20090108Vol IX [technical hearing] pgs 2053-2475.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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) CASE NO. IPC-E-08-10
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) Idaho Public Utilties Commission
) Office of the SecretaryRECEIVED
JAN - 8 2009
Boise, Idaho
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 IX - Pages 2053 - 2475
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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:
Neil Price, 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-and-
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 Technology,
Inc. :
For The Kroger Company:
(Of Record)
CSB REPORTING
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APPEARANCES
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1 A P PEA RAN C E S (Continued)
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3 For the Community Action
Partnership of Idaho:
Brad M. Purdy, Esq.
Attorney at Law
2019 North 17th Street
Boise, Idaho 83702
Mr. Ken Miller
5400 West Franklin
Boise, Idaho 83705
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For Snake River Alliance:
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CSB REPORTING
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APPEARANCES
1 I N D E X.2
3 WITNESS EXAINATION BY PAGE
4 Matthew I.Kahal Mr.Bruder (Direct)2053
(Department of Energy)Prefiled Direct Testimony 2057
5 Mr.Nordstrom (Cross)2138
Mr.Bruder (Redirect)2141
6
Steven R.Keen Ms.Nordstrom (Direct)2145
7 (Idaho Power Company)Prefiled Direct Testimony 2147
Prefiled Rebuttal Testimony 2189
8 Mr.Bruder (Cross)2208
Mr.Richardson (Cross)2215
9 Commissioner Kempton 2218
Commissioner Redford 2222
10 Ms.Nordstrom (Redirect)2224
Commissioner Redford 2230
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Terri Carlock Mr.Price (Direct)2231
12 (Staff)Prefiled Direct Testimony 2233
Mr.Ward (Cross)2249.13 Ms.Nordstrom (Cross)2253
14 Lori Smith Ms.Nordstrom (Direct)2256
(Idaho Power Company)Prefiled Direct Testimony 2259
15 Prefiled Rebuttal Testimony 2290
Mr.Ward (Cross)2351
16 Mr.Price (Cross)2359
Commissioner Redford 2374
17 Commissioner Smith 2377
Ms.Nordstrom (Redirect)2378
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Steven R.Keen Ms.Nordstrom (Direct-Ct i d)2384
19 (Idaho Power Company)Mr.Price (Cross)2386
20 Don Reading Mr.Richardson (Direct)2388
(Idaho Power Company)Prefiled Direct Testimony 2390
21 Prefiled Rebuttal Testimony 2441
Mr.Richardson (Direct-Ct' d) 2448
22 Mr.Walker (Cross)2450
Commissioner Kempton 2457
23 Commissioner Redford 2460
Commissioner Smith 2466
24 Commissioner Redford 2470
Mr.Richardson (Redirect)2472.25
CSB REPORTING
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INDEX
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1 EXHIBITS
PAGE
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3 NUMBER DESCRIPTION
4 FOR I DAHO POWER COMPANY:
5 27 - Idaho Power, Composite Cost of
Capital Premarked
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28 - Idaho Power, Effective Embedded
Cost of Long-Term Debt
Premarked
8 29 - Idaho Power, Other Operating
Revenues
Premarked
9 30 - Idaho Power, Deductions From Premarked
10 Operation & Maintenance Expenses
11 31 - Idaho Power, Summary of Adjustments Premarked
to 2007 Operating Expenses
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32 - Idaho Power , Additional Ratebase &
Expense Adj ustments
Premarked
14 33 - Idaho Power, Methodology Summary,
2008 Test Year
Premarked
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34 - Methodology Manual, 2008 Rate Case Premarked
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83 - IPCo, Other Operating & Maintenance Premarked
17 excluding Net Power Supply Expenses
& Energy Efficiency
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84 - IPCo, Other Operating & Maintenance Premarked
19 excluding Net Power Supply Expenses
& Energy Efficiency
20 85 - Idaho Power Customer Growth Premarked21 Compared- to Regional Peer Utilities
22 86 - Idaho Power O&M Growth Compared Premarkedto Regional Peer Utili ties
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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
Premarked
8 201 - Qualifications of Don C. Reading Premarked
CSB REPORTING
Wilder, Idaho 83676
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
4 FOR THE STAFF:
5 128 - Industry Leverage Beginning to
Rise
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7 FOR THE INDUSTRIAL CUSTOMERS OF IDAHO POWER:
9 202 - Marginal Generation Capacity
Costs
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203 - Marginal Power Supply Costs
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204 - Power Supply Expenses Normalized
Including Known & Measurable
Power Supply Adj ustments
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205 - 3CP/12CP as Filed by Idaho Power,
3CP/12CP Using 2007 CP
15 206 - 3CP/12CP as Filed by Idaho Power,
13CP /12CP with Full MC Weighting
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207 - 3CP /12CP as Filed by Idaho Power,
Base Case; Hydro Set at .25
Energy / . 75 Demand
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208 - 3CP/12CP as Filed by Idaho Power,
3CP /12CP with 2007 CP, Full MC
Weighting, Hydro at .25% Energy /
.75% Demand20
21 209 - Project'Test Year Compared to
Six Months Actual
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FOR KROGER COMPANY:
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401 - Kevin C. Higgins, Vitae
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EXHIBITS
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1 E X H I BIT S (Continued)
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3 NUMBER DESCRIPTION PAGE
4 FOR U. S. DEPARTMENT OF ENERGY:
5 601 - Rate of Return Summary Premarked
6 602 - Trends in Capital Costs Premarked
7 603 - Value Line Risk Indicators for
the Western Proxy Companies
Premarked
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604 - DCF Summary for Full 13-Company Premarked
9 West Region Proxy Group
10 605 - Dr. Avera's DCF Estimates Based Premarked
on Al ternati ve Growth Rate Sources
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606 - Historical/Projected Earned Return Premarked12 on Equity West Region Electric
Utility Companies
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612 - Idaho Business Review, Idacorp
earnings rise in 3rd quarter
Identified 2211
15 613 - IDA - IDACORP, Inc. - Google
Finance Identified 2211
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CSB REPORTING
Wilder, Idaho 83676
EXHIBITS
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1 BOISE, IDAHO, THURSDAY, DECEMBER 18, 2008, 1:15 P. M.
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4 COMMISSIONER SMITH: Mr. Bruder, we'll go
5 back on the record and we're ready for your witness.
6 MR. BRUDER: Thank you. The Department
7 calls Mr. Matthew Kahal.
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9 MATTHEW I. KAHAL,
10 produced as a witness at the instance of the U. S.
11 Department of Energy, having been first duly sworn, was
12 examined and testified as follows:
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14 DIRECT EXAMINATION
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16 BY MR. BRUDER:
17 Q Would you state your name and address for
18 the record?
19 A Yes, my name is Matthew I. Kahal. My
20 address is 5565 Sterrett Place, Suite 310, Columbia,
21 Maryland 21044.
22 Q And by whom and in what capacity are you
23 employed?
24 A I'm employed as a consultant to Exeter
25 Associates retained by the United States Department of
CSB REPORTING
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2053 KAHAL (Di)
Department of Energy
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1 Energy.
2 Q I show you a document now that is titled
3 Direct Testimony of Matthew I. Kahal. This consists of
4 43 pages of text and 14 pages of exhibits. The exhibits
5 are numbered DOE Exhibits 601 through 606 and these
6 materials indicate that you prefiled them on October 24
7 of this year. Are you that same Mr. Kahal who did in
8 fact file these materials?
9 A Yes.
10 Q And was all of this material prepared by
11 you or under your direction?
12 A Yes, it was.
13 Q And, Mr. Kahal, do you have at this time
14 any additions or corrections to this prefiled testimony
15 and these exhibits?
16 A I do. I have a couple of minor
17 typographical' corrections. On page 41 at line 23,
18 there's a reference to a range of "9.4 to 10.4." That
19 should be "9.6 to 10.6," and on page 42 at line 13, I
20 misspelled the word "recommendation." There should be an
21 "0" in that word. These are typographical corrections.
22 They don't change my recommendation or anything like
23 that.
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COMMISSIONER SMITH: I missed the second
one.
CSB REPORTING
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2054 KAHAL (Di)
Department of Energy
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1 THE WITNESS: The second one is on page 42
2 at line 13. It's just a misspelling of the word
3 "recommendation."
4 COMMISSIONER SMITH: I see it. Thank you.
5 Q BY MR. BRUDER: All right, Mr. Kahal, if I
6 were to ask you --
7 COMMISSIONER SMITH: Mr. Bruder, there
8 seems to be some issue here. We'll be at ease.
9 (Off the record discussion.)
10 COMMISSIONER SMITH: Mr. Bruder, we're
11 back on the record.
12 MR. BRUDER: I was going to ask if we
13 could go off the record. I want to get one thing
14 clear.
15 COMMISSIONER SMITH: Okay, we'll be at
16 ease.
17 MR. BRUDER: Okay.
(Off the record discussion.)
COMMISSIONER SMITH: Now we're back with
20 Mr. Bruder.
21 Q BY MR. BRUDER: If I were to ask you all
22 of the same questions that are set out in the testimony,
23 would all of your responses be the same as those that are
24 shown in those materials?
25 A Yes, they would.
CSB REPORTING
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2055 KAHAL (Di)
Department of Energy
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1 MR. BRUDER: Okay, Madam Chairman, I ask
2 that these materials be spread upon the record as if they
3 had been put forward from the stand today and I ask that
4 the exhibits be marked DOE Exhibit 601 through 606 for
5 identification and I do tender this witness for
6 cross-examination.
7 COMMISSIONER SMITH: Seeing no obj ection,
8 we will spread the prefiled testimony upon the record as
9 if read and identify Exhibits 601 to 606.
10 (The following prefiled direct testimony
11 of Mr. Matthew Kahal is spread upon the record.)
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CSB REPORTING
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2056 KAHAL (Di)
Department of Energy
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1 I . QUALIFICATIONS
2 Q.PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A.My name is Matthew I. Kahal. I am employed as an
4 independent consultant retained in this matter by the
5 firm of Exeter Associates, Inc. My business address is
6 5565 Sterrett Place, Suite 310, Columbia, Maryland
7 21044.
8 Q.PLEASE STATE YOUR EDUCATIONAL BACKGROUND.
9 A.I hold B.A. and M.A. degrees in economics from the
10 University of Maryland and have completed all course work
11 and qualifying examination requirements for the Ph. D.
12 degree in economics. My areas of academic concentration
13 included industrial organization, economic development
14 and econometrics.
15 Q.WHAT IS YOUR PROFESSIONAL BACKGROUND?
A.I have been employed in the area of energy, utility
17 and telecommunications consulting for the past 30 years
18 working on a wide range of topics. Most of my work has
19 focused on electric utility integrated planning, plant
20 licensing, environmental issues, mergers and financial
21 issues. I was a co-founder of Exeter Associates, and from
22 1981 to 2001 I was employed at Exeter Associates as a
23 Senior Economist and Principal. During that time, I took
24 the lead role at Exeter in performing cost of capital and
25 financial studies. In recent years, the focus of much of
2057 Matthew I. Kahal, Di 1
Department of Energy
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1 my professional work has shifted to electric utility
2 restructuring and competition.
3 Prior to entering consulting, I served on the
4 Economics Department faculties at the University of
5 Maryland (College Park) and Montgomery College teaching
6 courses on economic principles, development economics and
7 business.
8 Q.HAVE YOU PREVIOUSLY TESTIFIED AS AN EXPERT WITNESS
9 BEFORE UTILITY REGULATORY COMMISSIONS?
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2058 Matthew I. Kahal, Di 1a
Department of Energy
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1 A. Yes. I have testified before approximately two-dozen
2 state and federal utility commissions in more than 300
3 separate regulatory cases. My testimony has addressed a
4 variety of subjects including fair rate of return,
5 resource planning, financial assessments, load
6 forecasting, competi ti ve restructuring, rate design,
7 purchase power contracts, merger economics and other
8 regulatory policy issues. These cases have involved
9 electric, gas, water and telephone utilities. In 1989, I
10 testified before the U. S. House of Representatives,
11 Committee on Ways and Means, on proposed federal tax
12 legislation affecting utili ties.
13 Q. WHAT PROFESSIONAL ACTIVITIES HAVE YOU ENGAGED IN
14 SINCE LEAVING EXETER AS A PRINCIPAL IN 2001?
15 A.Since 2001, I have worked on a variety of consulting
16 assignments pertaining to electric restructuring,
17 purchase power contracts, environmental controls, cost of
18 capi tal and other regulatory issues. Current and recent
19 clients include the U. S. Department of Justice, U. S.
20 Air Force, U. S. Department of Energy, the Federal Energy
21 Regulatory Commission, Connecticut Attorney General,
22 Pennsylvania Office of Consumer Advocate, New Jersey
23 Division of Counsel, Rhode Island Division of Public
24 Utilities, Louisiana Public Service Commission, Arkansas
25 Public Service Commission, Maryland Department of Natural
2059 Matthew I. Kahal, Di 2
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1 Resources and Energy Administration, and Maine Office of
2 the Public Advocate.
3 Q.HAVE YOU PREVIOUSLY TESTIFIED IN MATTERS BEFORE THIS
4 COMMISSION?
5 A.Yes. I have testified on cost of capital before the
6 Idaho Public Utilities Commission on previous occasions,
7 including Idaho Power Company's (" IPC" or "the Company")
8 base rate case in 1994 (IPC-E-94-5) and in last year's
9 case (IPC-E-07 -8) .
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2060 Matthew I. Kahal, Di 2a
Department of Energy
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1 II . OVERVIEW
2 A.Sumary of Recommendations
3 Q.WHAT is THE PURPOSE OF YOUR TESTIMONY IN THIS
4 PROCEEDING?
5 A.I have been asked by the U. S. Department of Energy
6 ("DOE") to develop a recommendation concerning the fair
7 rate of return on the jurisdictional electric utility
8 rate base of Idaho Power Company (" IPC" or "the
9 Company"). IPC is the electric utility subsidiary of
10 IdaCorp, Inc., and it accounts for the vast majority of
11 IdaCorp' s invested capital and operations. My work in
12 this case includes both a review of the Company's
13 proposal concerning rate of return and the preparation of
14 an independent study of the cost of common equity.
