple-B rated utility bonds.
9 Similarly, with triple-B utility bond yields averaging
10 above 9 percent so far in November 2008, the top end of
11 her DCF range implies an equity risk premium of less than
12 80 basis points. In light of the risks that investors
13 presently associate with long-term capital generally and
14 utilities specifically, an equity risk premium of 80
15 basis points is far below what is necessary to ensure
16 Idaho Power' s ability to attract capital. 23
17 In addition, while Ms. Carlock contended that
18 her DCF conclusions were based in part on a review of my
19 analyses, as noted in my direct testimony, all but one
20 of the average DCF estimates resulting for my proxy group
21 exceeded 11 percent.
22
23
24.25
22 Kahal Direct at 18.
23 At the time the IPUC authorized a 10.25 percent ROE for Idaho
Power in Case No. IPC-3-03-13, the six-month average single-A utility
bond yield was approximately 6.25 percent. This implies a risk
premium of 400 basis points.24 Response to IPC Request No. 27.
1956 AVERA, DI REB 21
Idaho Power Company
.
.
.
1 Q.Did you have the opportunity to review the
2 details of the comparable earnings analysis that underlie
3 Ms. Carlock's conclusions?
4 A.No. Ms. Carlock's testimony contains no
5 schedules or exhibits presenting the results of her
6 comparable earnings analyses. In response to Idaho Power
7 Company's production Request No. 25, Ms. Carlock asserted
8 that the "returns are for utility companies shown in
9 Company witness Avera exhibits and workpapers."
10 Q.Does Ms. Carlock's comparable earnings range
11 correspond to the returns investors are anticipating for
12 the companies in your proxy group?
13 A. No. As indicated on my Exhibit No. 25,
14 expected earned rates of return for the firms in my proxy
15 group result in an average implied return on equity of
16 11.1 percent, which is considerably higher than the 9.5
17 percent to 10.5 percent range cited in her testimony. In
18 addi tion, as noted earlier, Value Line expects that
19 electric utili ties as a whole are anticipated to earn a
20 return of 11.5 percent. A return that is significantly
21 below the level that Value Line expects for electric
22 utili ties generally would undermine confidence in Idaho
23 Power's financial integrity and its ability to attract
24 capital.
25 Q. Do historical allowed rates of return support
Ms. Carlock's ROE recommendations?
1957 AVERA, DI REB 22
Idaho Power Company
.
.
.
1 A. No. While I have no basis to dispute Ms.
2 Carlock's observation that authorized ROEs during 2007
3 and the first quarter of 2008 may have ranged from 9.8
4 percent to 11.25 percent, these historical figures
5 completely ignore the significant changes in capital
6 market conditions since the record in these various
7 proceedings was established. As indicated earlier, the
8 increase in utility bond yields translates to an upward
9 adjustment in the cost of equity on the order of 100
10 basis points. As a result, adjusting the stale,
11 historical figures underlying Ms. Carlock's analysis of
12 authorized returns would suggest a current range on the
13 order of 10.5 percent to 11.5 percent. As noted earlier,
14 this is consistent with the investment community's view
15 that "significantly higher regulated returns will be
.
16 required to attract equity capital." 25
17 Q.Did Ms. Carlock apply the CAPM to estimate the
18 cost of equity for Idaho Power?
19 A.No. While Ms. Carlock stated that "much of the
20 theoretical approach" that she used was consistent with
21 my testimony, Ms. Carlock did not use the CAPM to
22 estimate the cost of equity. As I explained in my direct
23 testimony, the CAPM method is widely recognized as a
24 meaningful approach to estimate investors' required rate
25 of return.
1958 AVERA, DI REB 23
Idaho Power Company
.
.
.
1 Unlike the comparable earnings method, which depends on
2 earned returns derived from accounting information, the
3 CAPM approach is based on capital market data indicative
4 of investors' current expectations. The IPUC has noted
5 the importance of "evaluating all the methods" and "using
6 each as a check on the other when setting the allowed
7 rate of return. "26
8 Q.Why is the use of multiple methods so important
9 when estimating the cost of equity?
10 A.Investors' expectations are unobservable, and
11 there is no methodology that provides a foolproof guide
12 to their required rate of return. Each method provides
13 another facet of examining investor behavior, with
14 different assumptions and premises. Investors do not
15 necessarily subscribe to anyone method, and no model can
16 conclusively determine or estimate the required return
17 for an individual firm. If the cost of equity estimation
18 is restricted' to certain methodologies, while the results
19 of other approaches are ignored, it may significantly
20 bias the outcome. Rather, all relevant evidence should
21 be weighed and evaluated in order to minimize the
22 potential for- error.
23
25 Fitch Ratings Ltd., "EEl 2008 Wrap-Up: Cost of Capital Rising,"
24 Global Power North America Special Report (Nov. 17, 2008).
25 26 Idaho Public Utilities Commission, Order No. 29505 (May 25, 2004)
at 38.
1959 AVERA, DI REB 24
Idaho Power Company
.
.
.
1 Regulators have customarily considered the
2 resul ts of al ternati ve approaches in determining allowed
3 returns. 27 It is widely recognized that no single method
4 can be regarded as a panacea; all approaches have
5 advantages and shortcomings. For example, a publication
6 of the Society of Utility and Financial Analysts
7 (formerly the National Society of Rate of Return
8 Analysts), concluded that:
9 Each model requires the exercise of judgment as
to the reasonableness of the underlying
assumptions of the methodology and on the
reasonableness of the proxies used to validate
the theory. Each model has its own way of
examining investor behavior, its own premises,
and its own set of simplifications of reality.
Each method proceeds from different fundamental
premises, most of which cannot be validated
empirically. Investors clearly do not
subscribe to any singular method, nor does the
stock price reflect the application of anyone
single method by investors. 28
10
11
12
13
14
15
16 Q.Has the IPUC expressed reluctance to consider the
17 resul ts of the CAPM approach?
18 A.Yes. I am aware that in the past the IPUC has
19 expressed concerns over the measurement and proper use of
20 the beta value necessary to apply the CAPM and has not
21
27 For example, a NARUC survey reported that 26 regulatory
22 jurisdictions ascribe to no specific method for setting allowed ROEs,
with the results of all approaches being considered. "Utility
23 Regulatory Policy in the U.S. and Canada, 1995-1996," National
Association of Regulatory Utility Commissioners (December 1996).
24
25
28 Parcell, David C., "The Cost of Capital - A Practitioner's Guide,"
Society of Utili ty and Regulatory Financial Analysts (1997) at Part
2, Page 4.
1960 AVERA, DI REB 25
Idaho Power Company
.
.
.
1 routinely focused on the results of this method.29
2 Nevertheless, the CAPM is a rigorous conceptual framework
3 at the heart of modern financial theory and it is widely
4 used and referenced in the investment community. Indeed,
5 evidence suggests that reliance on the DCF model as a
6 tool for estimating investors' required rate of return
7 has declined outside the regulatory sphere, with the CAPM
8 being "the dominant model for estimating the cost of
9 equity. "30 Of course, the CAPM is based on restrictive
10 assumptions and does not describe security returns
11 perfectly and there are controversies surrounding the
12 measurement of key variables, such as beta. But then
13 exactly the same could be said for the constant growth
14 DCF model, which assumes a single, static growth rate
15 into perpetuity that has no observable proxy in the
16 capi tal markets. Moreover, I have used Value Line as the
17 source of my betas, a reference cited by Ms. Carlock in
18 her data responses.
19 Q.What cost of equity is implied if the CAPM
20 method is used to check Ms. Carlock's conclusions?
21 A.As discussed in detail in my direct testimony
22 and show on Table 4, the results of the CAPM approach
23 implied cost of equity estimates ranging from 10.2
24 percent
25
1961 AVERA, DI REB 26
Idaho Power Company
.
.
.
16
17
18
19
20
21
22
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
23 29 See e.g., Order No. 29505 at 38.
24
25
30 See, e.g., Bruner, R.F., Eades, K.M., Harris, R.S., and Higgins,
R. C., "Best Practices in Estimating Cost of Capital: Survey and
Synthesis," Financial Practice and Education (1998).
1962 AVERA, DI REB 26a
Idaho Power Company
.
.
20
1 to 11.9 percent, with the average of the individual
2 values being 11.0 percent. This result is consistent
3 wi th my finding that present capital market conditions
4 imply an ROE significantly above the 10.25 percent
5 approved in Idaho Power's last litigated rate case.
6 Q.Did Ms. Carlock recognize that the investment
7 risks associated with electric utilities have increased?
8 A.Yes. Ms. Carlock noted that a plethora of
9 changes have impacted investors risk perceptions,
10 observing that:
11 The competi ti ve risks for electric utili ties
have changed with increasing non-utility
generation, deregulation in some states, open
transmission access, and changes in electricity
markets.31
12
13
14 Ms. Carlock concluded that, because of these greater
15 uncertainties, the difference in the risk between
16 industrial firms operating in the competitive market and
17 electric utilities "is not as great as it used to be. "32
18 Q.Did Ms. Carlock consider this increase in risk
19 in her analysis of the cost of equity for Idaho Power?
A.No. Ms. Carlock ignored the implications of
21 this trend in investment risks for utilities, asserting
22 instead that Idaho Power's "competitive risks" are lower
23 because of its "low-cost source of power" and "low retail
24.25
31 Carlock Direct at 8.
32 Id.
1963 AVERA, DI REB 27
Idaho Power Company
.
.
.
1 rates. "33 Ms. Carlock also asserted that the Power Cost
2 Adj ustment (" PCA" ) and Fixed Cost Adj ustment (" FCA" )
3 reduce Idaho Power's risks relative to other electric
4 utili ties. 34
5 Q.Does this represent an accurate assessment of
6 the investment risks investors' associate with Idaho
7 Power?
8 A.No. While I agree with Ms. Car lock that
9 relatively low rates provide benefits to customers, this
10 narrow view ignores the substantial uncertainties that
11 Idaho Power's investors assume to realize these benefits.
12 As explained in detail in my direct testimony, because a
13 high proportion of the Company's energy needs is provided
14 by hydroelectric facilities, Idaho Power is exposed to a
15 level of uncertainty not faced by other utili ties, which
16 are less dependent on hydro generation.
17 Reduced hydroelectric generation due to
18 below-average water conditions forces Idaho Power to rely
19 on less efficient thermal generating capacity and
20 purchased power to meet its resource needs. As the IPUC
21 has noted, "there are no guarantees about future stream
22 flows or market prices, "35 and in light of the recent
23 past, this dependence on wholesale markets entails
24 significant risk in the minds of investors, especially
25 for a utility located in the West.
1964 AVERA, DI REB 28
Idaho Power Company
.
.
15
16
17
18
19
20
21
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
22 33 Id. at 9.
23 34 Id.
24 35 Idaho Power Granted $256 million deferral, but bond plan denied,
Idaho Public Utilities Commission (May 13, 2002)..25
1965 AVERA, DI REB 28a
Idaho Power Company
.
.
.
1 Investors recognize that volatile markets, unpredictable
2 stream flows, and Idaho Power's dependence on wholesale
3 purchases to meet the needs of its customers expose the
4 Company to the risk of reduced cash flows, increased need
5 for financing, and unrecovered power supply costs.
6 Apart from exposure to market uncertainties,
7 Idaho Power also confronts the complexities associated
8 wi th maintaining the necessary licenses to operate its
9 hydroelectric stations. The process of relicensing is
10 prolonged and involved and often includes the
11 implementation of various studies and measures to address
12 environmental and stakeholder concerns. 36 These measures
13 can impose significant additional costs and/or lead to
14 reduced generating capacity and flexibility.
15 Q.Does the fact that Idaho Power has a PCA
16 absolve investors from risk of volatility, as Ms. Carlock
17 seems to imply?
18 A.No. The fact that Idaho Power had been granted
19 a PCA does not translate into lower risk vis-à-vis other
20 electric utilities. First, adjustment mechanisms to
21 account for changes in power supply costs are the rule,
22 rather than the exception in the utility industry, so
23
24
36 The current license for the Hells Canyon Complex, which accounts
for 68 percent of Idaho Power's hydroelectric generating capacity,
expired in July 2005. Apart from significant ongoing expenditures
associated with proposed environmental measures, the relicensing
process is complex, protracted, and expensive.
25
1966 AVERA, DI REB 29
Idaho Power Company
.
.
.