15 Q.WHAT is THE COMPANY'S RATE OF RETURN PROPOSAL IN
16 THIS CASE?
17 A.As presented on Exhibit 27 sponsored by Mr. Steven
18 Keen, the Company proposes an overall rate of return of
19 8.55 percent, based on the projected capitalization and
20 debt costs at December 31, 2008. The capital structure
21 proposed in this case includes 50. 7 percent common equity
22 and 49.3 percent long-term debt, with no preferred stock
23 or short-term debt included in the capital structure. In
24 developing the requested overall rate of return Mr. Keen
25 selects a return on common equity of 11.25 percent.
2061 Matthew I. Kahal, Di 3
Department of Energy
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1 IPC's outside cost of capital witness, Dr. William Avera,
2 recommends a return on common equity range of 10.8 to
3 11.8 percent.
4 Q.WHAT is MR. KEEN'S APPROACH TO CAPITAL STRUCTURE?
5 A.IPC is a wholly-owned subsidiary of IdaCorp, Inc., a
6 utili ty holding company, and is principally engaged in
7 electric utility retail operations in Idaho, with a small
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2062 Matthew I. Kahal, Di 3a
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1 amount of retail utility operations in Oregon. Mr. Keen
2 bases the ratemaking capital structure on the proj ected
3 Idaho Power Company capital structure at December 31,
4 2008. As of this date, IPC expects to have no preferred
5 stock outstanding, and Mr. Keen includes the effects of
6 expected long-term debt issuances.
7 Mr. Keen also provides an estimate of the
8 actual embedded cost of debt, inclusive of the
9 prospecti ve cost rates for the Company's variable rate
10 debt and its proj ected new debt issuances. This produces
11 an embedded cost of debt of 5.927 percent.
12 Q.HOW DOES MR. KEEN'S RATE OF RETURN REQUEST COMPARE
13 WITH THE REQUEST IN LAST YEAR'S RATE CASE (CASE NO.
14 IPC-E-07-08) ?
15 A.In last year's case, Mr. Keen also proposed a
16 proj ected "50/50" capital structure and a proj ected
17 year-end cost of debt. However, in this case he has
18 lowered the requested return on common equity from 11.5
19 percent to 11.25 percent. In addition, the cost of debt
20 in this case has risen from 5.59 percent to 5.93 percent.
21 The lower return on equity request follows the reduction
22 in the range recommended by Dr. Avera, as compared to his
23 testimony last year.
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Q.WHAT IS YOUR RECOMMENDATION AT THIS TIME ON RATE OF
RETURN?
2063 Matthew I. Kahal, Di 4
Department of Energy
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1 A. As presented on my Exhibit No. 601, at this time I
2 am recommending a return on the IPC jurisdictional rate
3 base of 8.18 percent, which includes a 10.5 percent
4 return on common equity. The 10.5 percent figure is at
5 the high end of my range of evidence. Depending on the
6 Commission's treatment of certain ratemaking
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2064 Matthew I. Kahal, Di 4a
Department of Energy
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1 policy issues (such as the Power Clause Adj ustment)
2 raised by the Company as maj or risk factors, the
3 Commission should consider a range of 10.25 to 10.5.
4 The 10.5 percent upper end figure is based
5 primarily upon discounted cash flow (DCF) evidence using
6 a proxy group of electric utility companies operating in
7 the West Region of the U. S. I also present DCF evidence
8 using a subset of Dr. Avera's proxy companies, i. e. ,
9 those non-West Region companies in his group that operate
10 as integrated, fully-regulated utilities. In addition, I
11 have reviewed and considered Dr. Avera's evidence using
12 the Capital Asset Pricing Model (CAPM), although I find
13 the CAPM to be much less useful than the DCF studies.
14 Finally, I compare my DCF results to "comparable
15 earnings" evidence, although this is not a market cost of
16 equity estimation method. The results of a comparable
17 earnings analysis, while not the basis of my position in
18 this case, do not support a result exceeding 10.5
19 percent. The 10.5 percent is somewhat higher than my DCF
20 midpoint results, providing IPC with a premium over the
21 "baseline" proxy group cost of equity estimate. As
22 mentioned above and discussed in Section V of my
23 testimony, the 10.5 percent is an upper end
24 recommendation before consideration of certain proposed
25 regulatory policy changes.
2065 Matthew I. Kahal, Di 5
Department of Energy
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1 In formulating my overall rate of return
2 recommendation, I have accepted the Company's proposed
3 December 31, 2008 capital structure and embedded cost of
4 debt, subj ect to possible updating. This capital
5 structure is nearly identical to that used in last year's
6 case and provides IPC with a slightly thicker equity
7 ratio than approved by the Commission in the 2004 rate
8 case. These percentages appear to be consistent with
9 IPC's financial objectives.
10 Q.WHAT RATE OF RETURN DID THE COMMISSION APPROVE IN
11 THE LAST FULLY-LITIGATED RATE CASE?
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2066 Matthew I. Kahal, Di 5a
Department of Energy
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1 A.In IPC' s last fully-litigated case, decided in 2004
2 (Case No. IPC-E-03-13, May 25, 2004), the Commission set
3 the Company's rate of return on equity (ROE) at 10.25
4 percent, in conjunction with a common equity ratio of 46
5 percent. In that rate order, the Commission concluded
6 that the authorized 10.25 percent return on equity
7 appropriately reflected the Company's business risks.
8 The Commission's return on equity quantification in that
9 Order relied primarily on DCF and comparable earnings
10 evidence.(Order, page 38) Since that case, the
11 Company's rate case filings have been resolved by
12 settlement agreement without an explicit cost of equity
13 ruling.
Q. WHAT RETURN ON EQUITY DID YOU RECOMMEND IN THE
15 YEAR'S RATE CASE FOR IPC?
16 A.In last year's case, I recommended 10.25 percent,
17 consistent with the Commission's ruling in the 2004 rate
18 case. This recommendation was fully supported by the
19 cost of capital evidence at that time. Although the cost
20 of capital data in this case have not changed
21 substantially, I believe that the difficulties in
22 financial markets (along with IPC' s financial position)
23 may warrant a, moderately higher return than I recommend
24 in last year's case. At the same time, the Commission
25 should consider possible regulatory changes that mitigate
2067 Matthew I. Kahal, Di 6
Department of Energy
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1 the Company's risk.
2 Q.WHAT is THE ASSESSMENT OF IPC BY THE RATING
3 AGENCIES?
4 A.As summarized in Mr. Keen's testimony, all three
5 major credit rating agencies rate IPC medium to high
6 triple B, low single A, with the low single A applicable
7 only to the Company's secured debt. The recent reports
8 from the three major credit rating agencies (Standard &
9 Poors, Moody's and Fi tchRatings) were provided as part of
10 Mr. Keen's and Dr. Avera's workpapers, and all three
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2068 Matthew I. Kahal, Di 6a
Department of Energy
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1 organizations provide generally similar business risk
2 assessments. For example, Fi tchRatings notes as "Key
3 Credi t Strengths" the PCA recovery mechanism, IPC' s
4 favorable rates and strong growth prospects.(July 9,
5 2007) Standard & Poors identifies the Company's
6 strengths as being "a strong power cost adj ustment (PCA)
7 mechanism," supportive regulation, low-cost generation
8 and the absence of unregulated business.(February 1,
9 2008) Moody's refers to IPC' s "generally low business
10 risk profile", reasonably supportive regulatory treatment
11 and the Company's low costs of supply as positive for
12 ratings.(June 4, 2008)
13 Similarly, each of the three credit rating
14 agencies mentions the same negative factors. The
15 principal rating concerns include IPC' s large
16 construction program (including the risks of rate
17 disallowances), the risk of adverse hydrologic conditions
18 and weak near-term financial metrics. S&P lowered its
19 IdaCorp and IPC credit ratings by one notch in January
20 2008 (though it changed its outlook from "negative" to
21 "stable") due primarily to the perceived weakening credit
22 of metrics.
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Q.WHAT DO YOU CONCLUDE?
A.Based on my review of the information submitted in
this case, including the recent credit rating reports, I
2069 Matthew I. Kahal, Di 7
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1 conclude that IPC is an approximately average risk
2 electric utility. Thus, the West Region group of
3 vertically-integrated electric companies provide a
4 generally reasonable risk proxy for IPC.
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2070 Matthew I. Kahal, Di 7a
Department of Energy
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1 B.Capi tal Cost Trends
2 Q.HAVE YOU REVIEWED THE TRENDS IN MARKET CAPITAL COSTS
3 OVER THE PAST DECADE?
4 A.Yes. My Exhibit No. 602 shows capital cost
5 indicators on an annual basis since 1992 and on a monthly
6 basis during January 2002 to September 2008. The
7 indicators include inflation (as measured by the annual
8 change in the Consumer Price Index), short-term Treasury
9 yields, ten-year Treasury yields and single A-rated
10 long-term utility bond yields (per Moody's) .
11 This schedule shows that despite year-to-year
12 fluctuations there has been a downward trend in capital
13 costs over this time period, at least for long-term
14 securi ties. Short-term interest rates tend to be
15 governed by Federal Reserve Board (Fed) policy, and up
16 until about a year ago the Fed had been "tightening"
17 (i. e., raising short-term rates) in response to a
18 strengthening U. S. economy. In response to a slowing
19 U. S. economy and distress in the housing market the Fed
20 has reversed this trend and has reduced short-term
21 interest rates. As measured by utility bond yields, it
22 appears that capital costs "bottomed out" in mid-2005,
23 with single A utility bond yields reaching a low point in
24 the mid 5 percent range. Long-term interest rates
25 remained relatively low through most of 2006 (i.e.,
2071 Matthew I. Kahal, Di 8
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1 long-term utility bond yields at approximately 6
2 percent), and this has continued since then. Long-term
3 rates can move from month-to-month but the underlying
4 trend has been relatively stable. Single A utility bond
5 yields generally have remained in the 6.0 to 6.5 percent
6 range, with Ten-Year Treasury yields moving downward in
7 2008 to the 3.7 to 4.0 percent range. The precipitous
8 decline this year in Treasury security yields reflects
9 weakness in the U. S. economy and the "flight to quality"
10 effect which takes hold during periods of economic
11 distress.
12
2072 Matthew I. Kahal, Di 8a
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1 In recent months, financial markets distress
2 and equity market volatility has increased drastically,
3 wi th credit markets beginning in late September freezing
4 up. This is a serious economic crisis that has required
5 historical remedial action by U. S. and foreign
6 governments. As of this writing, it is difficult to
7 predict when normal conditions, reflecting underlying
8 business fundamentals, will return to financial markets.
9 Q.ACCORDING TO EXHIBIT NO. 602, THERE WAS AN UPWARD
10 MOVEMENT IN INFLATION IN THE PAST YEAR. WHAT ACCOUNTS
11 FOR THIS CHANGE?
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A.The upward movement in inflation has been in
response to price spikes for energy and, to some degree,
increased food prices. However, the underlying "core"
15 inflation (excluding the volatile fuel and food sectors)
16 remains relatively stable. For example, the long-term
17 "consensus" forecast of the GDP Deflator (Blue Chip
18 Economic Indicators, October 10, 2008) is 2.1 to 2.2
19 percent annually. The favorable "core" inflation outlook
20 is based on strong productivity growth in the U.S.
21 economy, the expansion of global competition which tends
22 to hold down increases in U. S. product prices and Fed
23 monetary policy that over time emphasizes inflation
24 control.
25 Q.YOUR EXHIBIT NO. 602 PROVIDES DATA ON LONG-TERM
2073 Matthew I. Kahal, Di 9
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1 INTEREST RATES. IS THIS INDICATIVE OF COMMON EQUITY COST
2 RATES?
3 A.At least in a general sense, I believe it is. The
4 forces over time that lead to lower yields on long-term
5 debt also favorably affect the cost of equity, although I
6 would acknowledge that equity and debt cost rates do not
7 necessarily move together in
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2074 Matthew I. Kahal, Di 9a
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1 lock step. The favorable trends over time in long-term
2 debt cost rates are also likely to affect IPC' s equity
3 cost rate for providing electric service.
4 There is another force at work that further
5 contributes to a reduced cost rate for equity -- federal
6 tax policy. In mid-2003, Congress enacted legislation
7 granting favorable income tax treatment for dividend
8 payments and capital gains.(Legislation extending this
9 favorable tax treatment was enacted by Congress last
10 year.) Lower taxes on returns to equity investments mean
11 that investors are willing (or should be willing) to
12 accept lower returns for holding common stocks (such as
13 those of electric and other utilities), particularly as
14 compared with bonds, which do not enj oy this benefit.
15 The DCF method, which uses relatively current market
16 data, can fully capture this effect. Other methods, such
17 as historical risk premium method (as used by Dr. Avera),
18 may not be able to do so.
19 Q.AT THIS TIME, THE U. S. AND GLOBAL FINANCIAL MARKETS
20 HAVE BEEN SEVERELY DISTRESSED, DESCRIBED BY MANY
21 OBSERVERS AS A "CRISIS." HAVE YOU DIRECTLY INCORPORATED
22 THIS CRISIS INTO YOUR RECOMMENDAITON?
23 A.No, I have not. My cost of equity evidence is based
24 on market data from the six months ending September 2008,
25 largely a period of financial weakness and stress but not
2075 Matthew I. Kahal, Di 10
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1 financial crisis. The purpose of this proceeding is to
2 set permanent rates for IPC, and it would not be proper
3 to set fair rate of return based on financial crisis
4 condi tions, which likely will be temporary. Moreover,
5 the standard models (such as DCF and CAPM) normally
6 employed for estimating the utility cost of capital
7 cannot meaningfully be applied to crisis conditions.
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2076 Matthew I. Kahal, Di lOa
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1 C.Cost of Equity Sumry
2 Q.HOW DID DR. AVERA OBTAIN HIS RECOMMENDED COST OF
3 EQUITY RANGE?
4 Dr. Avera emphasized two cost of capitalA.
5 methodologies, the DCF and the CAPM, and he also employed
6 comparable earnings evidence, a method which does not
7 directly measure the cost of equity. He reports the
8 following results:
9
10 Dr. Avera's ROE Summary
11 1.11. 0 - 12.6%DCF
12 10.2 - 11.9%2.CAPM
13 Comparable Earnings 11.1%3.
14 Flotation Cost Adder 0.0%4.
15 Source: Avera, page 73
16
17 Dr. Avera concludes that this evidence supports a "bare
18 bones" cost of equity range of 10.8 to 11.8 percent based
19 on these methods. While he does not propose a specific
20 allowance for flotation expense, he suggests this
21 potential cost should be considered in selecting an
22 allowed return on equity wi thin this range.
23 WHAT ARE YOUR COST OF EQUITY RESULTS?Q.
24 As mentioned earlier, my recommendation (beforeA.
25 considering the need for an IPC risk premium) is based
2077 Matthew I. Kahal, Di 11
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1 primarily on the DCF evidence. I have applied the DCF
2 model to a broad proxy group of West Region electric
3 utility companies. This group is very similar to the
4 proxy group used by Dr. Avera in the 2004 rate case and
5 in a 2006 IPC rate case before the Federal Energy
6 Regulatory Commission (" FERC"), as indicated in response
7 to DOE I-19. My full group DCF analysis produces a range
8 of 9.9 to 10.4 percent with a midpoint of 10.2
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2078 Matthew I. Kahal, Di 11a
Department of Energy
1 percent. Using a subset of that group (i. e., excluding.2 California electrics and two other companies), the range
3 becomes 9.6 to 10.6 percent, with a midpoint of about
4 10.1 percent. Dr. Avera's own DCF evidence, based on a
5 subset of his industry group, i. e., just those integrated
6 electric utilities operating in "non-restructured"
7 states, supports a DCF estimate in the range of about 9
8 to 11 percent, with a 10.5 percent midpoint. These three
9 DCF studies are summarized on my Exhibit No. 604, pages 1
10 and 2, and on Exhibit No. 605.
11 I also present evidence on comparable earnings
12 as additional background information for the Commission..13 The recent historical and proj ected earned returns for
14 the proxy electric companies are generally in the 9 to 10
15 percent range, on average, or somewhat higher.
16 Considering this cost of capital evidence, I
17 believe a reasonable range for the "baseline" cost of
18 equity would be about 10.0 to 10.5 percent, with the best
19 evidence supporting returns toward the midpoint or lower
20 end of this range. Hence, my recommendation of 10.5
21 percent (before consideration of possible risk-mitigating
22 regulatory changes) is consistent with this baseline
23 evidence plus a small return premium to recognize the
24 stressed financial environment and concerns of credit.25 rating agencies.
2079 Matthew I. Kahal, Di 12
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1 Q.HAVE YOU INCLUDED AN ADJUSTMENT FOR COMMON STOCK
2 ISSUANCE COSTS?
3 A.No, I have not done so since there is no indication
4 in discovery responses of any current or near-term plans
5 by IdaCorp to conduct a public issuance of common stock.
6 The last such public issuance occurred in 2004. Notably,
7 Dr. Avera also presents no evidence for a flotation
8 adj ustment adder, nor does he calculate such
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2080 Matthew I. Kahal, Di 12a
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1 an adder. Consequently, there is no basis for suggesting
2 such costs somehow are being "left out" of the cost of
3 capital determination.
4
5 D.Testimony Organization
6 Q.HOW is THE REMAINDER OF YOUR TESTIMONY ORGANIZED?
7 A.Section III presents my DCF evidence based on the
8 application of that model to the West Region electric
9 utili ties. Section iv is my reply to Dr. Avera's cost of
10 equi ty evidence. In presenting that reply I discuss his
11 DCF evidence , Capital Asset Pricing Model (CAPM) studies
12 and his comparable earnings data. In Section iv, I
13 present alternative comparable earnings information.
14 Finally, Section V presents a summary of my conclusions
15 and recommendations.
16
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2081 Matthew I. Kahal, Di 13
Department of Energy
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1 I I I . COST OF COMMON EQUITY
2 A.Using the DCF Model
3 Q.WHAT STANDARD ARE YOU USING TO DEVELOP YOUR RETURN
4 ON EQUITY RECOMMENDATION?
5 A.As a general matter, the ratemaking process is
6 designed to provide the utility an opportunity to recover
7 its prudently-incurred costs of providing utility service
8 to its customers, including the reasonable costs of
9 financing its, used and useful investment. Consistent
10 with this "cost-based" approach, the fair and appropriate
11 return on equity award for a utility is its cost of
12 equi ty. The utility's cost of equity is the return
13
14
required by investors (i. e., the "market return") to
acquire or hold that Company's common stock. A return
15 award greater than the market return would be excessive
16 and would overcharge customers for utility service.
17 Similarly, an insufficient return could unduly weaken the
18 utility and impair incentives to invest.
19 Although the concept of the cost of equity may be
20 precisely stated, its quantification poses challenges to
21 regulators. The market cost of equity, unlike certain
22 other utility costs, cannot be directly observed (i. e. ,
23 investors do not directly, unambiguously state their
24 return requirements), and it therefore must be estimated
25 using analytic techniques. The DCF model is one such
2082 Matthew I. Kahal, Di 14
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1 technique familiar to analysts and this Commission and
2 was relied upon in IPC' s last fully-litigated rate case,
3 in 2004.
4 Q.is THE COST OF EQUITY A FAIR RETURN AWARD FOR THE
5 UTILITY AND CUSTOMERS?
6 A.Generally speaking, I believe it is. A return award
7 commensurate with the cost of equity generally provides
8 fair and reasonable compensation to utility investors and
9 normally should allow efficient utility management to
10 successfully finance its
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2083 Matthew I. Kahal, Di 14a
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1 operations on reasonable terms. Certainly, this has been
2 the case for IPC based on the 10.25 percent equity return
3 granted by the Commission in its rate case in 2004.
4 Setting the return on equity equal to a reasonable
5 estimate of the cost of equity also is fair to
6 ratepayers.
7 I recognize that there can be exceptions to
8 this general rule. For example, in some instances,
9 utili ties have sought rate of return adders as a reward
10 for asserted good management performance. In this case,
11 the Company is seeking a return on equity that
12 approximates the midpoint of Dr. Avera's 10.8 to 11.8
13 percent cost of equity range. Mr. Keen further justifies
14 the 11.25 percent request (an increase of 100 basis
15 points compared to the 10.25 percent previously awarded)
16 on a range of business risks that IPC currently faces.
17 Q.WHAT DETERMINES A COMPANY'S COST OF EQUITY?
18 A.It should be understood that the cost of equity is
19 essentially a market price, and as such, it is ultimately
20 determined by the forces of supply and demand operating
21 in financial markets. In that regard, there are two key
22 factors that determine this price. First, a company's
23 cost of equity is determined by the fundamental
24 conditions in capital markets (e.g., outlook for
25 inflation, monetary policy, changes in investor behavior,
2084 Matthew I. Kahal, Di 15
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1 investor asset preferences, etc.). The second factor (or
2 set of factors) is the business and financial risks
3 encountered by the utility in question. For example, the
4 fact that a utility company effectively operates as a
5 regulated monopoly, dedicated to providing an essential
6 service (in this case electric utility service),
7 typically would imply low business risk and therefore a
8 relatively low cost of equity, as compared to most
9 unregulated companies operating in competi ti ve markets.
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2085 Matthew I. Kahal, Di 15a
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1 Q.DOES DR. AVERA INCORPORATE THESE PRINCIPLES?
2 A.In general, he attempts to incorporate these
3 principles in conducting his DCF and CAPM analyses.
4 However, I disagree with his recommendation of a return
5 on equity range substantially higher than that granted by
6 the Commission in 2004. Moreover, I question whether his
7 "risk premium" analyses (i. e., his CAPM studies) reliably
8 measure the cost of equity, and I also question his use
9 of unregulated companies as being appropriate "risk
10 proxies" for the fully-regulated IPC. The use of
11 unregulated companies as a proxy group for a utility is a
12 non-standard approach.
13 Q.WHAT METHODS ARE YOU USING IN THIS CASE?
14 A.I employ the DCF method applied to proxy groups of
15 electric utility companies to obtain a "baseline" cost of
16 equity, and I also consider comparable earnings evidence.
17 However, for reasons discussed in my testimony, I
18 emphasize the DCF model results in formulating my
19 recommendation. It has been my experience that most
20 utility regulatory commissions (federal and state)
21 heavily emphasize the use of the DCF model to determine
22 the cost of equity when setting the fair return. While I
23 do not rely on the CAPM to develop my recommendation, the
24 next section of my testimony provides a discussion of
25 this method and Dr. Avera's application of it. The
2086 Matthew I. Kahal, Di 16
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1 comparable earnings method can provide perspective, but
2 it is not a cost of equity method.
3 Q.PLEASE DESCRIBE THE DCF MODEL.
4 As mentioned, this model has been widely used in theA.
5 regulatory community, including by this Commission. Its
6 widespread acceptance is due to the fact that the model
7 is market-based and is derived from standard and accepted
8 economic/financial theory. The model is transparent and
9 readily understandable.
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2087 Matthew I. Kahal, Di 16a
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1 The DCF theory begins by recognizing that any
2 publicly-traded common stock (utility or otherwise) will
3 sell at a price reflecting the discounted stream of cash
4 flows expected by investors. The obj ecti ve is to
5 estimate that discount rate.
6 Using certain simplifying assumptions (that I
7 believe are generally reasonable for utilities), the DCF
8 model for dividend paying stocks can be distilled down as
9 follows:
10 Ke ~ (Do/Po) (1 + 0.5g) + g, where
11 Ke = cost of equity;
12 Do the current annualized dividend;
13 Po stock price at the current time; and
14 g =, the long-term annualized dividend growth15 rate.
16 As an example, assume a utility company has a
17 current share price of $20.00, pays a current annualized
18 dividend per share of $1.00, and its dividend is expected
19 to grow over time by 5 percent per year. The DCF formula
20 would calculate the investor market rate of return to be:
21 ($1.00 / $20.00) (1.025) + 5.0% = 10.13%
22 This is referred to as the constant growth DCF
23 model, because for mathematical simplicity , it is assumed
24 that the growth rate is constant for an indefinitely long
time period. While this constancy assumption may seem
2088 Matthew I. Kahal, Di 17
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1 restricti ve in many cases, for traditional utili ties
2 (which tend to be more stable than most unregulated
3 companies) the assumption generally is reasonable,
4 particularly when applied to a group of companies.
5 Q.HOW HAVE YOU APPLIED THIS MODEL?
6 A.Strictly speaking, the model can be applied only to
7 publicly-traded companies, i. e., companies whose market
8 prices (and therefore market valuations) are
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2089 Matthew I. Kahal, Di 17a
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1 transparently revealed. Consequently, the model cannot
2 be applied to IPC, which is a wholly-owned subsidiary of
3 IdaCorp, and therefore, a market proxy is needed. In
4 theory, IdaCorp could serve as that market proxy, and I
5 include IdaCorp as one of my 13 West Region proxy
6 companies.
7 In any case, I believe that an appropriately
8 selected proxy group (preferably one reasonable in size)
9 is likely to be more reliable than a single company
10 study. This is because there is "noise" or fluctuations
11 in stock price (or other) data that cannot always be
12 readily accounted for in a simple DCF study. The use of
13 an appropriate proxy group helps to allow such "data
14 anomalies" to cancel out in the averaging process.
15 For the same reason, I prefer to use market
16 data that are, relatively current but averaged over a
17 period of several months (i. e., six months rather than
18 purely relying upon "spot" market data). It is important
19 to recall that this is not an academic exercise but
20 involves the setting of "permanent" utility rates that
21 are likely to be in effect for several years. The
22 practice of averaging market data over a period of
23 several months can add stability to the results. Dr.
24 Avera, by comparison, appears to favor "spot" market data
25 (i.e., as of May 2008) and has not indicated any plans to
2090 Matthew I. Kahal, Di 18
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1 provide an update.
2
3 B.DCF Study Using the West Region Group of Electric
4 Utili ty Companies
5 Q.HOW DID YOU SELECT YOUR PROXY GROUP IN THIS CASE?
6 A.I have applied the DCF model to a group of 13
7 companies listed in the Value Line Investment Survey as
8 being West Region Electric Utilities. This is the same
9 general approach as taken by Dr. Avera in the 2004 rate
10 case and more recently for IPC in a FERC case in 2006.
11 He employed in the 2006 FERC case 11 West
12
2091 Matthew I. Kahal, Di 18a
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1 Region companies, and 10 of his 11 proxy companies are
2 part of my proxy group. I initially include all of the
3 West Region electrics that are listed in Value Line
4 except for three companies that have dividend anomalies
5 that make application of the DCF problematic. Sierra
6 Pacific Resources only recently began paying a dividend,
7 and it is currently at a very minimal level. El Paso
8 Electric does not pay a dividend, and PNM Resources cut
9 its dividend wi thin the last three months. As a second
10 proxy group, I have eliminated five West Region electrics
11 from my list of 13 companies. Specifically, I eliminate
12 all three California utilities, since California is a
13 restructured state; MDU Resources, since it is rated "1"
14 for Safety by Value Line and has unusual growth
15 characteristics; and UniSource since its DCF
16 characteristics are unusually low. This second or
17 "restricted group" includes eight West Region electric
18 companies.
19 I provide a listing of these 13 companies on
20 Exhibi t No. 603, along with certain risk indicators
21 (i. e., Value Line Safety Rating, common equity ratio,
22 beta and financial strength rating). The "beta" measure
23 is explained further later in Section iv of my testimony.