1 that the Company's PCA merely moves its risks closer to
2 those of other utili ties. Second, the PCA does not
3 prevent the lag between the time that Idaho Power
4 actually incurs power supply expenses and when those
5 expenses are recovered from ratepayers. As S&P noted:
6 The Company's PCA does not currently fully
insulate it under very poor or persistently low
7 hydro conditions. In exceptionally low water
years, deferrals materially weaken cash flows8 and credit metrics. 37
9 Investors are well aware that the significant reduction
10 in cash flows associated with mounting deferrals can have
11 a debilitating impact on a utility's financial position.
12 Moreover, investors are aware that the PCA does not apply
13 to 100 percent of the difference between the actual cost
14 of purchased power and the amount collected through
15 rates, with Idaho Power's shareholders remaining at risk
16 for a portion of any discrepancy. 38 As documented in my
17 direct testimony, investors recognize that uncertainties
18 over water conditions are a persistent operational risk
19 associated with Idaho Power.
20
37 Standard & Poor's Corporation, "Sumary: Idaho Power Co.,"
21 RatingsDirect (Aug. 29, 2008).
22 38 While the stipulation filed in October 2008 would improve Idaho
Power's PCA mechanism by allowing the Company to collect 95 percent
of under-collected power costs and providing a better match between
actual expenses and revenues, S&P concluded that, while positive,
these revisions would not result in an improvement to Idaho Power's
credit ratings. Standard & Poor's Corporation, "Bulletin: Proposed
PCA Changes Should Help Idaho Power Co. Recoup Costs, No Rating
Change," RatingsDirect (Oct. 16, 2008).
23
24
25
1967 AVERA, DI REB 30
Idaho Power Company
.
.
.
1 Q.Is there any merit to Ms. Carlock's position
2 that the FCA implies lower risks for Idaho Power than for
3 other electric utili ties?
4 A.No. As explained in my direct testimony, while
5 adj ustment mechanisms such as the FCA help to preserve
6 Idaho Power's opportunity to earn its authorized return
7 by allowing the Company to recover reasonable and
8 necessary expenditures, they also address the investment
9 community's heightened concerns over the risks associated
10 with rising costs. Of particular concern to investors is
11 the impact of. regulatory lag and cost-recovery on the
12 utility's ability to earn its authorized ROE. For
13 example, Moody's has emphasized the need for regulatory
14 support "in an era of broadly rising costs," noting that
15 as cost presspres have escalated for electric utilities,
16 so too has the importance of timely recovery through the
17 regulatory process and the risks associated with
18 regulatory lag. 39
19 While the FCA attenuates Idaho Power's exposure
20 to attrition in an era of rising costs, this leveling of
21 the playing field will only serve to preserve the
22 Company's opportunity to earn its authorized return, as
23 required by established regulatory standards. Indeed,
24 S&P recently
25
1968 AVERA, DI REB 31
Idaho Power Company
.
.
.
16
17
18
19
20
21
22
23
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
24 39 Moody's Investors Service, "Regulatory Pressures Increase For U.S.
Electric Utilities," Special Comment (March 2007) .
25
1969 AVERA, Dr REB 31a
Idaho Power Company
.1 observed that its risk analysis focuses on the utility's
2 abili ty to consistently earn a reasonable return:
3 Notably, the analysis does not revolve around
"authorized" returns, but rather on actual4 earned returns. We note the many examples of
utili ties with heal thy authorized returns that,
5 we believe, have no meaningful expectation of
actually earning that return because of rate
6 case lag, expense disallowances, etc. 40
7 Since before the IPUC' s 2004 decision authorizing Idaho
8 Power an ROE of 10.25 percent, the Company's actual
9 earned returns have fallen in the single digits, with
10 Value Line projecting an earned return on equity for
11 IDACORP of 7.5 percent in 2008.41
12 Moreover, utili ties increasingly benefit from a.13 wide variety of mechanisms designed to mitigate against
14 the risks associated with fluctuations in costs and
15 regulatory lag. While these mechanisms are not always
16 directly analogous to the specific provisions of Idaho
17 Power's FCA, the obj ecti ve is similar; namely, to allow
18 the utility an opportunity to earn a fair rate of return
19 and partially. attenuate exposure to attrition in an era
20 of rising costs . Reflective of this industry trend, the
21 companies in my proxy group operate under a variety of
22 cost adj ustment mechanisms, which range
23
40 Standard & Pdor' s Corporation, "Assessing U. S. Regulatory
24 Environments," RatingsDirect (Nov. 7, 2008)..25 41 The Value Line Investment Survey (Nov. 7, 2008).
1970 AVERA, DI REB 32
Idaho Power Company
.
.
.
1 from riders to recover bad debt expense and
2 post-retirement employee benefit costs to adjustment
3 clauses designed to address the rising costs of
4 environmental compliance measures.
5 For example, apart from revenue decoupling and
6 other attrition rate adj ustments, Pacific Gas and
7 Electric Company benefits from a number of other
8 balancing account mechanisms that cover a significant
9 portion of its revenue requirements. Similarly, Xcel
10 Energy, Inc., also benefits from a transmission cost
11 recovery adj ustment that allows the utility to recover
12 incremental transmission investments between rate cases,
13 as well as an adjustment clause to account for the impact
14 of demand side management programs. Moreover, in
15 response to the heightened risk associated with
16 utili ties' exposure to substantial costs for
17 environmental' remediation, adjustment mechanisms designed
18 to allow for recovery of these costs outside a general
19 rate case have become increasingly prevalent.
20 Considering that the impact of various adjustment
21 mechanisms is. already reflected in the cost of equity
22 estimates for the proxy firms, there is no basis for Ms.
23 Carlock's contention that Idaho Power's risks are lower
24 than for other electric utilities.
25 Q.Does reference to obj ecti ve risk measures
1971 AVERA, DI REB 33
Idaho Power Company
.
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
1 confirm your conclusion that Idaho Power's investment
2 risks are comparable to the utilities in your proxy
3 group?
4
5 /
6
7 /
8
9 /
1972 AVERA, DI REB 33a
Idaho Power Company
.
.
.
1 A.Yes. As discussed in my direct testimony,
2 Idaho Power is rated "BBB" by S&P, which is identical to
3 the average for the firms in the Utility Proxy Group.
4 Meanwhile, Value Line has assigned IDACORP a Safety Rank
5 of "3" and a Financial Strength Rating of "B+", which are
6 also the same as the proxy group average. These
7 cri teria, which reflect obj ecti ve, published indicators
8 that incorporate consideration of a broad spectrum of
9 risks, including the impact of regulatory adjustment
10 clauses, financial and business position, relative size,
11 and exposure to company specific factors, demonstrate
12 that investors regard this group as having comparable
13 risks to Idaho Power.
14 Q.Do you believe that investment community risk
15 indicators, such as S&P' s credit ratings, may not reflect
16 an informed assessment of regulatory risks?
17 A.No. Ms. Carlock indicated that in assigning
18 credit ratings "regulatory risks may not be fully
19 analyzed," and she asserted that "regulatory mechanisms
20 for example may not be completely understood and may not
21 be adequately reflected. "42 In fact, however, the
22 investment community clearly recognizes that an accurate
23 evaluation of regulatory climate, including the specific
24 adjustment mechanisms affecting a utility's cash flows,
25 is critical in any
1973 AVERA, DI REB 34
Idaho Power Company
1.2
3 /
4
5 /
6
7 /
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24 42 Response to IPC Request No. 23..25
1974 AVERA,DI REB 34a
Idaho Power Company
.
.
1 assessment of investment risk. For example, S&P noted in
2 a recent publication entitled "Assessing U. S. Utility
3 Regulatory Environments "that, "The assessment of
4 regulatory risk is perhaps the most important factor in
5 Standard & Poor's Ratings Services' analysis of aU. S.
6 regulated, investor-owned utility's business risk. "43
7 Credi t rating agencies such as S&P devote considerable
8 resources towards their analyses of a utility's credit
9 risks, including the impact of regulation and related
10 adjustment mechanisms.
11 With respect to Idaho Power specifically,
12 Moody's concluded, "A key consideration in order for
13 (Idaho Power) to stabilize its rating outlook and
14 maintain its Baal senior unsecured rating will be the
15 extent to which the IPUC is supportive in any future
16 regulatory filings. "44 Similarly, Fitch noted that
17 " (m) eaningful price increases will be required to recover
18 planned capital expenditures to meet infrastructure and
19 growth requirements,45 while S&P cited" (r) egulatory
20 challenges in meeting rising costs and a large
21
22 43 Standard & Poor's Corporation, "Assessing u. S. Regulatory
Environments," RatingsDirect (Nov. 7, 2008).
23
44 Moody's Investors Service, "Credit Opinion: Idaho Power Company,"
24 Global Credit Research (June 4, 2008)..25 45 Fitch Ratings, Ltd., "Idaho Power Company," Global Power U. S. and
Canada Credit Analysis (Apr. 10, 2008).
1975 AVERA, DI REB 35
Idaho Power Company
.
.
17
18
19
1 capital expenditure program" as a key risk exposure. 46
2 The investment community is aware of the impact that
3 regulatory decisions can have on Idaho Power's risks, and
4 there is no basis to conclude that their risk assessment
5 is somehow lacking.
6 Q.What other evidence indicates the importance of
7 reasonable regulatory decisions on Idaho Power' s ability
8 to maintain its financial integrity?
9 A.As noted earlier, the outcome of Idaho Power's
10 last rate proceeding in Case No. IPC-E-03-13 was
11 instrumental in S&P' s decision to downgrade Idaho Power's
12 corporate cre~it rating from "A-" to "BBB+" in November
13 2004. In explaining that action, S&P noted:
14 Following the IPUC staff's 3.1% rate increase
recommendation in February 2004, Standard &
Poor's said that "a final decision by the
commission that adopted a rate increase akin to
that proposed by the staff could have an
adverse effect on bondholder protection
measures. " The final IPUC ruling is indeed
substantially closer to the staff's position
than the company's, and will weaken credit
protection measures. 47
15
16
20 Similarly, Moody's also downgraded the Company's issuer
21 rating from "A3" to "Baal", citing the risks associated
22 with
23
4 6 Standard & Poor's Corporation, "Idaho Power Co.," Ra tingsDirect
2 4 ( Feb. i , 2008)..25 47 Standard & Po'or's Corporation, "IDACORP and Unit Ratings Lowered,
Removed From CreditWatch Negative," RatingsDirect (Nov. 29, 2004).
1976 AVERA, DI REB 36
Idaho Power Company
.
.
1 hydroelectric power and ongoing capital commitments, as
2 well as the need for additional regulatory support as key
3 factors leading to lower credit ratings for Idaho Power:
4 The downgrade of IPC' s ratings reflects: 1)
expected weaker cash flow coverage of interest
and debt; 2) the likelihood for continuednegati ve free cash flow over the next few
years, with internally generated funds falling
short of meeting the dividend requirements of
IDACORP and significant utili ty-related capital
spending; 3) persistent drought conditions that
are likely to result in higher supply costs,
not all of which are recoverable under the
utility's power cost adj ustment mechanism; 4)
the final resolution this fall of the company's
rate case, which resulted in a revenue increase
of a little more than half of the company's
updated request; and 5) the likely need foraddi tional support from the Idaho Public
Utility Commission (IPUC) in future rate
proceedings as IPC adds new generation and
transmission infrastructure to help meet
customer and load growth and ensure reliability
of service. 48
5
6
7
8
9
10
11
12
13
14
15 Citing similar concerns over deteriorating financial
16 metrics, S&P again lowered Idaho Power's corporate credit
17 rating from "BBB+" to "BBB" in January 200849, with
18 Moody's
19
20
21
22 48 Moody's Investors Service, "Ratings Action: IDACORP, Inc.," Global
Credit Research (Dec. 3, 2004).
23
49 Standard & Poor's Corporation, "IDACORP, Idaho Power Co. Ratings
24 Lowered One Notch To 'BBB'; Outlook Stable," RatingsDirect (Jan. 31,
2008) ..25
1977 AVERA, DI REB 37
Idaho Power Company
.1 and Fitch presently maintaining a "negative" outlook for
2 Idaho Power's credit standing. 50
3 Considering these successive downgrades and the
4 fact that Moody's and Fitch have already assigned a
5 "negative" outlook to Idaho Power, the perception of lack
6 of regulatory support would undoubtedly place further
7 downward pressure on current ratings. Such an outcome
8 would be inconsistent with the IPUC' s stated desire to
9 maintain Idaho Power' s credit ratings and lends further
10 support for a_ return on equity above the top of Ms.
11 Carlock's recommended range. 51
12 Q.Is there evidence regarding the importance of.13 regulatory support in determining a utility's financial
14 integrity?