24 My exhibit shows the average values for these risk
25 indicators using both the full 13-company group and the
2092 Matthew I. Kahal, Di 19
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1 restricted 8-company group. The averages for the two
2 proxy groups appear to be very similar, with the
3 13-company group having a slightly stronger Safety
4 Rating. In general, IdaCorp appears to have risk
5 attributes generally similar to the averages of both
6 groups, with perhaps slightly greater risk.
7 Unfortunately, these risk indicators are not published by
8 Value Line for IPC since it is not a publicly-traded
9 company.
10 Q.HAVE EITHER YOU OR DR. AVERA PROPOSED AN ADJUSTMENT
11 TO THE COST OF EQUITY FOR ANY RISK DIFFERENCE BETWEEN THE
12 PROXY COMPANIES AND IPC?
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2093 Matthew I. Kahal, Di 19a
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1 A.No. Dr. Avera adopts a cost of equity range of 10.8
2 to 11.8 percent, and Mr. Keen selects 11.25 percent which
3 is close to the midpoint of that range. While Mr. Keen
4 discusses risk issues, he does not quantify or propose a
5 specific cost of equity adj ustment. I also do not
6 propose a discrete risk adjustment relative to my proxy
7 group DCF results, although my 10.5 percent
8 recommendation is toward the upper end of my DCF range.
9 Q.HOW HAVE YOU APPLIED THE DCF MODEL TO THIS GROUP?
10 A.I have elected to use a six-month time period to
11 measure the dividend yield component (Do/Po) of the DCF
12 formula. Using the Standard & Poor's Stock Guide, I
13
14
compiled the month-ending dividend yields for the six
months ending September 2008, the most recent data
15 available to me as of this time. The dividend yields are
16 month-ending, and since the October 2008 edition of the
17 Stock Guide is not yet available, I have used Yahoo
18 Finance as the data source for my September 2008 yields
19 (i.e., as of September 30, 2008).
20 I show these dividend yield data on page 3 of
21 Exhibit No. 604 for each proxy company, April through
22 September 2008. Over this six-month period, the
23 13-company group average dividend yields were relatively
24 stable ranging from a high of 3.88 percent in June to a
25 low of 3.62 percent in April 2008, averaging 3. 73 percent
2094 Matthew I. Kahal, Di 20
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1 for the full six months. This indicates a slight upward
2 trend over this recent six-month period.
3 For DCF purposes and at this time, I am using a
4 proxy group six-month average dividend yield of 3. 73
5 percent.
6 Q.is 3. 73 PERCENT YOUR FINAL DIVIDEND YIELD?
7 A.Not quite. Strictly speaking, the dividend yield
8 used in the model should be the value the investor
9 expects over the next 12 months. Using the standard
10 "half
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2095 Matthew I. Kahal, Di 20a
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1 year" growth rate adjustment technique, the DCF adjusted
2 yield becomes 3.9 percent. This is based on assuming
3 that half of a year of growth is 3.0 percent (i. e., a
4 full year growth is about 6.0 percent) .
5 Q.DOES DR. AVERA EMPLOY THE SAME GROWTH RATE
6 ADJUSTMENT?
7 A.It appears that he indirectly uses a similar
8 approach that would produce about the same end result as
9 my dividend adjustment. As best I can determine, he
10 employs Value Line's estimate of the per share dividend
11 over the next 12 months. For a group of companies, this
12 would be roughly analogous to using the "0. 5g" adjustment
13 factor.
14 Q.HOW HAVE YOU DEVELOPED YOUR GROWTH RATE COMPONENT?
15 A.Unlike the dividend yield, the investor growth rate
16 cannot be directly observed but instead must be inferred
17 through a review of available evidence. The growth rate
18 in question is the long-run dividend per share growth
19 rate, but analysts frequently use projected earnings
20 growth as a proxy for (long-term) dividend growth. This
21 is because in the long-run earnings are the ultimate
22 source of dividend payments to shareholders, and this is
23 likely to be particularly true for a large group of
24 companies.
25 One possible approach is to examine historical
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1 growth as a guide to investor expected future growth, for
2 example the recent five-year or ten-year growth in
3 earnings, dividends and book value per share. However,
4 my experience in recent years with utili ties has been
5 that these historic measures have been very volatile and
6 are not reliable as long-run prospective measures. This
7 may be due in part to extensive corporate restructuring
8 in the energy industry. I note that
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2097 Matthew I. Kahal, Di 21a
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.1 Dr. Avera also chooses to rely primarily on prospective
2 rather than historical growth measures. The DCF growth
3 rate should be prospective, and one useful source of
4 information on prospective growth is the published
5 proj ections of earnings per share (typically five years)
6 prepared by securities analysts. Dr. Avera places
7 primary weight on this information (along with his
8 calculations of earnings retention growth), using
9 earnings growth rates published by Value Line, IBES and
10 Zacks, and I agree that this type of evidence warrants
11 substantial emphasis.
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Q.PLEASE DESCRIBE YOUR EVIDENCE.
A. Exhibit No. 604, page 4 of 5, presents four
well-known sources of projected earnings growth rates.
15 Three of these four sources -- First Call, Zacks and
16 CNNMoney. com -- provide averages from securities analyst
17 surveys conduGted by or for these organizations
18 (typically reporting the median value). The fourth,
19 Value Line, is that organization's own estimates. Value
20 Line publishes its own projections using annual average
21 earnings per share for a three-year historic base period
22 of 2005-2007 to a forecast period of 2011-2013.
23 As this exhibit shows, the growth rates vary
24 somewhat among the four sources, both for individual.25 companies and for the group averages. These group
2098 Matthew I. Kahal, Di 22
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1 averages are 6.33 percent for CNN, 7.83 percent for First
2 Call, 6.89 percent for Zacks and 4.85 percent for Value
3 Line. In this case, I have calculated the average of
4 these four sources, or about 6.2 percent, as a reasonable
5 measure of expected growth, and a range of 6.0 to 6.5
6 percent.
7 Q.is THERE ANY OTHER EVIDENCE THAT SHOULD BE
8 CONSIDERED?
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2099 Matthew I. Kahal, Di 22a
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1 A.Yes. There are a number of reasons why investor
2 expectations of long-run dividend growth could differ
3 from the limited, five-year earnings proj ections from
4 securi ties analysts. Consequently, while securities
5 analyst estimates should be considered and given
6 substantial weight, these growth rates should be subject
7 to a reasonableness test and corroboration, to the extent
8 feasible.
9 On Exhibit No. 604, page 5 of 5, I have
10 compiled three other measures of growth published by
11 Value Line, i.e., growth rates of dividends and book
12 value per share and long-run retained earnings growth.
13 (Retained earnings growth reflects the growth over time
14 one would expect from the reinvestment of retained
15 earnings, i. e., earnings not paid out as dividends. It
16 is one of the growth sources considered by Dr. Avera.)
17 As shown on this Exhibit, these growth measures tend to
18 be similar to or less than analyst growth proj ections
19 shown on page 4 of the Exhibit. Di vidend growth averages
20 5.33 percent,' book value growth averages 5.00 percent,
21 and earnings retention growth averages 4.54 percent.
22 Notably, each of these al ternati ve measures of growth
23 falls below the 6.0 to 6.5 percent range cited above.
24 This suggests' that the growth rate range based on
25 earnings proj ections surveys I have calculated for DCF
2100 Matthew I. Kahal, Di 23
Department of Energy
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21
22
23
24.25
1 purposes may be conservatively high.
2 Q.WHAT is YOUR DCF CONCLUSION?
3 A. I summarize my DCF analysis on page 1 of Exhibit No.
4 604. The adjusted dividend yield for the six months
5 ending September 2008 is 3.9 percent for this group.
6 Published earnings growth rate proj ections would support
7 a long-run growth rate in the range of about 6.0 to 6.5
8 percent, as explained above. Summing the adj usted yield
9 and growth rate range produces a total return of 9.9
10 percent to 10.4 percent, and a midpoint result of 10.15
11 percent.
12
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18
19
2101 Matthew I. Kahal, Di 23a
Department of Energy
.
.
.
1 Q.WHY DO YOU NOT INCLUDE AN ADJUSTMENT FOR FLOTATION
2 COSTS?
3 A.If a utility issues new common stock through public
4 offering, it will likely incur flotation expenses,
5 principally underwriting fees. This is potentially a
6 recoverable expense, and one way of providing recovery is
7 through a rate of return adder. Dr. Avera proposed an
8 adder of 0.2 percent in last year's case, but does not
9 include any adj ustment in this current case. Instead, he
10 suggests that this should be a consideration in selecting
11 a final authorized return. However, he presents no data
12 showing that these costs actually have been incurred.
13 Given this lack of evidence and company data
14 responses indicating that there are no material flotation
15 costs, this should not be a factor in setting the
16 authorized return.
17 Q.DOES YOUR DCF STUDY TAKE INTO ACCOUNT THE CURRENT
18 FINANCIAL CRISIS?
19 A.No, not directly. It is based on market conditions
20 during the second and third calendar quarters of 2008,
21 which I believe is appropriate for rate setting in this
22 case. This was a period of elevated stress and
23 volatili ty but was largely prior to the severe financial
24 crisis that emerged in recent weeks. I discuss this
25 issue later in the "Conclusions" section of my testimony.
2102 Matthew I. Kahal, Di 24
Department of Energy
.
.
.
1 C.DCF Study Using the Restricted Proxy Group
2 Q.WHAT is THE PURPOSE OF YOUR RESTRICTED PROXY GROUP
3 STUDY?
4 A.I have eliminated five proxy companies in order to
5 obtain a proxy group that is more representative of IPC
6 than the 13-company proxy group. I have done so by
7 eliminating the three California companies (PG&E, Edison
8 International and
9
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2103 Matthew I. Kahal, Di 24a
Department of Energy
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1 Sempra) since they operate in a very different regulatory
2 environment than the rest of the West Region. I also
3 eliminated two companies (MDU and UniSource) that appear
4 to be "outliers" in terms of the DCF growth rate results,
5 wi th MDU being unusually high and UniSource being
6 unusually low. Moreover, MDU differs from other West
7 Region companies begin rated "1" for Safety by Value
8 Line. This leaves a restricted West Region electric
9 proxy group of eight companies.
10 Q.HOW HAVE YOU CONDUCTED YOUR DCF STUDY FOR THIS
11 GROUP?
12 A.I have conducted my DCF analysis for the restricted
13 group in the same manner as my DCF analysis for the full,
14 13-company group. I present the data used in restricted
15 group analysis on DOE Exhibit No. 604. On pages 3, 4 and
16 5 of that exhibit, the restricted proxy group averages
17 are shown in the row below the full group averages. Page
18 2 of that Exhibit presents the DCF summary.
19 For the six months ending September 2008, the
20 group dividend yield averages 4.33 percent, which
21 translates into an adjusted yield of 4.6 percent. Based
22 on the evidence on pages 4 and 5 of that Exhibit, a
23 reasonable growth range would be 5.0 to 6.0 percent,
24 somewhat less than the growth rate range for the full
25 group. Combining the adj usted yield plus the range of
2104 Matthew I. Kahal, Di 25
Department of Energy
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22
23
24
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1 growth produces a total return range of 9.6 to 10.6
2 percent, and a midpoint of 10.1 percent. Again, no
3 adj ustment is needed for flotation expense.
4 Q.HOW DID YOU DEVELOP THE 5.0 TO 6.0 PERCENT GROWTH
5 RATE RANGE?
6 A.Page 4 of Exhibit No. 604 shows the published
7 earnings growth rates from my four sources - Value Line,
8 CNN, Zacks and First Call. The four sources average
9
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/
2105 Matthew I. Kahal, Di 25a
Department of Energy
.
.
.
1 to 5. 78 percent for the restricted proxy group, with
2 First Call being an "outlier" of 7.19 percent. This
3 appears to be due primarily to one anomalous data point -
4 a 14.8 percent growth rate for Hawaiian Electric.
5 (Similarly, Value Line has an anomalously low growth rate
6 for one company, Pinnacle West.)
7 Page 5 of this Exhibit provides Value Line
8 growth measures other than earnings for the restricted
9 proxy growth ~ dividends, book value and earnings
10 retention. Each of these growth measures for the group
11 is in the 3 to 4 percent per year range.
12 Consideration of all of this information, but
13 emphasizing published earnings growth proj ections,
14 supports a DCF growth rate range of 5.0 to 6.0 percent at
15 this time.
16
17 D.Dr. Avera's DCF Estimates
18 Q.HOW DID DR. AVERA ESTIMATE THE COST OF EQUITY USING
19 THE DCF MODEL?
20 A.Dr. Avera employed an application of the standard
21 DCF model to two proxy groups of companies. The first
22 analysis group uses a proxy group of 27 electric utility
23 companies in conjunction with four DCF growth measures.
24 Three of the growth measures are analyst proj ections of
25 the growth in earnings per share (published by IBES,
2106 Matthew I. Kahal, Di 26
Department of Energy
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24
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1 Zacks and Value Line), and the fourth is Dr. Avera's own
2 calculations of growth from retained earnings ( derived
3 using Value Line data). The DCF calculations employ
4 market data as of May 2008, and four sources of growth
5 produce DCF estimates for the 27-company group of 11.7
6 percent, 11.6 percent, 11.1 percent and 9.5 percent. The
7 average of the four measures
8
9 /
2107 Matthew I. Kahal, Di 26a
Department of Energy
.1 produces an estimated investor return of about 11.0
2 percent, which is somewhat above the upper end of my own
3 DCF range.
4 Dr. Avera's second DCF study does not employ
5 utili ty companies at all, but instead uses a group of
6 unregulated companies. Not surprisingly, the non-utility
7 study produces dramatically higher DCF results -- 12.3
8 percent, 12.8 percent, 12.5 percent and 12. 7 percent
9 using the four growth rate measures, averaging 12.6
10 percent. This is roughly a 15 percent cost of equity
11 increase over his utility study DCF results.
.12
13
14
Q.ARE DR. AVERA'S DCF RESULTS REASONABLE?
A. His electric utility study is only moderately above
the upper end of my DCF results and in that sense might
15 seem to be a plausible estimate at least for this proxy
16 group. Howev~r, his study of non-utility companies
17 produces a completely unrealistic estimate of IPC' s cost
18 of equity, and Dr. Avera has no convincing explanation
19 for the enormous difference in the results of his two
20 studies. Since he ultimately recommends a range of 10.8
21 to 11.8 percent, it appears that he is putting no weight
22 on his non-utility DCF study in formulating his
23 recommendation. I believe that his non-utility study has
24 little to do with IPC's actual cost of equity and is not.25 reasonable for use in this case.
2108 Matthew I. Kahal, Di 27
Department of Energy
.
.
18
19
20
21
22
23
24.25
1 I have concerns regarding the comparability of
2 the 27 companies in his electric company proxy group as
3 well. This is because a number of his proxy group
4 electric companies operate in competi ti vely restructured
5 states, and some of the companies have substantial
6 non-utili ty operations. The most appropriate risk
7 proxies for IPC would be electric utility companies that
8 are fully or predominantly regulated utility and
9 vertically-integrated, such as the 13 companies in my
10 West Region proxy group.
11
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17
2109 Matthew I. Kahal, Di 27a
Department of Energy
.
.
1 Q.WHICH UTILITY COMPANIES SHOULD BE ELIMINATED FROM
2 HIS PROXY GROUP?
3 A.Companies in Dr. Avera's group operating mostly in
4 restructured states and/or with substantial unregulated
5 operations would include:
6 .Allegheny Energy ( Pennsylvania, Maryland)
7 .CenterPoint Energy (Texas)
8 .CMS Energy (Michigan)
9 .DPL, Inc. (Ohio)
10 .DTE Energy Co. (Michigan)
11 .Northeast Utilities (New England)
12 .PEPCO Holdings (Maryland, D. C., Delaware)
13 .PPL Corp. (Pennsylvania)
14 .Public Service Enterprise Group (New
15 Jersey)
16 .PG&E Corp. (California)
17 .UIL Holdings (Connecticut)
18 I believe these companies are less useful and
19 appropriate as proxies for IPC than his other electric
20 utility companies.
21 Q.HOW WOULD THE REMOVAL OF THE COMPANIES IN
22 RESTRUCTURED STATES AFFECT HIS DCF RESULTS?
23 A.On my Exhibit No. 605, I reproduce Dr. Avera's
24 electric utility DCF calculations using his four growth.25 rate measures but removing the companies from the
2110 Matthew I. Kahal, Di 28
Department of Energy
.
.14
15
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24.25
1 restructured states and their non-utility operations. I
2 have also excluded the West Region companies in his group
3 since those companies are already included in my DCF
4 study. As Exhibit No. 605 shows, a DCF study of the
5 fully regulated and vertically-integrated utility subset,
6 provides a return range (using his four growth
7
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9
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11
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13
2111 Matthew I. Kahal, Di 28a
Department of Energy
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.
20
21
22
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24.25
1 measures) of about 9.0 to 11.2 percent, averaging 10.5
2 percent. This corresponds to the upper end of my own DCF
3 study results and is well below his full 27-company
4 average of 11.0 percent. Please note that these are Dr.
5 Avera's own DCF calculations but utilizing a more
6 appropriate subset of his electric company proxy group,
7 rather than the full 27-company group.
8 Q.is IT REASONABLE TO REMOVE THE COMPANIES FROM
9 RESTRUCTURED STATES?
10 A.Yes. I believe the integrated, fully-regulated
11 companies are a more appropriate risk proxy for IPC. In
12 the 2004 case, the Commission recognized this distinction
13 noting that, "Idaho is not likely to have deregulation
14 risks like those experienced in other states".(Order,
15 page 43, Case No. IPC-E-03-13) Clearly, those "other
16 states" would include California, the Northeast and
17 Mid-Atlantic states, as indicated above.
18
19
2112 Matthew I. Kahal, Di 29
Department of Energy
.1 iv. REVIEW OF DR. AVERA'S DCF, CA AN COMPARLE
2 EAINGS
3 A.DCF Analysis
4 Q.WHAT ARE YOUR OBJECTIONS TO DR. AVERA'S DCF
5 ANALYSIS?
6 A.Dr. Avera performs two DCF studies, one using a
7 27-company proxy group of electric companies and a second
8 that uses a large group of unregulated companies
9 operating in competi ti ve markets. As previously
10 discussed, he obtains vastly different results for the
11 two proxy groups - 11.0 percent for his electric company
12 group and 12.6 percent for the unregulated companies. In.13
14
my opinion, the DCF study for the unregulated companies
has no value at all in determining the regulated fair
15 return in this case for IPC and therefore should be
16 disregarded.
17 The DCF study for the electric group is more
18 reasonable and closer to my upper end results in this
19 case. However, as noted earlier, even this analysis is
20 improperly burdened by the inclusion of electric
21 companies operating in restructured states, with some of
22 these companies having substantial non-regulated
23 operations (e. g., Allegheny Energy, PPL Corporation,
24 etc.), which adds substantial risk. Removing the.25 "restructured" companies would reduce the group cost of
2113 Matthew I. Kahal, Di 30
Department of Energy
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17
18
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22
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24.25
1 equi ty to about 10.5 percent as I have shown on my
2 Exhibit 605.
3 Q.DOES THE COMMISSION RELY ON DCF EVIDENCE?
4 A.Yes, in conjunction with the comparables earning
5 method. In particular, the Commission's Order in Case
6 No. IPC-E-03-13 (page 38) states:
7 The Commission has relied primarily on the
discounted cash flow method (DCF) and the
8 comparable earnings method in previous
cas~s, and we do so again in this case.
9
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16
2114 Matthew I. Kahal, Di 30a
Department of Energy
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1 That Order further observes that IPC is not burdened by
2 "deregulation risks" such as those experienced in other
3 states.(Id., page 43)
4
5 B.CAM Results
6 Q.WHAT RESULTS DOES DR. AVERA OBTAIN USING THE CAPM?
7 A.Dr. Avera uses two approaches to applying the CAPM
8 and two proxy groups, i. e., his electric company and
9 unregulated utility company groups. The two approaches
10 involve estimating the market risk premium using (a)
11 long-run historical market returns on stocks versus
12 bonds; and (b) a "prospective" estimate of the return on
13 a subset of the overall stock market (specifically, the
14 expected return on the dividend-paying stocks in the S&P
15 500). The two groups and methods produce the following
16 CAPM cost of equity estimates:
17 1. Utility/historical method - 10.8%
18 2. Non-utility/historical method - 10.2%
19 3. Utility/prospective method - 11.9%
20 4. ' Non-utility/prospective method - 11.2%
21 The four CAPM studies average to about 11.0 percent, but
22 the electric company cost of equity is found to be higher
23 than the unregulated company cost. This is
24 counterintuitive and exactly the reverse of his DCF.25 results.
2115 Matthew I. Kahal, Di 31
Department of Energy
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1 Q.PLEASE DESCRIBE THE CAPM APPROACH USED BY DR. AVERA.
2 A.The CAPM is a form of the "risk premium" approach
3 and is based on modern portfolio theory. According to
4 this model, the cost of equity (Ke) is equal to the yield
5 on a risk-free asset plus an equity risk premium
6 multiplied by a firm's "beta" statistic. "Beta" is a
7 firm-specific risk measure which is computed as the
8 movements in a company's stock price (or market return)
9 relati ve to
10
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14
2116 Matthew I. Kahal, Di 31a
Department of Energy
.
.
1 contemporaneous movements in the broadly defined stock
2 market. According to CAPM theory, this measures the
3 investment risk that cannot be reduced or eliminated
4 through asset diversification (i. e., holding a broad
5 portfolio of assets). The overall market, by definition,
6 has a beta of 1.0, and a company with lower than average
7 investment risk (e. g., a utility company) normally would
8 have a beta below 1.0. The "risk premium" is defined as
9 the expected return on the overall stock market minus the
10 yield or return on a risk-free asset.
11
12 The CAPM formula is:
Ke Rf + ß (Rm -Rf) ,where
Ke =the firm's cost of equity;
Rm =the expected return on the overall
market;
Rf the yield on the risk free asset;and
ß =the firm (or group of firms)risk
13
14
15
16
17
18
19 measure.
20 Two of the three principal variables in the
21 model are directly observable -- the yield on a risk-free
22 asset (e. g., a Treasury security yield) and the beta.
23 For example, Value Line publishes estimated betas for
24 each of the companies that it covers. The greatest area.25 of controversy, however, is in the measurement of the
2117 Matthew I. Kahal, Di 32
Department of Energy
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.
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~
1 expected stock market return (and therefore the equity
2 risk premium), since that variable cannot be directly
3 observed.
4 While the beta itself also is technically
5 "observable," different investor service publications or
6 sources provide differing estimates of betas depending on
7 the calculation methods that they use. These beta
8 differences can have large impacts on the CAPMcost of
9 equity results. In this case, Dr. Avera employs Value
10 Line published betas, and I have used Value Line betas as
11 well in past '
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2118 Matthew I. Kahal, Di 32a
Department of Energy
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1 cases. However, I note that other sources have very
2 different utility betas, which could yield lower (or
3 higher) results. I show an alternate source of betas,
4 which I compare with the Value Line betas, in this
5 subsection of my testimony.
6 Q.HOW HAS DR. AVERA APPLIED THIS MODEL?
7 A.Dr. Avera uses a long-term Treasury yield as the
8 risk-free return (i. e., 4.6 percent), and the average
9 beta for his electric proxy group is 0.88 (0. 79 for the
10 non-utility group). His "historic" and "prospective"
11 risk premium values are 7.1 percent and 8.3 percent,
12 respectively.
13 These parameters yield the following CAPM
14 calculations for his two proxy groups:
15 Ke = 4.6% + 0.88 (7.1) = 11.2%
16 (utili ty /historical)
17 Ke = 4.6% + 0.88 (8.3)11.9%
18 (utili ty /prospecti ve)
Ke = 4.6% +0.79 (7.1)10.2%
(non-utility /historical)
Ke = 4.6% + 0.79 (8.3) = 11.2%
(non-utili ty /prospecti ve)
Q.WHY DO YOU QUESTION THE VALUE LINE BETA ESTIMATES?
A.Dr. Avera considered only one source for the beta
statistics, a critical parameter for an application of
2119 Matthew I. Kahal, Di 33
Department of Energy
.
.
.
1 the CAPM. This differs from his DCF study where he used
2 three public sources for the published earnings growth
3 rates.
4 I have assembled growth rates from another
5 source (YahooFinance. com), and I compare them to the
6 Value Line figures for my proxy group, as shown below.
7 For the full 13-company group, the betas (on average) are
8 similar - 0.85 for Value Line versus 0.88 for Yahoo
9 Finance. For' the restricted proxy group, the Yahoo
10 Finance figures are slightly lower, 0.78 versus the Value
11 Line 0.83. Based on current evidence, the differences in
12 the published beta sources for the two proxy groups do
13
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not seem larg~.
2120 Matthew I. Kahal, Di 33a
Department of Energy
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23
24
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1 Based on this information, a reasonable range
2 would be O. 78 to 0.88 for beta. This takes into account
3 both sources of beta and both the full and restricted
4 proxy groups.
5
6 Alternative Beta Estimates for the
West Region Electrics
7
8 Value Line Yahoo Finance
9 Avista 0.90 0.70
10 Black Hills 0.90 1. 20
11 Edison Int.0.90 0.95
12 Hawaiian 0.75 0.41
13 IdaCorp 0.90 0.68
14 MDU Resources 1. 00 0.86
15 Pinnacle West 0.80 0.75
16 PG&E 0.85 0.93
17 Portland General 0.80 0.85
Puget Energy 0.80 0.85
Sempra 0.95 0.90
UniSource 0.75 1. 64
Xcel 0.80 0.76
Full Group Average 0.85 0.88
Restricted Group Average 0.83 0.78
Source: Value Line Investment Survey, August 8, 2008,
Yahoo Finance . com, September 2008.
2121 Matthew I. Kahal, Di 34
Department of Energy
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24.25
1 Q.DO YOU FIND THE 7.1 TO 8.3 PERCENT RISK PREMIUM TO
2 BE REASONABLE?
3 A. No, I believe these risk premium values are too
4 high. The "historical" 7.1 percent is a 1926-2007 stock
5 market arithmetic average risk premium, based on
6 after-the-fact market returns, compiled by Ibbotson
7 Associates. However, Dr. Avera
8
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2122 Matthew I. Kahal, Di 34a
Department of Energy
.
.
.
1 overlooks a key limitation in that estimate (as a measure
2 of today' s risk premium) that Dr. Ibbotson himself has
3 emphasized. His recent research has concluded that the
4 7.1 percent average historic value is biased upward by a
5 rising price/earnings ratio over the historic period~ and
6 the continuation of that trend would be inconsistent with
7 standard financial theory. He has corrected the historic
8 data removing this upward bias, obtaining a corrected
9 historic ( arithmetic average) risk premium of 5.9
10 percent.(Roger G. Ibbotson and Peng Chen, "Stock Market
11 Returns in the Long Run: Participating in the Real
12 Economy", Financial Analyst Journal, 2003.)
13 Dr. Avera's "prospective" 8.3 percent risk
14 premium itself is based on his very questionable
15 assumption that earnings on unregulated companies (i. e. ,
16 the dividend paying stocks in the S&P 500) will increase
17 by 10.4 percent per year for the long run. I believe
18 that this is excessively optimistic as an overall average
19 expectation for the long-term rate of growth in corporate
20 earnings. For example, the Value Line Selection and
21 Opinion, page 3975 (August 22, 2008), projects the
22 year-to-year growth rate in After-Tax Profits for 2009 to
23 2012 to range from 4.2 to 8.0 percent per year. Blue
24 Chip Economic Indicators (October 10, 2008), a survey of
25 major forecasting organizations, publishes a "consensus"
2123 Matthew I. Kahal, Di 35
Department of Energy
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24
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1 forecast that U. S. pre-tax corporate profits (current $)
2 will grow by 5.5 percent annually for 2010-2014 and 5.0
3 percent annually for 2015-2019. In light of these
4 prominent economic forecasts, Dr. Avera's corporate
5 earnings forecast growth rate of 10.4 percent (and
6 resulting 8.3 percent risk premium) is implausibly high,
7 as a measure of a long-run growth rate.