15 A.Yes. Investment publications and the trade
16 press are replete with examples that highlight the
17 cri tical role that a constructive regulatory environment
18 plays in investors' assessment of a utility' s credit
19 quali ty. In discussing the outlook for the utility
20 industry, for example, Fitch Ratings, Ltd. noted that:
21 Regulatory risk remains a recurring theme in
Fitch's 2008 outlook. For regulated electric22 utili ties, there is continuing event risk
related to state
23
/
24.25 /
1978 AVERA, DI REB 38
Idaho Power Company
1.2
3 /
4
5 /
6
7 /
8
9
10
11
12.13
14
15
16
17
18
19
20
21
50 Moody's Investors Service, "Moody's Changes Outlook of Idacorp And
22 Sub to Negative," Press Release (June 3, 2008); Fitch Ratings Ltd.,
"Idaho Power Company," Global Power u.s. and Canada Credit Analysis
23 (Apr. 10, 2008).
.24 51 Idaho Public Utilities Commission, Order No. 29505 (May 25, 2004)
at 43.
25
1979 AVERA, DI REB 38a
Idaho Power Company
.
.
1
2
regulatory and political reactions to higher
energy bills. ... The risk is heightened by
the convergence of rising costs for fuel,
equipment and maintenance materials, pension
and medical benefits, and infrastructure
investments. 52
3
4
5 More recently, S&P concluded "the quality of regulation
6 is at the forefront of our analysis of utility
7 creditworthiness. "53 Accordingly, it is critical to
8 assure investors' confidence in a balanced approach if
9 reasonable access to capital is to be maintained.
10 Q.In light of the shortfalls in Ms. Carlock's
11 analysis and her failure to present a balanced assessment
12 of Idaho Power's relative investment risks, what is your
13 conclusion regarding her recommendations in this case?
14 A. In my opinion, Ms. Carlock's recommended 10.25
15 percent cost of equity falls well short of the rate of
16 return that investors require from Idaho Power. In order
17 to maintain and expand utility infrastructure, it is both
18 reasonable and necessary that the Company be provided the
19 opportunity to maintain its credit standing and ability
20 to attract capital. To meet these challenges
21 successfully and economically - particularly during times
22 of capital market adversity - it is crucial that Idaho
23 Power receive. adequate
24.25 /
1980 AVERA, DI REB 39
Idaho Power Company
.
.
.
15
16
17
18
19
20
21
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
22 52 Fitch Ratings, Ltd., "U. S. Utilities, Power & Gas 2008 Outlook,"
at 5 (Dec. 11, 2007).
23
53 Standard & Poor's Corporation, "Assessing U. S. Utility Regulatory
24 Environments," RatingsDirect (Nov. 7, 2008).
25
1981 AVERA, DI REB 39a
Idaho Power Company
.
.
.
16
17
1 support for its credit standing. Ms. Carlock's
2 recommendation is inadequate to meet this goal.
3 At the very least, the IPUC should consider the
4 dramatic upward shift in long-term capital costs and the
5 deterioration in Idaho Power's credit ratings since it
6 approved a 10.25 percent ROE for the Company in Case No.
7 IPC-E-03-13. Ms. Carlock granted that, in selecting a
8 point estimate from within a range, "any point within
9 (the) range is reasonable. "54 Coupled with the higher
10 returns demanded by investors, the ongoing risks
11 associated with Idaho Power's continued exposure to
12 wholesale power markets, and the downward pressures on
13 its credit standing, this would suggest a minimum cost of
14 equity at the very top of Ms. Carlock's 9.5 percent to
15 10.5 percent range.
v.MATTHEW I. KA
Q.Briefly describe how Mr. Kahal arrived at his
18 recommended cost of equity for Idaho Power.
19 A.Mr. Kahal recommended a 10.5 percent ROE for
20 Idaho Power based primarily on the results of the
21 constant growth DCF model applied to alternative groups
22 of electric utili ties. Mr. Kahal developed his proxy
23 groups based on the companies included in Value Line's
24 Electric Utility (West) industry group, as well as a
25 subset of the comparable
1982 AVERA, DI REB 40
Idaho Power Company
1.2
3 /
4
5 /
6
7 /
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24 54 Carlock Direct at 15..25
1983 AVERA,DI REB 40a
Idaho Power Company
1 utili ties developed in my direct testimony that Mr. Kahal.2 characterized as operating in "non-restructured" states.
3 In addition to the DCF model, Mr. Kahal also examined
4 historical and proj ected earned rates of return for his
5 reference groups. Based on the results of his analyses,
6 Mr. Kahal concluded that a reasonable cost of equity
7 would fall in the range of 9.4 percent to 10.4 percent,
8 al though the DCF results for his two proxy groups
9 suggested a range of 9.9 percent to 10.4 percent and 9.6
10 percent to 10.6 percent, respectively. In explaining his
11 recommended ROE of 10.5 percent for Idaho Power, Mr.
12 Kahal noted that it was "toward the upper end" of his DCF.13 range. 55
14 Q.Did Mr. Kahal adequately recognize the
15 importance associated with reliance on multiple methods
16 and approaches in estimating the cost of equity?
17 A.No. Apart from passing reference to the
18 comparable earnings approach, which I address
19 subsequently, Mr. Kahal ignored the results of other
20 methods, such as the CAPM, to check or validate his
21 results. As I explained earlier, however, no single
22 method or model should be relied upon to determine a
23 utility's cost of equity because no single approach can
24 be regarded as wholly reliable. Considering the results.25 of al ternati ve methods and
1984 AVERA, DI REB 41
Idaho Power Company
1.2
3 /
4
5 /
6
7 /
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24 55 Kahal Direct at 42..25
1985 AVERA,DI REB 41a
Idaho Power Company
1 approaches provides greater confidence that the end.2 result is reflective of investors' required rate of
3 return. Regulatory Finance: Utilities' Cost of Capital
4 concl uded that:
5 When measuring equity costs, which essentially
deal with the measurement of investor
6 expectations, no one single methodology
provides a foolproof panacea. If the cost of
7 equi ty estimation process is limited to one
methodology, such as DCF, it may severely bias8 the results. 56
9 Q.Do you believe that the results of Mr. Kahal' s
10 constant growth DCF analyses mirror investors' long-term
11 expectations in the capital markets?
12 A.No. There is every indication that Mr. Kahal' s.13 resul ts are biased downward and fail to reflect
14 investors' required rate of return. As Mr. Kahal
15 correctly observed, the "g" component of the DCF model
16 should be prospective and must reflect the growth
17 "expected by investors. "57 But as he went on to note,
18 the environment presumed by the constant growth DCF
19 approach he employed does not exist in reality. Mr.
20 Kahal granted' the significant dislocations recently faced
21 by electric utili ties, noting that:
22
23 56 Morin, Roger, "Regulatory Finance: Utilities i Cost of Capital,"
Public Utilities Reports, Inc. at 238 (1994).
24
57 Kahal Direct at 17 (emphasis original)..25
1986 AVERA, DI REB 42
Idaho Power Company
.
.
1 (M) Y experience in recent years with utili ties
has been that these historic measures have been
very volatile and are not reliable as long-runprospecti ve measures. This may be due in part
to extensive corporate restructuring in the
energy industry. 58
2
3
4
5 And while Mr. Kahal noted that his proj ected growth rates
6 "warrants substantial emphasis," he also recognized that
7 "(t) here are a number of reasons why investor
8 expectations of long-run growth could differ from the
9 limited, five-year proj ections from security analysts. "59
10 Considering that investors' expectations could differ
11 substantially from the growth rates he relied on, Mr.
12 Kahal concluded that the resulting cost of equity
13 estimates "should be subj ect to a reasonableness test and
14 corroboration. "60 If the growth projections used to apply
15 the DCF model do not fully reflect the long-term
16 expectations investors have built into stock prices, the
1 7 resulting cost of equity estimates will be biased
18 downward.
19 Q.Did Mr. Kahal test the reasonableness of the
20 individual growth estimates he relied on to reach his
21 recommended ROE for Idaho Power?
22 A.No. Mr. Kahal' s mechanical application of the
23 constant growth DCF model contradicts his own
24.25
58 Kahal Direct at 21.
59 Kahal Direct at 22-22.
60 Kahal Direct at 23.
1987 AVERA, DI REB 43
Idaho Power Company
.1 admonishment to avoid simply plugging alternative growth
2 rates into the DCF formula with no consideration for the
3 reasonableness of the end results. In fact, many of the
4 growth measures embodied in Mr. Kahal' s constant growth
5 DCF application make no economic sense.
6 For example, consider the fact that four of the
7 Value Line growth rates reported on page 4 of Mr. Kahal' s
8 Exhibi t No. 604 were 2.0 percent or less. A growth rate
9 of 2.0 percent, when combined with Mr. Kahal' s average
10 dividend yield of approximately 3.9 percent, 61 suggests a
11 DCF cost of equity estimate of approximately 5.9 percent.
12 Indeed, one of the growth values that Mr. Kahal.13 referenced was less than zero,62 implying that the
14 utility's cost of equity is below its dividend yield.
15 Similarly, almost one-third of the individual growth
16 rates contained on page 5 of Mr. Kahal' s Exhibit No. 604
17 were 3.0 percent or less, implying a cost of equity of at
18 most 6.9 percent. These implied cost of equity estimates
19 fall far below the average yield on triple-B public
20 utility bonds reported by Moody's for October 2008 of
21 approximately 8.6 percent. 63 Clearly, the risks
22 associated with an investment in public utility common
23 stocks exceed
24.25 /
1988 AVERA, DI REB 44
Idaho Power Company
.
.
16
17
18
19
20
21
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
22 61 Exhibit No. 6D4, p. 1. This actually overstates the dividend
yield, which Mr. Kahal has adj usted for one-half years' growth.
23
24.25
62 Exhibit No. 604, p. 4.
63 Moody's Investors Service, CreditTrends.com (retrieved Nov. 14,
2008) .
1989 AVERA, DI REB 44a
Idaho Power Company
.
.
.
1 those of long-term bonds, and Mr. Kahal' s growth measures
2 result in a built-in downward bias to his DCF
3 conclusions, which provide no meaningful information
4 regarding the expectations and requirements of investors.
5 Q.What other evidence indicates that Mr. Kahal' s
6 DCF analysis fails to reflect the current requirements of
7 investors?
8 A.As indicated earlier, Mr. Kahal made no attempt
9 to reflect the impact of the ongoing financial crisis on
10 investors' required returns. Considering the dramatic
11 upward trend in long-term capital costs, this omission
12 virtually ensures that Mr. Kahal' s recommendations are
13 downward biased. Consider the dividend yield component
14 of Mr. Kahal' s DCF analysis, for example. While Mr.
15 Kahal noted a "slight upward trend" in dividend yields
16 over the six-month period ending September 2008,64 he
17 nonetheless elected to base his analysis "on market
18 condi tions during the second and third calendar quarters
19 of 2008, "65 rather than relying on the most recent
20 information available to him.
21 Q.How do current dividend yields for Mr. Kahal' s
22 proxy groups compare with the values used in his DCF
23 analysis?
24
64 Kahal Direct at 20.
25
65 Kahal Direct at 24.
1990 AVERA, DI REB 45
Idaho Power Company
.1 A.Since September 2008, utility stock prices have
2 continued to decline sharply in response to the upward
3 revision in investors' required returns. As a result,
4 di vidend yields have also increased significantly. As
5 shown on Exhibit No. 81, based on average closing prices
6 in November 2008, the expected dividend yield for Mr.
7 Kahal' s West Region proxy group is now approximately 4. 7
8 percent, versus the 3.9 percent calculated in his direct
9 testimony. Similarly, the indicated dividend yield for
10 Mr. Kahal' s Restricted West Region proxy group is now on
11 the order of 5.1 percent, which is 50 basis points higher
12 than the 4.6 percent figure used in his analysis..13
14
Q. What cost of equity is indicated if current
di vidend yields are incorporated into Mr. Kahal' s DCF
15 analysis?
16 A.As shown on Exhibit No. 82, incorporating a
17 di vidend yield for Mr. Kahal' s proxy groups based on
18 average closing stock prices in November 2008 results in
19 midpoint cost of equity estimates for the West Region and
20 Restricted West Region groups of 10.95 percent and 10.61
21 percent , respectively. Because these estimates rely on
22 Mr. Kahal' s growth rate ranges, which incorporate the
23 impact of illogical values discussed earlier, these
24 resul ts continue to be downward biased. Nevertheless,.25 they confirm my earlier conclusion that a fair ROE for
Idaho Power should be
1991 AVERA, DI REB 46
Idaho Power Company
.1 established above the 10.5 percent upper end of Ms.