8 Q.ARE YOU AWARE OF ANY OTHER EVIDENCE THAT WOULD
9 CHALLENGE THE 7.1 TO 8.5 PERCENT RISK PREMIUM RANGE?
10
11 /
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14
2124 Matthew I. Kahal, Di 35a
Department of Energy
.1 A.Yes. The prominent textbook by Brealy, Myers and
2 Allen (Principles of Corporate Finance, 8th Edition, page
3 152) cites to survey data estimates of the equity risk
4 premiums. A 2001 Yale University survey study of
5 financial economists finds a 5.5 percent risk premium,
6 and a 2003 Duke Uni versi ty study of corporate Chief
7 Financial Officers ("CFOs") obtains a 3.8 percent risk
8 premium. While survey estimates are not necessarily
9 precise measures, this is "real world" information that
10 challenges the reasonableness of Dr. Avera's clearly
11 overstated equity risk premium range of 7.1 to 8.3
12 percent..13
14
Q.ARE YOU SPONSORING A CAPM STUDY?
A.No, I am not sponsoring such a study as a basis for
15 establishing IPC' s cost of equity in this case for the
16 reasons discussed above. It is also apparent that the
17 Commission has concerns about this method's usefulness
18 and in particular "the measurement and proper use of
19 Beta" .(Order No. 29505, page 38, May 25, 2004)
20 However, as a comparison and check on Dr. Avera's CAPM, I
21 present a CAPM calculation using: a risk-free rate of
22 4.5 percent (slightly lower than the figure used by Dr.
23 Avera, based on the most recent six months of yields for
24 20 year Treasury bonds), a beta of 0.83 (the midpoint of.25 the Value Line and the Yahoo Finance range of betas) and
2125 Matthew I. Kahal, Di 36
Department of Energy
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24.25
1 a 6.0 percent risk premium.
2
3 Ke 4.5% + 0.83 (6.0)9.5 percent
4
5 While I do not advocate the use in this case of
6 the CAPM method, I believe the 9.5 percent result shown
7 above for IPC should be compared with Dr. Avera's range
8 of 10.2 to 11.9 percent. The 10.2 percent is within the
9 range of reasonableness but the 11.9 percent clearly is
10 excessive.
11
12 /
13
/
2126 Matthew I. Kahal, Di 36a
Department of Energy
.
.
21
1 Q.WHAT CAPM ESTIMATE WOULD YOU OBTAIN USING DR.
2 AVERA'S HISTORICAL MARKET RISK PREMIUM OF 7.1 PERCENT?
3 A.That risk premium value produces the following cost
4 of equity estimate using the CAPM:
5 Ke = 4.5% + 0.83 (7.1) = 10.4 percent
6 Again, while I do not recommend this analysis, this
7 estimate is consistent with the range of my DCF studies.
8 C.Comparable Earnings
9 Q.WHAT RESULTS DID DR. AVERA OBTAIN FROM HIS
10 COMPARABLE EARNINGS STUDY?
11 A.Dr. Avera focused on the Value Line proj ections of
12 the earned return on equity for his electric utility
13 proxy group (11.1 percent). He also cites to the Value
14 Line estimated return on equity of 11.5 percent for 2008
15 and 13.5 percent for the electric industry as a whole for
16 the three to five-year forecast horizon. Based on this
17 information, he finds a comparable earnings estimate of
18 11.1 percent.(Avera, page 73 and his Exhibit 25)
19 Q.DOES HIS COMPARABLE EARNINGS ANALYSIS PROVIDE A
20 MARKET COST OF EQUITY ESTIMATE?
A.No, and he does not appear to claim that it does.
22 Rather, these are one publication's (i. e., Value Line's)
23 estimates of the accounting returns on book equity that
24 electric companies might earn in the future. It does not.25 measure either the return requirements or expectations
for financial markets. One key reason
2127 Matthew I. Kahal, Di 37
Department of Energy
.
.
.
1 why that is so is because the electric utility companies
2 have stock prices that typically are at a premium to book
3 value, a fact that Dr. Avera does not mention.
4 Q.WHY DOES THE MARKET-TO-BOOK RATIO MATTER?
5 A.Consider an electric utility with earnings per share
6 of $2.20 and a book value of $20. This would equal Dr.
7 Avera's 11.0 percent accounting return on equity.
8 However, if the stock price is $30, then the investor is
9 really earning $2.2/$30 = 7.3 percent on the market value
10 of his investment. Put another way, the investor is
11 willing to pay $30 per share for the stock and receive
12 $2.20 in current earnings. The fact that the market
13 value of the stock significantly exceeds book value
14 renders the usefulness of Dr. Avera's comparable earnings
15 study highly questionable.
16 Q.DO YOU HAVE ANY ALTERNATIVE CALCULATIONS OF
17 COMPARABLE EARNINGS?
18 A.Yes. As a comparison, I have compiled the
19 historical (i~e., 2006 - 2008) and projected (2011 -
20 2013) earned returns on equity, as published by Value
21 Line, on Exhibit No. 606 for my West Region electric
22 group and for Dr. Avera's electric group, i. e., the
23 vertically-integrated (non-West Region) subset of that
24 group.(Please note that 2008 results are partly actual
25 and partly projected.)
2128 Matthew I. Kahal, Di 38
Department of Energy
.
.
15 /
16
17
18
19
20
21
22
23
24.25
1 As shown on page 1, the West Region 13-company
2 proxy group earned return on equity ranges from about 9.2
3 percent to 10.4 percent, on average, for both the
4 historic and projected period. The earned returns for
5 the 8-company restricted proxy group are even lower,
6 averaging about 8.5 percent. For Dr. Avera's
7 vertically-integrated companies, the results are similar.
8 (Page 2 of Exhibit No. 606) During the historical
9 period, the group average return on equity
10
11 /
12
13 /
14
2129 Matthew I. Kahal, Di 38a
Department of Energy
.
.
20
21
22
23
24.25
1 is about 9.6 percent but increases to 10.6 percent for
2 the projected 2011 - 2013 time period.
3 If the two proxy groups on pages 1 and 2 of
4 Exhibi t No. 606 are combined, the average earned returns
5 on equity would generally fall in the 9 to 10 percent
6 range.
7 Q.WHAT DO YOU CONCLUDE?
8 A.While not a market cost of equity method, the
9 comparable earnings analysis results are roughly
10 consistent with or below my DCF evidence and help to
11 support a return on equity award in this case not to
12 exceed 10.5 percent.
13
14
15
16
17
18
19
2130 Matthew I. Kahal, Di 39
Department of Energy
.
.
.
1 V. CONCLUSIONS ON FAIR RATE OF RETUR
2 Q.PLEASE SUMMARIZE THE CONCLUSIONS THAT YOU HAVE
3 REACHED CONCERNING THE COMPANY'S RATE OF RETURN REQUEST.
4 A.IPC in this case is seeking an overall rate of
5 return of 8.55 percent, based on a proj ected year-end
6 2008 capital structure and embedded cost of debt and
7 inclusive of a return on common equity of 11.25 percent.
8 The requested return on equity is the approximate
9 midpoint of Dr. Avera's study range of 10.8 to 11.8
10 percent. IPC's 11.25 percent return on equity request is
11 a reduction from last year's request but is a very large
12 increase over, the 10.25 percent return on equity awarded
13 by the Commission in the 2004 rate case, an award
14 accompanied by a 46 percent common equity ratio.
15 I find acceptable the Company's proposed
16 capi tal structure and embedded cost of debt. However, I
17 do not agree with IPC' s request and supporting evidence
18 to increase the return on common equity from 10.25
19 percent awarded in 2004 to 11.25 percent. IPC remains a
20 financially sound, credit worthy utility with recognized
21 favorable business risk attributes. Most of the evidence
22 presented by Dr. Avera significantly overstates the IPC
23 cost of equity and fair return.
24 Q.PLEASE SUMMARIZE YOUR SPECIFIC DISAGREEMENTS WITH
25 DR. AVERA.
2131 Matthew I. Kahal, Di 40
Department of Energy
.
10 /
11
.
.
1 A. Dr. Avera presents three types of studies: DCF,
2 CAPM and comparable earnings. My only significant
3 disagreement with his DCF evidence is with his proxy
4 company selection.His non-utility DCF study obtained
5 12.6 percent, but unregulated companies from other
6 industries are not proper risk or business proxies for
7 IPC' s Idaho monopoly utility operations. These
8 unregulated
9
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
2132 Matthew I. Kahal, Di 40a
Department of Energy
1 companies from other industries are fundamentally.2 different from IPC. His electric company DCF study is an
3 improvement, but even that study is impaired by its
4 inclusion of several "restructured" companies. Some of
5 those companies have risk profiles and operating
6 environments much different than IPC. His subset of
7 vertically-integrated (non-West Region) companies yields
8 DCF results averaging about 10.5 percent.
9 The CAPM significantly overstates the cost of
10 equity by assuming a stock market risk premium in
11 approximately the 7 to 8 percent range, when a more
12 realistic estimate is 6 percent or less, and he selects a.13 utility "beta" value of 0.88 based on a single source.
14 In addition to these shortcomings, the Commission has
15 expressed concerns over the reliability and applicability
16 to IPC of the CAPM as a basis for determining the cost of
17 capital.
18 Finally, Dr. Avera obtains an 11.0 percent
19 result based on Value Line projections of accounting
20 returns on common equity for his utility proxy group (and
21 the industry as a whole). This evidence is problematic
22 and overstated for the reason stated previously -- the
23 utility group includes many companies that operate in an
24 unregulated environment in restructured states..25 Moreover, his calculations ignore the fact that these
2133 Matthew I. Kahal, Di 41
Department of Energy
.
.
.
1 companies sell at a large premium to book value.
2 Q.PLEASE SUMMARIZE YOUR OWN EVIDENCE ON COST OF
3 CAPITAL FOR IPC.
4 A.I recommend an overall return of 8.18 percent, which
5 includes a 10.5 percent cost of capital. I rely
6 primarily on a DCF study of two groups of West Region
7 electric utili ties, obtaining a range of 9.6 to 10.6
8 percent (9.9 to 10.4 percent and 9.6 to 10.6 percent for
9 the two groups). Consistent with Dr. Avera, I have used
10 the standard, constant growth DCF model, recent stock
11 market data and securities
12
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
2134 Matthew I. Kahal, Di 41a
Department of Energy
1 analyst proj ections of earnings growth. My two West.2 Region proxy groups are reasonably comparable to IPC
3 since all of these companies are vertically-integrated
4 electrics primarily operating under standard regulation.
5 This is similar to the proxy group previously used by Dr.
6 Avera in the 2004 IPC rate case as well as in a recent
7 FERC IPC rate proceeding.
8 As a check and to respond to Dr. Avera, I have
9 employed the comparable earnings method, using my proxy
10 group and the vertically-integrated portion of Dr.
11 Avera's proxy group. For these companies, the historical
12 and proj ected earned returns on equity display averages.13 in the range of about 9.0 to 10.0 percent, or at most
14 about 10.6 percent. The comparable earnings evidence
15 helps to support the reasonableness of my 10.5 percent
16 recommendation in this case.
17 Q.DOES YOUR RECOMMENDATION REFLECT THE EFFECTS ON THE
18 COST OF CAPITAL OF THE CURRENT FINANCIAL CRISIS?
19 A.No, it does not. As of this writing, the dimensions
20 of this crisis are not fully understood and cannot be
21 captured by standard, equilibrium models such as the DCF
22 or CAPM. These conditions cannot form the basis for
23 setting IPC' s fair rate of return and permanent retail
24 rates. My analysis employs market data from the most.25 recent six months ending September 2008, a period of
2135 Matthew I. Kahal, Di 42
Department of Energy
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.
.
11
12 /
13
14
15
16 /
17
18
19
20
21
22
23
24
25
1 stress and enhanced volatility but not severe financial
2 disruption and crisis. Nonetheless, I believe it
3 appropriate to award IPC an equity return no higher than
4 10.5 percent, a figure toward the upper end of my DCF
5 range.
6 While my recommendation at this time is 10.5
7 percent, this is before consideration of potential
8 regulatory changes (discussed at length by Company
9 wi tnesses) that may have the effect of mitigating IPC' s
10 investment risk. Credit
/
2136 Matthew I. Kahal, Di 42a
Department of Energy
.
.
15
16
17
18
19
20
21
22
23
24.25
1 rating agency reports also have discussed these
2 regulatory issues. Such changes could include allowing
3 the use of a forecasted test year; changing (i. e. ,
4 increasing) the cost reconciliation percent (currently 90
5 percent) under the Power Cost Adj ustment (PCA) clause;
6 and potential modifications to the Load Growth Adjustment
7 Rate (LGAR). It is my understanding that the Company,
8 Staff and certain parties are in the process of
9 addressing the PCA and LGAR issues. Depending on how
10 these regulatory policy issues ultimately are resolved,
11 the Commission should consider a return on equity award
12 in this case of 10.25 to 10.5 percent, with the 10.5
13 percent being an upper bound figure in this case.
14 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY
A.Yes, it does.
2137 Matthew I. Kahal, Di 43
Department of Energy
.1
2 open hearing.)
(The following proceedings were had in
4 you have questions?
COMMISSIONER SMITH: Mr. Richardson, do3
5 MR. RICHARDSON: Thank you, Madam Chair, I
6 do not have any questions.
.
18
19
7
8
9
10
11
12
13
14
15
16
17
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: No questions.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Ward.
MR. WARD: No questions.
COMMISSIONER SMITH: Mr. Price.
MR. PRICE: No questions.
COMMISSIONER SMITH: Ms. Nordstrom.
MS. NORDSTROM: Thank you.
CROSS-EXAMINATION
20 BY MS. NORDSTROM:
21
22
23
Q
A
Q
Good afternoon.
Good afternoon, Ms. Nordstrom.
Turning your attention to page 10 of your
24 testimony, lines 20 and 21, you state that it would not.25 be proper to set a fair rate of return based on financial
CSB REPORTING
[phone]
2138 KAHAL (X)
Department of Energy
.1 crisis conditions which will likely be temporary . Given
2 that Idaho Power has indicated in Mr. Gale's rebuttal
3 testimony that it is currently evaluating a 2009 filing,
4 isn't it appropriate to use current market conditions to
5 formulate rates that will likely be in effect for next
6 year?
7 A If you mean current market conditions as
8 of today as opposed to the test year itself, the answer
9 is no. I don't believe that would be appropriate. I
10 believe that the Commission should rely upon the evidence
11 that's filed in this case. In my case, that represents
12 evidence that goes through market conditions extending
.13 through the end of September. I think that Ms. Carlock
14 may have used something similar and the Company, Dr.
15 Avera, presented whatever he presented, but I believe
16 that the Commission should rely on the evidence in this
17 case that is representative of the test year rather than
18 the Commission focusing on conditions during a very short
19 period of time, which I think is all that i s implicit in
20 your question, that in fact may be aberrant.
21 We're setting permanent rates here and
22 it's not proper to set permanent rates on data that I
23 think are hi90lY abnormal. In addition to the fact
24 they're highly abnormal, they're extremely difficult to.25 interpret and then I have some different interpretations
CSB REPORTING
[phone]
2139 KAHAL (X)
Department of Energy
.
.
.
18
1 of that than your witnesses.
2 Q So what you're saying is the fact that
3 Idaho Power is going to file another rate case in short
4 order has no bearing on your opinion?
5 A Excuse me, no bearing on what?
6 Q Your opinion.
7 A My opinion with regard to my
8 recommendation, right. My recommendation is based upon
9 the cost of capital studies and analyses that I've
10 conducted in this case. That's what it's based on. I
11 can't know whàt the Company is going to do next year.
12 That's totally at the Company's discretion as to whether
13 they want to file a rate case or not. I don't believe
14 that's a basis for me to change my recommendation or for
15 any witness to change their recommendation because that's
16 simply unknowable.
17 MS. NORDSTROM: No further questions.
19 have question~?
COMMISSIONER SMITH: Mr. Boehm, do you
20
21
MR. BOEHM: No questions, Your Honor.
22 from the Commission? Nor I.
COMMISSIONER SMITH: Do we have questions
23
24
25
Do you have redirect?
MR. BRUDER: I have one question, if I
may.
CSB REPORTING
[phone]
2140 KAHAL (X)
Department of Energy
.
.
1 REDIRECT EXAINATION
2
3 BY MR. BRUDER:
4 Q Mr. Kahal, your testimony mentioned
5 present conditions in financial markets and the
6 condi tions which are described in this filing of awhile
7 back have continued since the testimony was filed. In
8 light of those market conditions, do you continue to
9 support the recommendations that are stated in that
10 prefiled testimony?
11 A Yes, I do. I think that we all recognize
12 that there is something of a financial crisis, even
13 though there has been some progress made in stabilizing
14 markets to some extent, but it's still a very serious
15 financial situation and in addition to that a very
16 serious economic downturn.
17 Q In light of that, could you explain why
18 your recommendation remains the appropriate one?
19 A Yes. As I responded to Ms. Nordstrom, I
20 believe that the Commission should rely upon the cost of
21 capi tal studies that have been submitted in this case.
22 My own studies would support a -- if you went to the mid
23 point, it would support a return in the low 10' s,
24 al though I believe it's reasonable to consider a return.25 as high as 10.5 percent, but that's what those studies
CSB REPORTING
[phone]
2141 KAHAL (Di)
Department of Energy
.
.
.
1 show. That's what we have in the record in this case.
2 That's what the evidence shows, but even if I were to
3 update this, for example, using market data going through
4 November which is the last completed month, that really
5 wouldn't change things very much. That would only
6 slightly raise my DCF results. It would still keep them
7 below 10.5 percent and in fact, the capital asset pricing
8 model results, those would actually fall if one were to
9 do an update as I think Dr. Avera explained.
10 Furthermore, the crisis conditions in
11 capi tal markets make it very, very difficult during these
12 very abnormal times to apply models like the DCF and CAPM
13 which are equilibrium models. I don't believe markets
14 actually are in equilibrium. The underlying assumption
15 of those models is that asset prices reflect the
16 underlying intrinsic economic value of those assets.
17 That's not what's going on. That's not what's been going
18 on for the last two months.
19 , What's been going on is what's called
20 technical selling; that is, financial institutions being
21 forced to sell assets as part of a de-leveraging process
22 due to redemptions in mutual funds and that sort of
23 thing. The forced selling has driven down asset prices,
24 and notwithstanding that, as I look at companies like
25 IDACORP, the parent of Idaho Power, they still held up
CSB REPORTING
[phone]
2142 KAHAL (Di)
Department of Energy
.1 reasonably well. The prices have gone down a little bit,
2 but not very much. In fact, when I just recently looked
3 at IDACORP, its dividend yield was around 4.1 percent or
4 maybe it's 4.2 percent.
5 The dividend yield I had for IDACORP in my
6 testimony based upon the second and third quarters of
7 this year was 4.0 percent. That's really not much of a
8 change. In fact, it's been a pretty good year for Idaho
9 Power and IDACORP. I think that it's also important to
10 understand when we look at this financial crisis that
11 al though asset prices have gone down and we've had these
12 problems with forced selling and the loss of confidence
13 by investors and all this sort of thing that we're also.14 facing an outlook of virtually non-existent inflation.
15 The inflation' outlook I may have said in my testimony was
16 two percent, but really today it's closer to one percent
17 going forth. That's what we're looking at for
18 inflationary expectations. That's good for the cost of
19 capital. That low inflation is going to drive down the
20 cost of capital when we come out of this crisis.
21 I don't see how anyone can say that over
22 the last six months or even over the last year Idaho
23 Power's risk profile has increased. It's not a riskier
24 company than it was six months ago or a year ago and some.25 people might argue that it's even less risky. Finally,
CSB REPORTING
[phone]
2143 KAHAL (Di)
Department of Energy
.
.
.
1 this financial crisis and economic recession, I can
2 understand how large corporations like Idaho Power can
3 see this is a problem, but it's also a problem for the
4 customers of Idaho Power, the businesses and consumers
5 and an increase in the rate of return beyond a range of
6 the 11.25 or the 11.5 that I've suggested as maybe an
7 upper bound, that kind of an increase is unnecessary,
8 it's unsupported by the evidence and I just don't see a
9 reason to burden consumers further with a high allowed
10 rate of return given what businesses and consumers are
11 already facing today.
12 MR. BRUDER: Nothing further. Thank
13 you.
14 COMMISSIONER SMITH: Since that seemed a
15 lot like additional direct, is there any cross on his
16 response?
17
18
MS. NORDSTROM: No, thank you.
19 much.
COMMISSIONER SMITH: Okay, thank you very
20 (The witness left the stand.)
21 COMMISSIONER SMITH: Moving right along, I
22 think, Ms. Nordstrom, we're back to you.
23 MS. NORDSTROM: The state calls Steven
24 Keen as its next witness. Sorry, I was a prosecutor for
25 a lot of years and old habits die hard.
CSB REPORTING
[phone]
2144 KAHAL (Di)
Department of Energy
.
.
.
1
2
STEVEN R. KEEN,
produced as a witness at the instance of the Idaho Power
3 Company, having been first duly sworn, was examined and
4 testified as follows:
5
6
7
8 BY MS. NORDSTROM:
9 Q
DIRECT EXAMINATION
Good afternoon.
Good afternoon.
12 name for the record.
Please state your name and spell your last
17
10 A
My name is Steven R. Keen. Last name is
By whom are you employed and in what
I am the vice president and treasurer for
18 Idaho Power Company.
19
11 Q
Are you the same Steven Keen that filed
20 direct testimony on June 27th, 2008 and prepared Exhibit
13 A
21 Nos. 27 through 28?
22
23
14 K-e-e-n.
Yes, I am.
Did you also file rebuttal testimony on
24 December 3rd, 2008?
25
15 Q
Yes, I did.
16 capacity?
A
Q
A
Q
A
CSB REPORTING
[phone]
2145 KEEN (Di)
Idaho Power Company
.
.
.
1 Q Did you have any exhibits with your
No.
Do you have any changes or corrections or
5 updates to your testimony or exhibits?
2 rebuttal?
I do not.
If I were to ask you the questions set out
8 in your prefiled testimony, would your answers be the
3 A
They would.
MS. NORDSTROM: I would move that the
12 pre filed direct and rebuttal testimony of Steven Keen be
4 Q
13 spread upon the record as if read and that Exhibits 27
19 record.)
6 A
7 Q
14 and 28 be marked for identification.
CSB REPORTING
[phone]
COMMISSIONER SMITH: Without obj ection, it
17 (The following prefiled direct and
9 same today?
10 A
11
15
16 is so ordered.
18 rebuttal testimony of Mr. Steven Keen is spread upon the
20
21
22
23
24
25
2146 KEEN (Di)
Idaho Power Company
.
.
.
1 Q.Would you state your name, address, and present
2 occupation?
3 A.My name is Steven R. Keen and my business
4 address is 1221 West Idaho Street, Boise, Idaho. I am
5 employed by Idaho Power Company as Vice President and
6 Treasurer.
7 Q.What is your educational background?
8 A.I graduated with high honors in 1981 from Idaho
9 State Uni versi ty, Pocatello, Idaho , receiving a Bachelor
10 of Business Administration degree in Accounting. I have
11 also attended numerous seminars and conferences on
12 accounting and finance issues related to the utility
13 industry. I am a Certified Public Accountant licensed in
14 the State of Idaho.
15 Q.Would you please describe your business
16 experience with Idaho Power Company?
17 A.I joined Idaho Power Company (" Idaho Power" or
18 the "Company") in September, 1982, in the Property
19 Accounting Department. In March 1983, I transferred to
20 the Tax Department as a Tax Accountant. From that time
21 through December 1998, I advanced through every position
22 in the Tax Department including Property Tax
23 Representative, Tax Research Coordinator, and, finally,
24 Corporate Tax'Director. In January 1999, I became
25 President of IDACORP Financial
2147 S. KEEN, DI 1
Idaho Power Company
.
.
.
1 Services. In June of 2006, I accepted the position of
2 Vice President and Treasurer of Idaho Power Company and
3 IDACORP, Inc.,
4 In the course of my duties with Idaho Power
5 Company, I presented testimony in Idaho Power's last
6 general rate case in Idaho, Case No. IPC-E-07-08. I have
7 also presented tax testimony to the Internal Revenue
8 Service as well as tax and/or capitalization rate
9 testimony to the Departments of Revenue and Taxation for
10 Idaho, Oregon, Wyoming, and Nevada.
11 Q.What are your duties as Vice President and
12 Treasurer of Idaho Power as they relate to this
13 proceeding?
14 A. I oversee the direct financial planning,
15 procurement, and investment of funds for Idaho Power, as
16 well as supervise corporate liquidity management.
17 My duties and responsibilities include various
18 aspects of all the Company's financings and other
19 financial matters. With respect to long-term financings,
20 sale of bonds' and equity, my duties include development
21 of financial plans with senior officers, meeting with
22 representatives of investment banking firms that are
23 interested in underwriting Idaho Power securities,
24 discussions with credit rating agencies, assisting in
25 preparation of financial material including Registration
2148 S. KEEN, DI 2
Idaho Power Company
1 Statements filed with the Securities and Exchange.2 Commission,representing the Company at
3
4 /
5
6 /
7
8 /
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
2149 S. KEEN, DI 2a
Idaho Power Company
.
.
.
1 information meetings for investment banking firms,
2 reviewing information relative to the Company's
3 financings and recommending disposition of net proceeds.
4 Wi th respect to short-term financings, these duties and
5 responsibili ties include negotiation of lines of credit
6 wi th commercial banks and overseeing the sale of
7 commercial paper.
8 Q.Do your responsibilities include communication
9 wi th members of the financial community?
10 A.Yes. I am in continuous contact with
11 individuals representing investment and commercial
12 banking firms, credit rating agencies, insurance
13 companies , institutional investment firms, and other
14 organizations interested in publicly traded securities
15 that actively follow IDACORP and Idaho Power Company. In
16 association with the Company's Chief Financial Officer
17 and the Director of Investor Relations, my
18 responsibilities include keeping these persons informed
19 of the Company's financial condition, arranging meetings
20 with these people and Idaho Power's senior executive
21 management, and visi ting with financial representatives
22 in their respective offices. Some of these members of
23 the investment community have followed the electric
24 utility industry for an extended period of time and have
25 a great deal of expertise in the financial problems and
prospects of utilities.
2150 S. KEEN, DI 3
Idaho Power Company
.
.
.
1 Through my continual contact with the financial
2 communi ty and review of investment banking analytical
3 reports and articles issued by these firms and the rating
4 agencies, I am able to keep informed on trends, interest
5 rates, financing costs, security ratings, and other
6 financial developments in the public utility industry.
7 Q.Are you a member of any professional societies
8 or associations?
9 A.Yes. I am a current member and past board
10 president of the Idaho Society of Certified Public
11 Accountants. I am a current member of and past council
12 member of the American Institute of Certified Public
13 Accountants. I am a current member and past board
14 chairman of the Associated Taxpayers of Idaho. I am also
15 the current chairman of the Board of the Idaho Tax
16 Foundation. I am a member of the Idaho Association for
17 Financial Professionals.
18 I also receive information from attendance at
19 conferences and seminars of these and other utility
20 professional groups such as the Edison Electric
21 Insti tute. Through participation in these events, I gain
22 addi tional insights into the financial developments
23 affecting Idaho Power Company as well as the electric
24 utility industry.