2 Carlock's ROE range.
3 Q.Did Mr. Kahal offer any evidence to support his
4 contention that DCF results for your non-utility proxy
5 group should be rej ected?
6 A.No.. Mr. Kahal simply asserted (p. 30) that,
7 because the obj ecti ve in this case was to determine an
8 ROE for Idaho Power's regulated utility operations, data
9 for unregulated companies have "no value at all."
10 Al though he provides no detailed explanation for his
11 posi tion, Mr. Kahal apparently contends that the
12 investment risks of my non-utility group were not.13
14
comparable to Idaho Power or the utility proxy group I
developed in my testimony. In fact, however,
15 participation in competitive markets says nothing at all
16 about the overall investment risks perceived by
17 investors, which is the very basis for a fair rate of
18 return.
19 For example, consider (1) an electric utility
20 operating in regulated markets that has experienced an
21 inability to recover the costs incurred to provide
22 service, and (2) Wal-Mart Stores, Inc. ("Wal-Mart"),
23 which faces competition on numerous fronts. Despite its
24 lack of a regulated monopoly, with a double-A bond.25 rating, the highest Value Line Safety Rank, and a beta of
1992 AVERA, DI REB 47
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 0.70, the investment community would undoubtedly regard
2 Wal-Mart as the less
3
4 /
5
6 /
7
8 /
9
1993 AVERA, DI REB 47a
Idaho Power Company
.
.
1 risky alternative. In fact, my review of objective
2 indicators of investment risk - which consider the impact
3 of competition and market share - demonstrated that, if
4 anything, the non-utility proxy group is less risky in
5 the minds of investors than the common stock of electric
6 utili ties, including Idaho Power. 66
7 Meanwhile, Mr. Kahal' s contention (p. 27) that
8 an estimate of the required return for firms in the
9 competi ti ve sector of the economy "is not reasonable for
10 use in this case" is wrong. In fact, returns in the
11 competitive sector of the economy form the very
12 underpinning tor utility ROEs because regulation purports
13 to serve as a substitute for the actions of competitive
14 markets. The Supreme Court has recognized in the
15 Bluefield and Hope cases that it is the degree of risk,
16 not participation in particular business acti vi ties,
17 which is relevant in evaluating an allowed ROE for a
18 utility.
19 Q.Do you agree with Mr. Kahal' s assertions
20 regarding the elimination of certain companies in
21 analyzing the cost of equity for Idaho Power?
22 A.No. Mr. Kahal argued for the elimination of
23 companies based on an assessment of the degree of
24 regulatory restructuring at the retail level or.25 participation' in non-
1994 AVERA, DI REB 48
Idaho Power Company
.
.
16
17
18
19
20
21
22
23
24.25
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
66 As shown in Table 2 of my direct testimony, the Non-Utility Proxy
Group was less risky than Idaho Power and the Utility Proxy Group
across the four major indicators of investment risk.
1995 AVERA, DI REB 48a
Idaho Power Company
.
.
1 utili ty operations. However, he failed to demonstrate
2 how his subj ecti ve criteria translate into differences in
3 the investment risks perceived by investors. As I amply
4 demonstrated in my direct testimony, 67 a comparison of
5 obj ecti ve indicators demonstrates that investment risks
6 for the firms in my proxy groups are relatively
7 homogeneous and comparable to Idaho Power. Moreover,
8 there are significant errors and inconsistencies
9 associated with Mr. Kahal' s approach that justify
10 rejecting his alternative proxy groups altogether.
11 Q.Did Mr. Kahal demonstrate a nexus between the
12 subjective criteria he used to define his proxy groups
13 and obj ecti ve measures of investment risk?
14 A. No. Under the regulatory standards established
15 by Hope and Bluefield, the salient criteria in
16 establishing a meaningful proxy group to estimate
17 investors' required return is relative risk, not the
18 degree of regulatory restructuring. Mr. Kahal presented
19 no evidence to demonstrate a connection between the
20 subjective criteria that he employed and the views of
21 real-world investors in the capital markets.
22 Q.What objective evidence can be evaluated to
23 confirm the conclusion that these subjective criteria are
24.25 67 Pages 36-38 and 50-52.
1996 AVERA, DI REB 49
Idaho Power Company
.
.
1 not synonymous with comparable risk in the minds of
2 investors?
3 A.Bond ratings are perhaps the most obj ecti ve
4 guide to utilities' overall investment risks and they are
5 widely cited in the investment community and referenced
6 by investors. While the bond rating agencies are
7 primarily focused on the risk of default associated with
8 the firm's debt securities, bond ratings and the risks of
9 common stock are closely related. As noted in Regulatory
10 Finance: Utili ties' Cost of Capital:
11 Concrete evidence supporting the relationship
between bond ratings and the quality of a
security is abundant . . . The strong
association between bond ratings and equity
risk premiums is well documented in a study by
Brigham and Shome (1982).68
12
13
14
15 While credit ratings provide the most widely referenced
16 benchmark for investment risks, other quality rankings
17 published by investment advisory services and rating
18 agencies also provide relative assessments of risk that
19 are considered by investors in forming their
20 expectations. For example, Mr. Kahal considered Value
21 Line's Safety Rank, beta, and Financial Strength Rating
22 in evaluating his reference group. 69
23
24 68 Morin, Roger A., "Regulatory Finance: Utilities' Cost of Capital,"
Public Utility Reports (1994) at 81..25
69 Exhibit No. 603.
1997 AVERA, DI REB 50
Idaho Power Company
.
.
.
1 As I noted in my direct testimony (p. 38), my
2 proxy group of 27 electric utilities had an average
3 corporate credit rating of triple-B. Similarly, credit
4 ratings assigned to the eleven utili ties excluded by Mr.
5 Kahal based on his subj ective tests ranged from "BBB-" to
6 "BBB+" and were entirely comparable to those assigned to
7 the remainder of the companies in my utility proxy group.
8 Considering that credit ratings provide one of the most
9 widely referenced benchmarks for investment risks, a
10 comparison of this obj ecti ve risk indicator demonstrates
11 that the range of risks for the companies eliminated
12 under the subj ecti ve criteria proposed by Mr. Kahal are
13 virtually identical to the remaining companies that he
14 accepted as comparable. A review of the key Value Line
15 risk indicators discussed in my direct testimony also
16 confirm the conclusion that the firms excluded by Mr.
17 Kahal are entirely comparable to the remainder of my
18 utili ty proxy group. In fact, PG&E Corporation, which
19 was one of my proxy companies deemed by Mr. Kahal to be
20 "less useful and appropriate, "70 was included in his own
21 West Region proxy group.
22 Q.What inconsistencies are associated with the
23 alternative tests proposed by Mr. Kahal?
24
25 70 Kahal Direct at 28.
1998 AVERA, DI REB 51
Idaho Power Company
1 A.While Mr. Kahal proposes to eliminate.2 companies based on his assessment of the proportion of
3 revenues from regulated utility operations, he presented
4 no explanation or evidence supporting his "test." Apart
5 from the fact that it is often impossible to accurately
6 apportion financial measures between utility and
7 non-utility sources, Mr. Kahal' s subjective assessment is
8 inconsistent with the companies he accepted in his own
9 reference group of western utilities. For example, while
10 Mr. Kahal argued to exclude companies with "substantial
11 unregulated operations," he included Black Hills
12 Corporation ("Black Hills") in his reference group..13 Black Hills reported in its most recent Form 10-K Report
14 that its utility operations accounted for 44 percent of
15 operating revenues, with other operations - including oil
16 and gas and coal mining, making up the remaining 55
17 percent. Similarly, in addition to its electric utility
18 operations, Hawaiian Electric Industries, Inc. ("Hawaiian
19 Electric") also owns and operates American Savings Bank,
20 which is the third largest financial institution in
2 i Hawaii. Despite the fact that competi ti ve banking
22 activities accounted for approximately 41 percent of
23 operating income in 2007, Mr. Kahal elected to include
24 Hawaiian Electric in his proxy group. Thus, Mr. Kahal' s.25 evaluation of my proxy companies is totally at odds with
his own evaluation and analyses.
1999 AVERA, DI REB 52
Idaho Power Company
.
.
20
1 Similarly, Mr. Kahal' s assertions concerning
2 the risks associated with restructuring are ill-defined
3 and inconsistent with his arguments over the implications
4 of competition. For example, while Mr. Kahal argues that
5 CenterPoint Energy should be excluded because it operates
6 in restructured power markets, CenterPoint Energy is
7 engaged almost exclusively in providing regulated
8 electric and gas distribution and transmission services. 71
9 As CenterPoint Energy noted:
10 It is a transmission and distribution electric
utility that operates wholly within the state
of Texas. Neither CenterPoint Houston nor any
other subsidiary of CenterPoint Energy makes
sales of electric energy at retail or
wholesale, or owns or operates any electric
generating facilities. 72
11
12
13
14 While CenterPoint Energy does not participate in
15 restructured wholesale power markets, Avista Corp. - one
16 of the companies included in Mr. Kahal' s reference group
17 - specifically informed investors of its exposure to the
18 risks of energy commodity markets and reported that
19 wholesale power market purchases accounted for almost 30
percent of total energy needs. 73 Again, the
21 circumstances faced by the
22
23 /
24.25 /
2000 AVERA, DI REB 53
Idaho Power Company
.
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19
1
2
3 /
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5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
20 71 In Texas, where Centerpoint's operations are concentrated,
utili ties providing transmission and distribution service are
21 regulated by th~ Public Utility Commission of Texas on a rate of
return basis essentially the same as the IPUC regulation of Idaho
22 Power. Wholesale and retail sales are subj ect to competi ti ve
markets.
23
24.25
72 CenterPoint Energy 2007 Form 10-K Report at 2.
73 Avista Corp. 2007 Form 10-K Report at 11.
2001 AVERA, DI REB 53a
Idaho Power Company
.
.
.
1 utili ties in Mr. Kahal' s own proxy group are inconsistent
2 with the subj ective "tests" he proposes.
3 Q.What market risk premium did Mr. Kahal use to
4 apply the CAPM?
5 A.While Mr. Kahal declined to consider the
6 resul ts of the CAPM in arriving at his recommendation, he
7 relied on a market risk premium of 6.0 percent, which he
8 apparently derived from a single journal article and two
9 selected studies reported in a finance textbook.74
10 Q.What is the fundamental problem associated with
11 the approach underlying Mr. Kahal' s suggested application
12 of the CAPM?
13 A.Like the DCF model, the CAPM is an ex-ante, or
14 forward-looking model based on expectations of the
15 future. As a result, in order to produce a meaningful
16 estimate of investors' required rate of return, the CAPM
17 must be applied using data that reflects the expectations
18 of actual investors in the market. However Mr. Kahal' s
19 application of the CAPM method was premised only on
20 historical - not projected - rates of return. The
21 primacy of current expectations was recognized by
22 Ibbotson Associates:
23
24
25 74 Kahal Direct' at 35-36.
2002 AVERA, DI REB 54
Idaho Power Company
.
.
1
2
The cost of capital is always an expectational
or forward-looking concept. While the past
performance of an investment and other
historical information can be good guides and
are often used to estimate the required rate of
return on capital, the expectations of future
events are the only factors that actually
determine cost of capital. 75
3
4
5
6 By failing to look directly at the returns investors are
7 currently requiring in the capital markets, as I did on
8 Exhibi t No. 21, Mr. Kahal' s CAPM estimate significantly
9 understates investors' required rate of return.
10 Q.Are the selected references cited by Mr. Kahal
11 representative of investors' expectations?
12 A.No. Mr. Kahal claims that "real world" data
13 suggests that the market risk premium is significantly
14 lower than the values relied on in my analyses. First,
15 Mr. Kahal' s selected surveys from 2001 and 2003 do not
16 examine the forward-looking expectations of today's
17 investors to estimate the required market rate of return
18 in current capital markets. These studies reflect
19 historical data, not the current expectations of the
20 future that form the basis of investors' required returns
21 today. This critical distinction was recognized in a
22 published survey of risk premium research:
23
24.25 75 Morningstar, Ibbotson SBBI, 2008 Valuation Yearbook at 23.
2003 AVERA, DI REB 55
Idaho Power Company
.
.
1
2
The debate surrounding the equity risk premium
arises because theoretically such premia are
concerned with the extent to which risky stocksare "expected" to outperform a (relatively)
safe investment, whereas excess returns are
estimated values of this outperformance derived
from observed data. The lack of consensus
regarding the true value of the equity risk
premium arises from the fact that expectations
are unobservable hence can only be estimated,
and that such estimates will vary over time
depending, in part at least, on the sample
period used. 76
3
4
5
6
7
8 In other words, instead of directly considering
9 requirements in today' scapi tal markets, Mr. Kahal is
10 implici tly asserting that events and expectations for the
11 time periods covered by his two surveys are more
12 representati ve of what is likely to occur going forward.
13 This assertion runs counter to the assumptions underlying
14 the use of the CAPM to estimate investors' required
15 return, which is a purely forward-looking model.
16 Moreover, even if historical studies were
i 7 relevant in this context, there are other such studies of
18 equi ty risk premiums published in academic journals that
19 imply required rates of return considerably in excess of
20 those selected by Mr. Kahal. For example, a study
21 reported in the Financial Analysts' Journal noted that
22 the real risk premium for U. s.
23
24.25
76 Oyefeso Oluwatobi, "Would There Ever Be Consensus Value and Source
of the Equity Risk Premium? A Review of the Extant Literature,"
International Jqurnal of Theoretical and Applied Finance, Vol. 9, No.
2 (2006) 199-215.
2004 AVERA, DI REB 56
Idaho Power Company
.1 stocks averaged 6.9 percent over the period 1889 through
2 2000 and concluded that:
3 Over the long term, the equity risk premium is
likely to be similar to what it has been in the
past and returns to investment in equity will
continue to substantially dominate returns to
investments in T-bills for investors with a
long planning horizon. 77
4
5
6
7 Similarly, based on a study of ex-ante expected returns
8 for a sample of S&P 500 firms over the 1983-1998 period,
9 a 2003 article in Financial Management found an expected
10 market risk premium of 7.2 percent. 78
11 In contrast to the conclusions that Mr. Kahal
12 draws from his review of selected studies, other.13 researchers are less sanguine and recognize that the
14 shortcomings of academic methods can produce results that
15 deviate from investors' actual expectations and
16 requirements:
17 The above discussion suggests that the equity
premium debate is far from over, and that the18 use of excess returns as a proxy for such
premia, while convenient, may capture a19 substantial amount of noise and be uncorrelated
wi th equity risk premia particularly over the20 short-run.79
21
22
23
.24 77 Mehra, Ranjnish, "The Equity Premium: Why Is It a Puzzle?",
Financial Analysts' Journal (January/February 2003) .
25
2005 AVERA, DI REB 57
Idaho Power Company
1.2
3 /
4
5 /
6
7 /
8
9
10
11
12.13
14
15
16
17
18
19
20 78 Harris, R.S., Marston, F. C., Mishra, D. R., and O'Brian, T. J.,
"Ex Ante Cost of Equity Estimates of S&P 500 Firms: The Choice
21 Between Global and Domestic CAPM, Financial Management (Autumn 2003)
at Table I.
22
79 Oyefeso Oluwatobi, "Would There Ever Be Consensus Value and Source
23 of the Equity Risk Premium? A Review of the Extant Literature,"
International Journal of Theoretical and Applied Finance, Vol. 9, No.
24 2 (2006) 199-215..25
2006 AVERA, DI REB 57a
Idaho Power Company
.1 In fact, no selected historical study, or group of
2 studies, is a substitute for an analysis of investors'
3 current expectations in the capital markets, such as that
4 incorporated in my CAPM analysis shown on Exhibit No. 21.
5 Q.Do the "real world" risk premiums relied on by
6 Mr. Kahal make economic sense?
7 A.No. As noted on page 36 of Mr. Kahal' s
8 testimony, the historical surveys included in his
9 assessment found market equity risk premiums of 5.5
10 percent and 3.8 percent. But multiplying these market
11 equity risk premiums by Mr. Kahal's beta of 0.83, and
12 combining the resulting risk premiums with his 4.5.13
14
percent risk-free rate, results in indicated cost of
equi ty estimates of approximately 7. 7 percent and 9.1
15 percent. These returns fall at or below current yields
16 on triple-B utility bonds and are dramatically lower than
17 the earnings Value Line expects utili ties to achieve in
18 coming years.' By any objective measure, such results
19 fall woefully short of required returns from an
20 investment in Idaho Power's common equity and confirm
21 that the inputs to Mr. Kahal' s CAPM cost of equity have
22 little relati9n to the expectation of real-world
23 investors.
24.25
Q.Is there anything wrong with the approach that you
employed to determine the equity risk premium for your
forward-looking CAPM analysis (Exhibit No. 21)?
2007 AVERA, DI REB 58
Idaho Power Company
.
.
.
1 A.No. As explained in my direct testimony, I
2 estimated the current equity risk premium by first
3 applying the DCF model to estimate investors' current
4 required rate of return for the firms in the S&P 500 and
5 then subtracting the yield on government bonds. Mr.
6 Kahal contends that this CAPM analysis is flawed because
7 of an alleged upward bias in the market risk premium. In
8 fact, however, the use of forward-looking expectations in
9 estimating the market risk premium is well accepted in
10 the financial literature. For example, in "The Market
11 Risk Premium: Expectational Estimates Using Analysts'
12 Forecasts" (Journal of Applied Finance, Vol. 11 No.1,
13 2001 J, Robert S. Harris and Felicia C. Marston employed
14 the DCF model and earnings growth proj ections from IBES _
15 just as I did in Exhibit No. 21.
16 Mr. Kahal' s complaint about my forward-looking
17 CAPM approach seems to hinge on the fact that this method
18 produces an equity risk premium for the S&P 500 that is
19 considerably higher than the unrealistic benchmarks he
20 ci tes. But as I explained earlier, estimating investors'
21 required rate of return by reference to current,
22 forward-looking data, as I have done, is entirely
23 consistent with the theory underlying the CAPM
24 methodology, which is an ex-ante, or forward-looking
25 model based on expectations of the future. As a result,
2008 AVERA, DI REB 59
Idaho Power Company
1 in order to produce a meaningful estimate of required.2 rates of return,the CAPM is best-
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
2009 AVERA,DI REB 59a
Idaho Power Company
.1 applied using data that reflects the expectations of
2 actual investors in the market. Rather than look
3 backwards to risk premiums based on historical literature
4 articles or surveys, my analysis appropriately focused on
5 the expectations of actual investors in today' scapi tal
6 markets.
7 Q.Is there any merit to Mr. Kahal' s contention
8 that the CAPM analysis should consider al ternati ve beta
9 values?
10 A.No. Application of any quanti tati ve technique
11 to estimate the cost of equity is an attempt to determine
12 the expectations and requirements of real-world investors.13 in the capital markets. In this regard, the Value Line
14 beta values I used to apply the CAPM are perhaps the best
15 indicator of the risks investors are likely to associate
16 wi th electric utili ties such as Idaho Power. As noted in
17 Regula tory Finance: Utili ties r Cost of Capi tal:
18 Value Line betas are computed on a
theoretically sound basis using a broadly-based19 market index, and they are adjusted for the
regression tendency of betas to converge to
20 1.00. ... Value Line is the largest and most
widely circulated independent investment21 advisory service, and exerts influence on a
large number of institutional and individual22 investors and on the expectations of these
investors.8o
23
24.25
80 Morin, Roger A., "Regulatory Finance: Utilities' Cost of Capital,"
Public Utilities Reports (1994) at 65.
2010 AVERA, DI REB 60
Idaho Power Company
.1 In my experience, Value Line is the most widely
2 referenced source for beta in regulatory proceedings and
3 Mr. Kahal has presented no evidence that would call these
4 values into question.
5 Q.Please comment on Mr. Kahal' s application of
6 the comparable earnings approach.
7 A.By failing to evaluate the economic logic of
8 the individual returns for the companies in his reference
9 group, Mr. Kahal' s comparable earnings analysis suffers
10 from the same flaw explained earlier in connection with
11 his DCF application. For example, Mr. Kahal' s comparable
12 earnings results included a number of values that fall.13 below current' yields on public utility bonds. 81 Indeed,
14 almost one-half of the individual returns included in Mr.
15 Kahal' s comparable earnings approach for his West Region
16 proxy group (Exhibit No. 606, p. 1) were equal to 8.5
17 percent or less. With triple-B public utility bonds
18 yielding 8.6 percent in October 2008, these values
19 provide no meaningful guide to investors' expected rate
20 of return. As a result, Mr. Kahal's comparable earnings
21 analysis is woefully understated and should be ignored.
22
23 81 See, e.g., the 4.2 percent and 5.5 percent returns for Avista
Corp. and Black Hills Corp., respectively, included on page 1 of
24 Exhibit No. 606..25
2011 AVERA, DI REB 61
Idaho Power Company
.
.
1 Q.Is there any merit to Mr. Kahal' s admonition
2 (p. 38) that market to book ratios for electric utilities
3 should be considered in establishing Idaho Power's
4 allowed rates of return?
5 A.No. Underlying Mr. Kahal' s argument is the
6 supposi tion that regulators should set a required rate of
7 return to produce a market-to-book value of approximately
8 1.0. This is fallacious. For example, Regulatory
9 Finance: Utilities Cost of Capital noted that:
10 The stock price is set by the market, not by
regulators. The M/B ratio is the end result of
regulation, and not its starting point. The
view that regulation should set an allowed rate
of return so as to produce a M/B of 1.0,
presumes that investors are masochistic. They
commi t capital to a utility with a M/B in
excess of 1.0, knowing full well that they will
be inflicted a capital loss by regulators.
This is not a realistic or accurate view of
regulation. 82
11
12
13
14
15
16 Indeed, while Mr. Kahal' s example supposes that
17 investors expect an earned return of 11.0 percent on the
18 common equity. of his hypothetical utility, he suggests
19 that regulators only need to allow the utility an ROE of
20 7.3 percent. In other words, Mr. Kahal apparently
21 believes that regulators should establish equity returns
22 that will cause share prices to fall. Gi ven the
23 regulatory imperative of
24.25 82 Id. at 256.
2012 AVERA, DI REB 62
Idaho Power Company
.
.
.
13
14
1 preserving a utility's ability to attract capital, this
2 would be a truly nonsensical result.
3 Q.Does Mr. Kahal' s reference to the ROE
4 authorized by the IPUC in Idaho Power's last fully
5 li tigated rate proceeding support his recommendations in
6 this in proceeding?
7 A.No. Mr. Kahal cites the 10.25 percent ROE
8 approved for Idaho Power in Case No. IPC-E-03- 13,
9 presumably as support for the reasonableness of his 10.5
10 percent ROE recommendation here. But as discussed
11 earlier in response to Ms. Carlock, this ignores the
12 dramatic changes in capital market conditions and the
fact that the Company's investment risks have increased.
Because the record in Case No. IPC-E-03-13 was predicated
15 on Idaho Power's former single-A credit rating, the 10.25
16 percent ROE awarded by the IPUC does not consider the
17 higher risks that investors now associate with the
18 Company. Nor does it consider the significant increase
19 in investors' required return on long-term capital, as
20 evidenced by sharply higher yields on public utility
21 bonds.
22 Q.Do you agree with Mr. Kahal (p. 10) that
23 changes in dividend taxation enacted in 2003 have led to
24 a significant decline in investors' required rate of
25 return on equity?
2013 AVERA, Dr REB 63
Idaho Power Company
1 A.No.In light of the unprecedented capital.2 market events of this year and the uncertainties
3 associated
4
5 /
6
7 /
8
9 /
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
2014 AVERA,DI REB 63a
Idaho Power Company
.
.
1 with the incoming administration's policy responses, it
2 is ironic that Mr. Kahal would choose to focus on 2003
3 tax legislation as support for his recommendations. 83
4 While dividend taxation is certainly one factor that may
5 be considered by investors, the impact of changes in
6 di vidend taxation on the cost of equity for Idaho Power
7 is unclear. First, the important role that pension funds
8 and tax deferred accounts play in the capital markets
9 dilutes any effect that tax rate changes might have on
10 investors' required rate of return. This is because the
11 reduction in the taxation of dividends has no impact on
12 the returns for tax-free investors.
13 Moreover, using current capital market data to
14 estimate the cost of equity, such as my DCF and
15 forward-looking CAPM approaches, already incorporate any
16 effects of changes in tax policies. While Mr. Kahal
17 implies that changes in dividend taxation suggest a lower
18 cost of equity than in the past, this ignores other
19 significant factors that influence required returns. In
20 particular, risk perceptions in general, and for electric
21 utilities speGifically, have shifted sharply upward,
22 which would more than offset any decline in the equity
23 risk premium due to changes in dividend taxation.
24 Finally, investors are.25
2015 AVERA, DI REB 64
Idaho Power Company
.
.
18
19
20
21
22
23
24.25
1
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
83 The reduction in dividend taxation in the Jobs and Growth Tax
Relief and Reconciliation Act of 2003 will expire at the end of 2008
unless renewed by Congress.
2016 AVERA, DI REB 64a
Idaho Power Company
.
.
.
1 forward-looking and recognize that there is no guarantee
2 that the reduction in dividend taxation will continue.
3 Q.Did Mr. Kahal incorporate an allowance for
4 flotation costs?
5 A.No. Based on his assertion that IDACORP has no
6 plans to issue common stock, Mr. Kahal rej ected an
7 allowance for issuance costs.
8 Q.Is Mr. Kahal' s position consistent with
9 financial realities and the views of other practitioners?
10 A.No. The need for a flotation cost adjustment
11 to compensate for past equity issues is recognized in the
12 financial literature. In a Public Utili ties Fortnightly
13 article, for example, Brigham, Aberwald, and Gapenski
14 demonstrated that even if no further stock issues are
15 contemplated, a flotation cost adjustment in all future
16 years is required to keep shareholders whole, and that
17 the flotation cost adj ustment must consider total equity,
18 including retained earnings. 84 Similarly, Regula tory
19 Finance: Utilities' Cost of Capital contains the
20 following discussion:
21 Another controversy is whether the underpricing
allowance should still be applied when the
22 utili ty is not contemplating an imminent common
stock issue. Some argue that flotation costs
23
24
25
84 Brigham, E.F., Aberwald, D.A., and Gapenski, L.C., "Common Equity
Flotation Costs and Rate Making," Public Utilities Fortnightly, May
2, 1985.
2017 AVERA, DI REB 65
Idaho Power Company
.
.
.
14
1
2
are real and should be recognized in
calculating the fair rate of return on equity,
but only at the time when the expenses are
incurred. In other words, the flotation cost
allowance should not continue indefinitely, but
should be made in the year in which the sale ofsecuri ties occurs, with no need for continuing
compensation in future years. This argument
implies that the company has already been
compensated for these costs and/or the initial
contributed capital was obtained freely, devoid
of any flotation costs, which is an unlikely
assumption, and certainly not applicable to
most utilities. ... The flotation cost
adjustment cannot be strictly forward-looking
unless all past flotation costs associated with
past issues have been recovered. (p. 175)
3
4
5
6
7
8
9
10 Q.Do you agree with Mr. Kahal's position your
11 testimony failed to support an adjustment for flotation
12 costs?
13 A. No. The rationale underlying an adjustment for
past flotation costs was discussed in detail in my direct
15 testimony at pages 59-61. Further, while Mr. Kahal
16 asserts (p. 12) that I did not calculate a flotation cost
17 adder, this is incorrect. As noted in my direct
18 testimony (p.' 61), my evaluation indicated that the
19 flotation cost allowance requires an estimated adjustment
20 to the return on equity of approximately 3.6 percent to
21 10 percent, which translated into a flotation cost adder
22 of approximately 14 to 39 basis points at the time my
23 testimony was prepared.
24
25
2018 AVERA, DI REB 66
Idaho Power Company
.1 VI . DENNIS E. PESEAU
2 Q.Did Dr. Peseau conduct an independent study to
3 estimate a fair ROE for Idaho Power?
4 A.No. Dr. Peseau did not perform any independent
5 analyses to support his assertions regarding Idaho
6 Power's requested ROE. Rather, his assessment was based
7 entirely on inaccurate comparisons between 2007 and the
8 present.
9 Q.Please discussed the flaws in Dr. Peseau' s
10 evaluation.
11 A.Dr. Peseau argues that a fair return to Idaho
12 Power does not exceed the 10.25 percent ROE established.13
14
in 2007 based on (1) a comparison of bond yields, (2) a
comparison of beta values, and (3) a comparison of
15 changes in my forward-looking risk premium. In contrast
16 to the conclusions reached by Dr. Peseau, none of his
17 comparisons support his conclusion that investors'
18 required return for Idaho Power is equal to or below
19 10.25 percent.
20 First, while Dr. Peseau suggests that the
21 decrease in Treasury bond yields experienced since 2007
22 implies that investors' required returns on common equity
23 may have fallen, the exact opposite is true. Treasury
24 bond yields have declined because of a "flight to.25 quality" as investors' risk perceptions have mounted in
2019 AVERA, DI REB 67
Idaho Power Company
.
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
1 the face of the ongoing financial crisis. As the Wall
2 Street Journal noted, "Real-
3
4 /
5
6 /
7
8 /
9
2020 AVERA, DI REB 67a
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.1 world borrowing costs are in a different universe from
2 Treasury yields and Fed rates. "85 The fact that the
3 prices of Treasury bonds have been driven sharply higher
4 is the mirror image of higher, not lower returns for more
5 risky asset classes, such as the common stock of
6 utili ties like Idaho Power. Moreover, as discussed in
7 detail earlier, Dr. Peseau' s conclusion that yields for
8 utili ties such as IDACORP "have been essentially flat" is
9 not true. 86 The average triple-B utility bond yield
10 during 2007 was approximately 6.3 percent, versus 9.0
11 percent in November 2008, or an increase of 270 basis
12 points..13
14
Second, while Dr. Peseau speculates about the
potential impact of changes in beta values and the
15 implied market risk premium, he completely ignores the
16 ramifications of this market data. As documented in
17 Exhibi t No. 21 to my direct testimony, employing current
18 beta values and a forward-looking estimate of the current
19 market risk premium implies a cost of equity for my
20 Utility Proxy Group of 11.9 percent, which considerably
21 exceeds Dr. Peseau's artificial 10.25 percent "ceiling."
22 Third, Dr. Peseau - like Ms. Carlock and Mr.
23 Kahal - entirely ignores the fact that Idaho Power's
24 risks have.25 /
2021 AVERA, DI REB 68
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1.2
3 /
4
5 /
6
7 /
8
9
10
11
12.13
14
15
16
17
18
19
20 85 Gangloff, Mark,"Ahead of the Tape: The Shocks Are Getting A
Workout," The Wall Street Journal at Cl (Sep.17,2008) .
21
86 Peseau Direct at 26.
22
23
24.25
2022 AVERA, DI REB 68a
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.
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20
1 increased, as exemplified by the decline in the Company's
2 credi t rating. The fact is that while the Commission
3 professed a goal of maintaining Idaho Power's bond
4 ratings at or above the single-A level in 2004,87 the
5 authorized return has been inadequate to achieve this
6 obj ecti ve and. the Company has consistently been unable to
7 earn an ROE above the single digits. Unsurprisingly, the
8 associated decline in financial metrics has pushed Idaho
9 Power's S&P credit rating to "BBB", while Moody's and
10 Fitch maintain a "negative" outlook, warning investors of
11 the potential for yet another downgrade. Considering
12 these trends and the adverse conditions in today' s
13 capi tal markets, the ROE recommendations of Ms. Carlock,
14 Mr. Kahal, and Dr. Peseau are inadequate and portend
15 further deterioration in Idaho Power's finances if
16 adopted.
17 Q.Does this conclude your rebuttal testimony?
18 A.Yes.
19
21
22
23
24 87 Idaho Public Utilities Commission, Order No. 29505 (May 25, 2004)
at 43.
lt 25
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.1
2 open hear ing . )
(The following proceedings were had in
MR. BRUDER: Thank you. I make this
4 wi tness available for cross.
3
5 COMMISSIONER SMITH: Thank you. Mr. Ward,
6 do you have questions?
.
7
8
9
10
11 BY MR. WARD:
12 Q
MR. WARD: Yes, I do.
CROSS-EXAINATION
Doctor, can you hear me okay?
I can, Mr. Ward.
Thank you. If you'd turn to page 5 of
15 your rebuttal testimony, are you there, Doctor?
13 A
I am, Mr. Ward.
At line 19 you say, "The Value Line
18 Investment Survey reports that electric utili ties as a
14 Q
19 whole are anticipated to earn a return of 11.5 percent in
16 A
20 2008," and then on through the rest of that sentence. Do
17 Q
Yes.
Now, in your -- and you cite to page 2230
24 of the Value Line report; correct? It's in your.25
21 you see that?
22 A
footnote. I'm sorry, Doctor, did you hear me okay?
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23 Q
2024 AVERA (X)
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1 A I did, Mr. Ward. It is in my footnote and
2 I actually have that page in front of me now.
3 Q Okay; so you have Issue 11 of Value Line
4 in front of you?
5 A I have the cover page, page 2230 and I
6 also have the page for IDACORP which is 2236.I don't
have the pages for all the other companies.
Q We have run against the limits of
telephone cross-examination.Doctor,by any chance would
you have the full issue where you could grab it?
7
8
9
10
11 A I do not, Mr. Ward. It's in my office. I
12 am very familiar with Value Line and perhaps you could
13 ask your questions and we could discuss it without my
14 physically having them in front of us.
15 COMMISSIONER SMITH: Does he have a fax?
16 MR. WARD: It's really tough -- hold on a
17 second, Doctor. Can we go off the record for a moment?
18 COMMISSIONER SMITH: We'll be at ease for
19 a moment.
20 (Off the record discussion.)
21 BY MR. WARD: Doctor, this is going to beQ
22 pretty crude, but bear with me. If you had Issue 11 in
23 front of you, it would show, I believe, 16 Western
24 utilities. That is the issue that deals with Western
25 utilities, is it not?
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1 A That is correct. The summary numbers deal
2 wi th the entire industry as followed by Value Line.
3 Q I understand that, Doctor, and
4 interestingly enough, we just had a discussion about
5 proxy groups. One of your proxy groups is a group
6 selected from the 16 Western utilities covered by Value
7 Line, is it not?
8 A My proxy group which I explain in my
9 direct testimony was drawn from the entire national
10 sample. Some of those that were selected that met the
11 objective criteria are from the West, but the proxy group
12 was not limited to the West, but because I wanted to use
13 obj ecti ve measures of risk, I'm very, very mindful of the
14 problem the Commissioner brought up in his discussion
15 wi th Dr. Peseau, so I wanted to use obj ecti ve measures of
16 risk and I tried to screen through the entire Value Line
17 sample.
18 Q All right, let me try it this way, Doctor,
19 and, obviously, if you are concerned about my
20 characterization of the issue I'm looking at, please
21 speak up. Of' the 16 Western utilities covered by Value
22 Line by my in my review of this issue, only four had a
23 listed return on common equity of 11.5 percent or more.
24 Would you accept that, subject to check?
25 A . That may very well be true. In the
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1 discussion with Dr. Peseau, it was pointed out the
2 utilities in New Mexico and Arizona and Nevada are
3 suffering from severe financial pain that's led them to
4 be junk bond rated and I know that those returns are
5 below 11. 5.
6 Q Okay, and you jumped ahead of me and many
7 of the others, and notably, as you said, in Nevada and
8 New Mexico, are in single digits and well below 10 on
9 common equity. Would you accept that?
10 A That's true, and they are junk bond
11 rated.
12 Now, on the other hand, of those four thatQ
13 had an 11.5 return on equity or more, those four are
14 Edison, MDU, PG&E and Sempra. MDU and Sempra are quite
15 unusual, are they not, in that they have very substantial
16 unregulated businesses?
17 Well, I think that would be true of MDU.A
18 As to Sempra, it has very substantial regulated
19 businesses. It's the largest gas utility in the country,
20 as well as being an electric utility, so while it has
21 significant amounts of non-electric revenues, they are
22 largely regulated.
23 I will accept that -- well, bear with meQ
24 for a second, Doctor. Here's the Value Line -- in the
25 introductory business characterization segment of a Value
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1 Line report that's in the middle of the page, roughly
2 just below the middle of the page, Doctor, here's what
3 Value Line says about Sempra: "Has various non-utility
4 subsidiaries (54 percent of '07 earnings)." That's
5 pretty significant, isn't it?
6 A Yes, in '07 the earnings were significant.
7 I think there has been some divestiture of those
8 businesses since '07.
9 Q All right, and of the other two that I
10 could find that had an 11.5 percent return on equity or
11 more, PG&E is unusual, is it not, in that it has gone
12 through a relative recent bankruptcy?
13 A It has. The California Commission earlier
14 this year allowed a return of 11.35 for PG&E, so I think
15 its returns are consistent with what has been allowed.
16 Q Yes, and I'm certainly not familiar with
17 that bankruptcy proceeding, but wouldn't it be generally
18 true that going through bankruptcy tends to reduce your
19 total equity and, all other things being equal,
20 thereafter increase your return on equity because of the
21 reduction in equity?
22 A Not necessarily, Mr. Ward. It depends on
23 how it happened. In the case of PG&E, and what often
24 happens in bankruptcy, investors who previously were debt.25 investors become equity investors, so the debt is
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10
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.
1 converted to equity, so it's not always the case that the
2 total equity of the company is reduced. In fact, it
3 could be that the equity would increase. It just happens
4 that those poor souls who were equity holders when they
5 went into bankruptcy have much smaller pieces of the
6 business when it comes out of bankruptcy.
7 MR. WARD: Very well. Thank you, Doctor.
8 That's all I have.
9 COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions, Madam Chair.
11 COMMISSIONER SMITH: Mr. Purdy.
12 MR. PURDY: No questions.
13 COMMISSIONER SMITH: Mr. Richardson.
14 MR. RICHARDSON: No questions,
15 Madam Chair.
16 COMMISSIONER SMITH: Mr. Bruder.
17 MR. BRUDER: I have a few. Thanks.
18
19 CROSS-EXAMINATION
20
21 BY MR. BRUDER:
22 Sir, I wanted to ask first looking at yourQ
23 direct testimony, you identify a reasonable range for the
24 cost of equity of 10.8 percent to 11.8 percent. Now,
25 there are you deferring to Mr. Keen on identifying a
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2029 AVERA (X)
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1 point value wi thin that range that should be adopted in
2 this case?
3 A Yes, I am. That's how we decided to
4 develop the case, that I would do the technical capital
5 market analysis and Mr. Keen based on his knowledge of
6 the Company and his contact with investors and rating
7 agencies would determine what rate of return he felt was
8 necessary to support the financial integrity of the
9 Company, attract capital and meet comparable risk
10 standards.
11 Q So you're not sponsoring a specific
12 recommendation, just kind of a range of the 10.8 to 11.8;
13 is that right?
14 A That's correct. I think the number that
15 Mr. Keen has chosen is certainly wi thin the range and I
16 think it's reasonable, especially given the dramatic
17 developments in the capital markets over the last month
18 since the testimony was filed.
19 Q In your rebuttal testimony have you
20 presented an update or any updates to your cost of equity
21 studies?
22 A I did not update the studies themselves.
23 I do talk about the capital market developments and
24 identify how they unambiguously point to higher required
25 returns. I think if you correctly interpret the capital
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2030 AVERA (X)
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1 market evidence, that's the result you come up with.
2 Dr. Peseau was asked by Staff to do a calculation and he
3 actually did the calculation right, but he interpreted it
4 wrongly.
5 Q Wait a minute, I must interrupt you, sir.
6 I had one specific narrow question and I think you've
7 answered it.
8 A Sure.
9 Q Does your testimony provide -- your
10 testimony does provide a discussion of the current
11 financial situation and its capital cost implications,
12 but it's my understanding that, again, you didn't make
13 any specific adj ustments to your cost of capital results
14 or recommendation in response to those events, it remains
15 the range of 10.8 to 11.8?
16 A That's correct, and it's my understanding
17 that the Company has not changed their request, but I
18 think it's become much more conservative as events have
19 unfolded that a reasonable result come out of this case
20 if the Company is to be able to attract capital in this
.25
21 capital market environment.
22 Q One of the methods you use is what is
23 referred to as CAPM; is that correct?
24 A Sure.
Q Now, CAPM requires, as you know, that you
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2031 AVERA (X)
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17
1 select what is called a beta statistic. Could you
2 explain briefly in layman's terms the function of this
3 so-called beta statistic as it is employed in the CAPM
4 calculation?
5 A Yes. The capital asset pricing model in
6 theory says that in equilibrium, all assets are priced
7 along capital market lines and the relative return to
8 each asset based on the correlation of its return with
9 the market return and the beta is the measure of how an
10 indi vidual asset's return is related to the market
11 return, and a beta of one says the asset basically moves
12 in lockstep with the market. A beta of .5 says it moves
13 half as much as the market and since the market is
14 dri ving the risk, a beta of .5 would be less risky than
15 the market. A beta of two which says the asset tends to
16 mul tiply the effect of market move would be more risky.
18 number. When. we measure and estimate the beta that
Now, in theory, the beta is an unambiguous
19 investors may be using, we have to go to the beta
20 statistic. The way that is measured is generally a
21 statistical analysis called a regression that traces the
22 movements in the market compared to the movements in an
23 individual stock historically, usually over five years,
24 using a big market index like the New York Stock Exchange
25 Index, and the equation estimates a beta statistic which
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2032 AVERA (X)
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1 is the coefficient that relates movements in the market
2 on average to movements in the individual stock, so a
3 beta statistic of .5 says that historically that stock
4 has moved about half as much as the market has moved.
5 It's important to make certain statistical adj ustments to
6 the beta statistic because they have certain systematic
7 tendencies to converge back to the market mean of one and
8 people like Value Line that estimate betas make those
9 adjustments.
10 Q Value Line is the only source of the betas
11 you use, is it not?
12 A It is. Value Line for reasons I explain
13 in my testimony is the most widely-used advisory service.
14 It is accepted in the regulatory world and an accepted
15 authori ty in courts. Since it is widely used and since
16 it is accepted, since it's transparent, we know how they
17 calculate their betas, how they make their adjustments, I
18 think it is the appropriate and best available beta
19 measure.
20 Q In Exhibit 23, you use a beta of 0.88 and
21 in Exhibit 22 you use a beta of 0.79; is that correct?
22 I thought we had a question pending. Is the witness
23 checking the exhibits to answer yes or no?
24 A I thought I answered yes.
25 Q I'm sorry, then.
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2033 AVERA (X)
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1 COMMISSIONER SMITH: We didn't hear you.
2 MR. BRUDER: Sorry.
3 Q BY MR. BRUDER: Can you tell me, then,
4 what the beta would be for -- what would the latest beta
5 or betas be for this Company, sir?
6 A I haven't updated the betas for my two
7 proxy groups, the utility and the non-utility proxy
8 groups. Betas change over time, not usually very
9 rapidly. There has been a tendency for the utility betas
10 to trend down over time, because as the market has
11 adequately fallen, utilities tend to fall less than the
12 market.
13 Q Utilities tend to fall less than the
14 market and in terms of perceived risks, what does that
15 mean?
16 A That means when you do this statistical
17 regression, beta statistics, generally when the market
18 has moved more than a particular company group, it tends
19 to reduce the estimated beta.
20 Q If I am an investor and seeking wise
21 investments and I see the beta move as it has for this
22 enti ty and similar entities during the past, say, two
23 months, is it my perception that it is a better or a
24 worse investment?
25 A I don't think you would make a decision
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2034 AVERA (X)
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.
.
1 based only on the beta. The beta --
2 Q Sir, that isn't what I asked you. I asked
3 you if I were looking at the beta and I were going to
4 make a decision or I were influenced on the basis of the
5 beta, what would be the influence of the movement of a
6 beta that you have described?
7 A The influence would be to tell me that it
8 is likely that utilities will move less than the market,
9 so if the market goes up, these will not participate as
10 strongly. If the markets continue to go down, utilities
11 will not go down as much.
12 Q And everything else held equal, sir, that
13 makes to me as a reasonably prudent investor this Company
14 more attractive as an investment vehicle rather than
15 less; is that not correct?
16 A That's not correct, because it depends on
17 what the investor expects the market to do. The
18 investor expects --
19 Q What does the investor expect the market
20 to do given what's happened with the beta, sir?
21 A Well, I think many investors, like Warren
22 Buffett and Professor Siegel, expect the market to go up
23 dramatically and if that were the case, you would want to
24 have high beta stock so you would participate in that
25 increase.
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2035 AVERA (X)
Idaho Power Company
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.
1 Q And if I'm an investor who isn't quite as
2 sanguine as they, sir, how would I tend to go?
3 A Oh, I think your level of sanguini ty would
4 determine where you would want to be on the beta
5 continuum. If you're completely panicked, as many people
6 are today, you would go to government securities which as
7 of earlier this week were yielding zero.
8 Q Yes, and if I were perhaps 15 percent less
9 panicked than that, sir, I might very well choose Idaho
10 Power as a good investment vehicle given my less than
11 frantic perception; isn't that right?
12 A That's right, if you --
13 Q Okay.
14 A -- were offered enough extra return to
15 move you from government securities to the stock. You
16 would also look at the fact you could earn almost nine
17 percent on Idaho Power bonds and you would have to expect
18 enough extra return from the stock to forego the nine
19 percent relatively certain return for the unknown stock
20 return.
21 Q We have materials that we had hoped to
22 have you look at and, of course, that isn't possible
23 given the situation this morning; however, it is
24 suggested and I ask is a beta of something like 0.38.25 instead of O. 79 or 0.88 more correct as a representation
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2036 AVERA (X)
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1 of the present situation for this Company, sir?
2 A Oh, I don't think so. I think the best
3 available beta, the most recently available beta, for
4 IDACORP is in the publication that Mr. Conley and I were
5 talking about or, excuse me, Mr. Ward, and that beta is
6 .85. That's on page 2236 of Edition 11 of the Value
7 Line.
8 Q Do Exhibits 22 and 23 use a treasury risk
9 free rate of 4.6 percent?
10 A They do.
11 Q Is that yes?
12 A Yes, they do.
13 Q Okay.What's the risk free treasury rate
14 today, December 2008,sir?
15 A It's around three percent. Again, it has
16 dramatically fallen with the continued flight to safety
17 that we've experienced and the dramatic events of the
18 last two months, but especially the last two weeks.
19 Q The fact is it's a good bit under three
20 percent and that's for 10 years; is that right?
21 A The benchmark that I use is the 20-year.
22 I believe the 20-year is around three percent the last I
23 checked.
24 Q And money loaned for 20 years at three
25 percent, that's an extraordinary low return, is it?
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2037 AVERA (X)
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1 A That's right. That's money loaned to the
2 federal government who has the power to tax and the
3 printing presses. Unfortunately, loaning money to a
4 company like Idaho Power --
5 Q Sir, really, I'd appreciate it if you
6 would limit your answers to the scope of the question.
7 If we substitute this current treasury cost rate for the
8 cost rate that's used on Exhibits 22 and 23, how will
9 that affect your calculated cost of equity? It would
10 reduce it substantially, would it not?
11 A It would. That would be contrary to what
12 we observe going on in the world.
13 Q Sir, I'm going to ask you once again to
14 please limit your responses to my questions.
15 MS. Nordstrom: I'd like that he be able
16 to answer the questions that he's being posed in a full
17 and complete manner rather than just being cut off.
18
19
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: Well, if he wants to say
20 something further and amplify, of course, that's all
21 right, but I think that's for redirect. I think that
22 what the witness intends to do is to lose the scope and
23 the force of the answer with a lot of stuff that is not
24 al together relevant and I think to some degree confusing.
25 COMMISSIONER SMITH: Dr. Avera, please
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2038 AVERA (X)
Idaho Power Company
.1 listen carefully to the question and answer to the best
2 of your ability in a manner that you believe fully
3 responds, but not overdoing it into new areas or
4 extraneous material.
5 THE WITNESS: I will do that,
6 Madam Chair.
7 COMMISSIONER SMITH: Thank you.
8 MR. BRUDER: Thank you.
9 Q MR. BRUDER: Sir, I understand that
10 Exhibit 82, that's in your rebuttal, is an update of
.
.
11 Mr. Kahal, and Mr. Kahal is DOE's cost of capital
12 wi tness, that is an update to his DCF study; is that
13 correct?
14 A Yes.
15 Q I can't translate that.
16 A I said yes. The beeps were not my
17 extraneous answer.
18 MR. BRUDER: Okay.
19 COMMISSIONER SMITH: We thought you hung
20 up on us.
21 MR. BRUDER: I will not cross-examine
22 R2-D2.
23 COMMISSIONER SMITH: The answer was yes?
24 THE WITNESS: Yes.
25 COMMISSIONER SMITH: Thank you.
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2039
.
.
1 Q BY MR. BRUDER: I understand that this
2 update is based on one month of stock price data, is that
3 right, and that's November 2008?
4 A Yes.
5 Q Now, you updated the dividend yield, did
6 you also update the growth rate?
7 A No, I used the growth rate that Mr. Kahal
8 used.
9 Q I repeat, did you update the growth
10 rate?
11 A I did not. As explained in my rebuttal, I
12 was trying to show the effect of the dividend yield
13 change alone on his results.
14 Q So you changed, updated you call it, his
15 dividend yiel?, but you did not change or update his
16 growth rate?
17 A That is correct.
18 Q Okay. Are you aware that Mr. Kahal uses a
19 six-month average dividend yield for his DCF study?
20
21
A Yes, I am.
Q Now, what you show on Exhibit 82 is not
22 Mr. Kahal' s DCF methodology, rather it's a change in the
23 methodology under which you use one month of market data
24 instead of six months; is that correct?.25 A That is correct. I did that to show the
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2040 AVERA (X)
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1 effect of the more recent data and giving it -- to give
2 the example of how recent events would change the
3 inferences that Mr. Kahal drew.
4 Q It isn't your contention that Mr. Kahal
5 used six months in this case alone rather than that being
6 a standard approach, is it?
7 A Please repeat the question, Mr. Bruder.
8 Q Sure. Mr. Kahall when he does this kind
9 of study uses in almost every case or every case six
10 months of data rather than the one month that you
11 substituted here.
12 A Yes, I believe that to be the case.
13 Q And he's always used the six months in the
14 past Idaho Power Company cases; is that right?
15 A That is correct, and my purpose here was
16 to show that recent events have been very dramatic and I
17 did it by reference to his DCF, but I'm not saying that I
18 think while I have my own thoughts about what average
19 should be used, I'm not denying the fact that he
20 consistently uses six months of data.
21 Q And you didn't use an average, you used
22 one month; is that right?
23 A That's correct.
24 Q Okay. To take it further, averaging over
25 six months rather than using one month is a common
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2041 AVERA (X)
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1 practice among rate of return witnesses generally, my
2 point being and let me say it directly that what you've
3 done is taken the one month for the purpose of creating
4 this dramatic example; is that right?
5 A I would say that many rate of return
6 wi tnesses use six-month averages, many do not. I don't
7 even think the predominant use is six months. Some
8 regulatory agencies, like the Federal Energy Regulatory
9 Commission, has dictated a six-month average, but I think
10 different analysts use different periods for different
11 reasons and the ones that I used which was from Value
12 Line I articulate in my testimony.
13 Q Now, looking at page 52 of your rebuttal
14 testimony, tell me when you have it, please.
15 A I have it.
16 Q There you discuss Mr. Kahal' s inclusion of
17 enti ties called Black Hills and Hawaiian Electric in his
18 proxy group. Do you include those two companies in your
19 DCF proxy group?
20 A Yes.
21 Q So you aren't recommending that those two
22 companies be discarded from the proxy group inclusion for
23 DCF purposes; is that right?
24 A No, I'm not. I'm making the point that
25 Mr. Kahal is being inconsistent in his criteria.
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1 Q Let's talk briefly about comparable
2 earnings, page 5, line 19. You state that Value Line
3 well, I'll let you get to page 5, line 19.
4 A On my rebuttal, sir?
5 Q I'm sorry, yes, page 5, line 19 of your
6 rebuttal.
7 A I'm there, Mr. Bruder.
8 Q Okay. You state that Value Line is
9 forecasting a future 11.5 percent return on equity for
10 the electric utility industry; is that correct?
11 A Correct.
12 MR. BRUDER: Did he answer?
13 COMMISSIONER SMITH: I haven't heard an
14 answer.
15 MR. BRUDER: Okay.
16 MS. NORDSTROM: Dr. Avera, could you
17 repeat your answer if you answered?
18 THE WITNESS: My answer was yes.
19 MS. NORDSTROM: You're kind of cutting out
20 a little bit, so sometimes we're struggling, particularly
21 wi th those short answers.
22 THE WITNESS: Maybe that's why I avoid
23 them.
24 BY MR. BRUDER: I beg to differ, sir.Q
25 Now, that 11.5 percent is specifically a reference to
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2043 AVERA (X)
Idaho Power Company
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1 what is called an accounting return rather than a market
2 return; is that right?
3 A Yes, that is the return that the books and
4 records of the utili ties reflect.
5 Q And the accounting return is simply the
6 projected earnings divided by projected book value?
7 A That is correct. In the case of Value
8 Line, as I point out in my testimony, the book value is
9 year-end, though this is a slight lower number than the
10 normal--
11 COMMISSIONER SMITH: Dr. Avera, the court
12 reporter was not able to hear your last response. Could
13 you please repeat it?
14 THE WITNESS: Yes. The 11.5 percent is
15 return on book value. Now, for Value Line, as I mention
16 in my testimony, that's year-end book value. The normal
17 measure of return on equity is average book value, so the
18 number actually should be a little bit higher than
19 11.5.
20
21
COMMISSIONER SMITH: Thank you.
Q BY MR. BRUDER: Have you any sources for
22 this accounting return other than Value Line?
23 A No, this is from Value Line. Value Line
24 derives its historical data from the SEC filings of the
25 Company. It's projected data and the 2008 would be
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2044 AVERA (X)
Idaho Power Company
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1 proj ected based on its analysts' proj ections based on
2 what the companies have already reported in 2008 and
3 their expectation of what the fourth quarter will
4 provide.
5 Q Okay, when you put forward this 11.5
6 percent, that is for what you call "electric utilities as
7 a whole." Now, that's a reference to the entire universe
8 of these companies classified by Value Line as electric
9 utili ty companies and that includes companies like
10 Exelon, Entergy, FPL, Dominion, PSE&G Group, PP&L, and
11 those companies have extensive unregulated merchant plant
12 or commodities operations; is that not correct?
13 A Yes, some of those companies have
14 different operations. They are still classified as
15 electric utilities, much like Hawaiian Electric has
16 substantial non-utility operations, but for the purposes
17 of Value Line, they are viewed as electrics.
18 Q And so when Value Line reports this 11.5
19 percent anticipated return on equity, it's not just the
20 regulated side of the utility business, is it? It also
21 includes unregulated and, therefore, considerably riskier
22 operations such as commodities and merchant power; is
23 that correct?
24 A It includes whatever the companies have.
25 Some of the companies have operations that may be less
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Idaho Power Company
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1 risky. For example, Hawaiian Electric has a savings bank
2 that's extremely --
3 Q Sir, I'm going to ask you once again, if
4 you want to amplify, that's all right, but, please, on
5 redirect. It's a narrow question.
6 MS. NORDSTROM: Could he be allowed to
7 finish answering?
8 COMMISSIONER SMITH: Yeah, I think right
9 here, Mr. Bruder, we're going to allow Dr. Avera to
10 finish that response.
11 MR. BRUDER: Okay.
12 THE WITNESS: The bottom line, Mr. Bruder,
13 is you're correct, it includes all of the companies'
14 revenues, but you i re incorrect that they always would be
15 viewed by investors as more risky operations.
16 Q BY MR. BRUDER: I don't recall saying
17 that, but if I said it, I accept that it was incorrect.
18 What is Value Line's estimate of return on equity for
19 just regulated utility operations of those companies?
A Value Line doesn't report that as far as I
21 know.
22 Q So if we were looking for something that's
23 more in line with Idaho Power's situation because Idaho
24 Power doesn't have any unregulated merchant plant or.25 commodi ties operations, we'd be looking for a figure that
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1 Value Line just doesn't provide; is that right?
2 A That is correct. Now, in my comparable
3 earnings analysis, I did take proxy groups which have the
4 same risk as Idaho Power and took the Value Line return
5 on equity for that group, so I think that is a comparable
6 risk measure.
7 Q One final question. Since the beginning
8 of the current financial crisis, and I would date that to
9 this past September, has any credit rating agency
10 downgraded IPC?
11 A I don't believe so. Both Fitch and
12 Moody's has Idaho Power on a negative outlook, but I
13 think that was before the subj ect to check, I could
14 check that, but I believe that to be the case.
15 MR. BRUDER: Okay, I'd just ask for one
16 minute to confer with my expert and then we'll wrap this
17 up.
18 (Pause in proceedings.)
19 MR. BRUDER: Nothing further. Thank you
20 very much.
21 COMMISSIONER SMITH: Thank you, Mr.
22 Bruder. Mr. Boehm.
23 MR. BOEHM: No questions, Your Honor.
24 COMMISSIONER SMITH: Mr. Howell.
25 MR. HOWELL: Thank you, Madam Chairman.
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1 CROSS-EXAMINATION
2
3 BY MR. HOWELL:
4 Q I just wanted to clear up the question of
5 Idaho Power's or IDACORP' s current beta as reflected in
6 the most recent Value Line survey. Dr. Avera, were you
7 present when Dr. Peseau was on the stand and the Staff
8 presented him with what you cannot see but what was
9 identified as Staff Exhibit 156?
10 A Yes, I heard that conversation.
11 Q Would you have any reason to disbelieve
12 his reading of the beta ranking from the December 19
13 Value Line that recognized IDACORP's beta as 0.80?
14 A No. If that is what the document says,
15 Value Line does update these continuously, so that would
16 be a reading after the sheet Value Line that I cited on
17 November 7.
18 MR. HOWELL: Thank you, Doctor. I have no
19 further questions.
20 COMMISSIONER SMITH: Do we have any
21 questions from the Commissioners?
22 COMMISSIONER KEMPTON: No.
23 COMMISSIONER REDFORD: No.
24 COMMISSIONER SMITH: Seeing none,
25 Ms. Nordstrom, do you have redirect?
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Idaho Power Company
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1 MS. NORDSTROM: I do. Thank you.
2
3 REDIRECT EXAMINATION
4
5 BY MS. NORDSTROM:
6 Q Dr. Avera, an earlier question posed by
7 Mr. Ward was in reference to the return numbers in Value
8 Line for certain companies in the 16 Western utilities
9 proxy group. Were those allowed rates of return or
10 actual rates of return?
11 A Those were actual rates of return.
12 Q And do you draw a distinction based on
13 that?
14 A Well, I think in many cases the allowed
15 rate of return is significantly higher, but for a variety
16 of reasons, the company has not been able to achieve that
17 allowed return.
18 Q Mr. Bruder asked you some questions about
19 attracti veness to investors in regards to some of the
20 calculations. Why would Idaho Power not be considered
21 more attractive to these investors?
22 A I think Idaho Power has many risks.
23 Because of its large capital program, because of its
24 exposure to variations in streamflows, because of its
25 exposure to the wholesale power markets, the rating
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Idaho Power Company
1 agencies, for example, have discussed these risks and.2 have over a period of time reduced the ratings of Idaho
3 Power, and currently two of the maj or rating agencies
4 have a negative outlook on Idaho Power, so Idaho Power is
5 a relatively risky utility.
6 The Idaho Exhibit 88 shows that there are
7 many companies above Idaho Power and few below and many
8 of those that are below are the junk bond ratings that
9 are having extreme difficulty raising capital in this
10 market, so from an investor's perspective, Idaho Power is
11 a risky utility and they have spoken with their
12 willingness to provide debt capital to triple B utilities.13 at rates of greater than eight percent and at times in
14 the last two months more than nine percent, so it is
15 likely that the equity returns would be well north of
16 nine.
17 In my rebuttal testimony, I cite this
18 principle that as, and it's an empirically proven fact,
19 that as interest rates on utility securities go up, the
20 cost of equity goes up about half as much, so the
21 required return on utility bonds of Idaho Power's risk,
22 triple B, have gone up about 200 basis points since the
23 summer and that would suggest that the required return on
24 equi ty has gone up at least 100 basis points..25 Q There were discussions of benchmark,
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1 particularly the treasuries and whether the -- well, the.2 federal government's ability to borrow. Can the federal
3 government borrow more cheaply than a company like Idaho
4 Power?
5 A Absolutely, and the spread has extremely
6 widened. Dr. Peseau was presented with Staff Exhibit 156
7 where there's a spread between government at 3.09 and
8 triple B' s at 4.46 percent. If you go to Dr. Peseau' s
9 testimony, he presents what it was in 2007 and the spread
10 was only 1.44 percent, so that spread has more than
11 doubled in the last year. Well, that says that investors
12 require a whole lot more return to move from treasuries.13 where the government will almost certainly payoff
14 because they have the power to tax and they can print
15 money to move from where you know you're going to get
16 your money, the risk free rate, to an asset where there
17 is some chance you won't get money, a triple B bond. The
18 amount they required extra last year was about
19 one-and-a-half percent. This year it's about
20 four-and-a-half percent. That tells us that investors
21 are fleeing to the safety and they're willing to accept
22 almost zero interest on the short end to avoid the risk
23 of owning a corporate security.
24 MS. NORDSTROM: That's all I have. Thank.25 you.
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22
23
24.25
1 COMMISSIONER SMITH: Thank you,
2 Ms. Nordstrom, and thank you for your help, Dr. Avera.
3 We appreciate your telephonic attendance.
4 THE WITNESS: Thank you, Madam Chair. I
5 hope everyone has a wonderful Christmas.
6 COMMISSIONER SMITH: Oh, thank you. It's
7 now time to take our lunch hour, from which we will
8 return at 1: 15 and so we're done for the morning.
9 (Lunch recess.)
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