25
2151 S. KEEN, DI 4
Idaho Power Company
.
.
.
15
1 Q.What is the purpose of your testimony in this
2 proceeding?
3 A.I am sponsoring testimony as to the point
4 estimate for Idaho Power Company's rate of return on
5 common equity and the embedded cost of long-term debt,
6 risk factors generally and that are unique to Idaho Power
7 Company, the use of a forecasted year-end 2008 capital
8 structure, and the resultant overall cost of capital used
9 to compute the Company's revenue requirement.
10 Q.What exhibits are you sponsoring?
11 A.I am sponsoring Exhibits numbered 27 and 28.
12 COST OF EQUITY POINT ESTIMATE
13 Q. What return on equity are you recommending in
14 this proceeding?
A.I have selected 11.25 percent as the point
16 estimate for cost of equity for the Company.
17 Q.Does that point estimate align with the
18 recommendations made by the Company's cost of capital
19 wi tness Mr. Avera?
20 A.It does. The Company's expert witness has
21 recommended a range of between 10.8 and 11.8 percent,
22 excluding the effects of flotation. I have selected a
23 percentage within his recommended range that I believe is
24 appropriate given the concepts put forth by the Company
25 in
2152 S. KEEN, DI 5
Idaho Power Company
.
.
.
1 this case. Elements of our submitted case include
2 requests for reduced regulatory lag and accelerated cash
3 recovery for the carrying cost of a portion of
4 Construction Work in Progress ("CWIP"). Both of these
5 proposals, if accepted by the Commission, would tend to
6 lower the Company's risk profile and warrant a cost of
7 equi ty below the upper end of Mr. Avera's range.
8 Q.If those concepts are not accepted and not
9 included in a final rate order would that impact your
10 recommendation on the point estimate?
11 A.Yes. Wi thout those enhancements I would be
12 recommending a point estimate higher in Mr. Avera's
13 recommended range.
14 Q. Are'there other issues that could potentially
15 influence your recommendation?
16 A.Yes. There are planned workshops focusing on
17 various issues that impact the Company's ability to earn
18 its allowed rate of return. The impacts of the Load
19 Growth Adjustment Rate ("LGAR") will be addressed along
20 wi th certain other potential changes to the Power Cost
21 Adjustment ("PCA") mechanism. If these issues are
22 resol ved in a manner that lessens the negative impacts on
23 the Company, my recommended cost of equity would move
24 lower. If the outcome of these workshops significantly
25 reduces the
2153 S. KEEN, DI 6
Idaho Power Company
.
.
.
1 Company's exposure to the variability of power supply
2 costs and the Company is no longer penalized for bearing
3 the burden of accommodating growth in our service
4 terri tory, I could support a lower cost of equity wi thin
5 Mr. Avera's recommended range. However, that
6 recommendation could only be made if the workshops result
7 in a favorable order to the Company that lowers risk.
8 RISK FACTORS
9 Q.Could you briefly outline what conditions
10 require a return on common equity of 11.25 percent?
11 A.Yes. I will summarize them here and discuss
12 them in greater detail later in my testimony. In
13 addition to the reasons advanced by Mr. Avera, I believe
14 that, at a minimum, an 11.25 percent return on equity is
15 required to properly account for the risks confronting
16 Idaho Power Company, namely: (1) the significant
17 variabili ty in power supply costs that exists due to a
18 predominately hydroelectric generating base subj ect to
19 the uncertainties of weather and water, (2) the effects
20 of pricing changes in a volatile wholesale power supply
21 market in the Western United States and specifically the
22 Northwest, coupled with its effect on the PCA mechanism
23 (3) the impacts related to the current methodology
24 utilized in the LGAR in the PCA, (4) the persistence of
25 water issues and water litigation in
2154 S. KEEN, DI 7
Idaho Power Company
.
.
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1 Idaho, (5) the renewal of federal licenses for the
2 Company's hydroelectric proj ects, primarily the Hells
3 Canyon Complex, which provides 40 percent of the
4 Company's total generating capacity and particularly the
5 significant cost of relicensing that proj ect, (6) the
6 impact of Qualified Facility ("QF") related expenditures,
7 (7) the inability of the Company to recover the
8 significant capital investment required for present and
9 growing electrical requirements and service reliability
10 for its customers on a timely basis, (8) the general
11 decline in credit quality of the Company, and (9) the
12 inabili ty of the Company to earn an actual return on
13 capi tal that is anywhere near a reasonable allowed rate
14 of return.
15 Q.Are some of these risk conditions the same risk
16 conditions that have been raised in past Idaho Power rate
17 proceedings?
18 A.Yes. These risks still exist and the passage
19 of time has exacerbated their potential impact on the
20 Company.
21 Q.Are there other risks, less specific to Idaho
22 Power Company, that also impact your recommendation?
23 A.Yes. There are general financial risks such as
24 increased volatility in the financial markets and what I
25 view as a heightened sensi ti vi ty to risk exposure that
has
2155 S. KEEN, DI 8
Idaho Power Company
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20
1 evol ved since the U. S. housing market began experiencing
2 problems in 2007. There are also industry specific
3 risks, such as unknown costs relative to carbon
4 emissions, an industry-wide need for infrastructure
5 improvements, and increased capital investment as well as
6 inflationary pressures that increase costs of both
7 operating expenses and capital outlays. All of these
8 factors combine to make a challenging environment in
9 which the Company must compete with others in the
10 electric utili ty industry~ for both resources and
11 capi tal, to serve the needs of its customers and
12 shareowners. While I do not intend to elaborate further
13 on these risk areas, they are factors worthy of notation
14 that point to an increased level of risk exposure for the
15 Company.
16 1.Hydro Variability
17 Q.Please describe the risks specific to Idaho
18 Power's predominately hydroelectric generating base which
19 is subj ect to the uncertainties of weather and water.
A.Idaho Power Company and its customers have
21 historically enj oyed the benefits of a
22 hydroelectric~based utility. The availability of
23 hydroelectric power depends on the amount of snow pack in
24 the mountains upstream of Idaho Power's hydroelectric
25 facili ties, reservoir storage, springtime snow pack
run-off, rainfall and other weather
2156 S. KEEN, DI 9
Idaho Power Company
.
.
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1 and stream flow management considerations. During low
2 water years, when stream flows into Idaho Power's
3 hydroelectric proj ects are reduced, Idaho Power's
4 hydroelectric generation is reduced. Extreme
5 temperatures increase demand for power by customers who
6 use electricity for cooling and heating, and moderate
7 temperatures decrease demand for power . Precipitation or
8 the lack thereof also directly affects the Company's
9 irrigation load. Weather and hydro-production are
10 inextricably linked. Reduced hydroelectric generation
11 resulting from below normal water flows requires the
12 Company to use more expensive thermal generation and/or
13 purchased power to meet the electrical needs of its
14 customers.
15 2.Pricing Volatility and the PCA
16 Q.Does the Company's PCA remove this weather and
17 water risk?
18 A.Not entirely. Although the Idaho Commission
19 grants recovery for the majority of the variations in
20 power supply expense through the Company's peA, the
21 recovery is less than 100 percent. Although originally
22 viewed by the Company as an earnings stability mechanism,
23 the PCA has provided less stability than anticipated.
24 The risks associated with the Idaho jurisdictional 10
25 percent of variations in power supply expenses (the
portion the
2157 S. KEEN, DI 10
Idaho Power Company
.
.
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1 Company's shareholders are required to absorb) are having
2 an increasingly significant adverse financial impact on
3 the earnings capability of the Company. Actual results
4 no longer provide the level of earnings stability
5 originally contemplated by the Company.
6 Q.Why have the earnings stability benefits of the
7 PCA to the Company declined?
8 A.While I do not profess to be an expert on the
9 details of the PCA mechanism, from a financial
10 perspective, I can identify one very significant factor
11 affecting the PCA that has materially affected earnings
12 stabili ty.
13 Q.Please elaborate.
14 A.The Commission in 1993 authorized a PCA
15 mechanism with the principal parts being fuel expenses, a
16 deduction for surplus sales, purchased power expenses,
17 and an adjustment to compensate for the difference
18 between actual load and the load used to establish base
19 rates.
20 At the time the PCA was established in 1993,
21 there was a fundamental relationship between FERC
22 jurisdictional rates for purchases and sales and Idaho
23 Power retail rates. All of the prices or rates were
24 cost-based.
25 In 1997, FERC determined that it would permit
market-based rates as opposed to cost-based rates. While
2158 S. KEEN, DIll
Idaho Power Company
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1 Idaho retail rates remained cost based, FERC
2 jurisdictional rates for sales and purchases became
3 market based. The cost or price for both FERC
4 jurisdictional power purchases and sales attributable to
5 Idaho Power increased significantly. This created an
6 enormous difference between the monetary amounts for
7 purchased power and surplus sales that the parties
8 considered in 1992 and 1993 when the PCA methodology was
9 established and the costs and prices experienced in
10 recent years. This volumetric change is truly monumental
11 when you consider the financial size of Idaho Power.
12 Company witness Said informed me that average Idaho Power
13 purchases for the period 1993 though 1996 were at an
14 average expense of $22,389,000 per year. For the period
15 1997 through 2007, the average Idaho Power purchases were
16 at an average expense of $217,265,000. Likewise, surplus
17 sales for the period 1993 through 1996 were at an average
18 revenue of $42,060,000. For the period 1997 through
19 2007, the average sales were at an average revenue of
20 $186,711,000.
21 Q.Did you ask Mr. Said to provide you with
22 information as to the decline in PCA earnings stability
23 benefits since the inception of the PCA due to increased
24 prices?
25
2159 S. KEEN, DI 12
Idaho Power Company
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1 A.Yes. Mr. Said has informed me that at the time
2 of the inception of the PCA, the Company, interested
3 parties, and the Commission envisioned power supply
4 expenses would vary $120 million from a high-water
5 scenario to a low-water scenario. Wi th base rates set at
6 the mean of the range and 90 percent sharing by
7 customers, the Company's exposure to adverse water power
8 supply expenses was $6 million (1/2 * $120 million * 10
9 percent = $6 million) .
10 Mr. Said also informed me that the range of
11 power supply expenses from a high-water scenario to a
12 low-water scenario is now $290 million. Using the same
13
14
computation I just presented, the Company's current
exposure to adverse water is $14.5 million (1/2 * $290
15 million * 10 percent). That means that the risk exposure
16 today is 2.4 times as great as it was at the time the PCA
17 was adopted. 'This increased dollar amount that is at
18 risk should be recognized in the Company's return on
19 equity in light of FERC market-based rates and how those
20 purchase power costs are calculated and treated in the
21 Idaho PCA mechanism.
22 Q.Does your recommended 11.25 percent return on
23 equity reflect this increased risk to the Company based
24 upon the expanding range of power supply expense
25 possibilities?
2160 S. KEEN, DI 13
Idaho Power Company
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1 A. I allowed for the increased volatility in the
2 markets, assuming the current PCA operates as ordered in
3 the Company's most recent general rate case. In doing
4 so, I am assuming there remains a possibility in the
5 future for the PCA mechanism to be symetrical and for
6 both benefit and cost sharing to occur. However, if the
7 PCA requires the shareowners to absorb 10 percent of the
8 costs every year resulting from weather and escalating
9 market prices, my recommended return on equity is too
10 low.
11 Q.If the PCA only results in cost sharing
12 (recovering less than 100 percent of its power supply
13 costs) going forward, as it has for each of the last
14 eight years, is your recommended return sufficient to
15 attract capital at reasonable prices?
16 A.No. '
17 3.LGA Implications
18 Q.On January 9, 2007, the Commission issued Order
19 No. 30215 concerning the LGAR in the PCA mechanism. Are
20 you aware of that order?
21
22
A.Yes.
Q.How was that Order received by the financial
23 community?
24
25
A.It heightened their concern that the Company
will be unable to earn its allowed rate of return. A. G.
2161 S. KEEN, DI 14
Idaho Power Company
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1 Edwards & Sons, Inc., issued a research report on
2 February 16, 2007, stating: "The revised LGAR mechanism
3 and use of the historical test years in rate cases makes
4 it difficult for IDA to earn its allowed ROE in periods
5 of strong customer and rate base growth." A similar
6 report from Wachovia Capital Markets, LLC, on February
7 15, 2007, states:
8 Wi th the resulting regulatory lag and
reduced prospects for Idaho Power to
9 recover its authorized return on equity,
in our view, the decision reduces10 confidence in the regulatory backdrop,
especially as the Company begins to enter11 a new base-load build cycle. Moreover,
more frequent rate case filings equate to12 more cost, more time, and more
uncertainty.
13
14 Q.In Order No. 30215, did the Commission discuss
15 the relationship between the load growth adj ustment and
16 the return on equity?
17 A.Yes. In that Order, the Commission stated:
18 "CB) ecause this process (the adjustment of load growth
19 recovery) puts the Company at some business and financial
20 risk, it is awarded a commensurate equity return."
21 (Order No. 30215 at p. 10).
22 Q.What does the Commission's statement mean to
23 you?
24
25
2162 S. KEEN, DI 15
Idaho Power Company
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1 A.It communicates to me that the additional risks
2 borne by the Company due to the denial of load growth
3 costs are to be offset by a commensurate equity return.
4 As the load growth adjustment rate increases, the return
5 on equity component must also increase.
6 Q.On February 28, 2008, the Commission issued
7 Order No. 30508 ordering a change in the Company's base
8 rates. Are you aware of that order?
9 A. Yes.
10 Q. How did that order address the LGAR in the PCA
11 mechanism?
12 A.Order No. 30508 adopted the relevant portions
13 of a settlement stipulation which essentially did two
14 things relative to the LGAR. The parties to the
15 stipulation agreed "to make a good-faith effort to
16 develop a mechanism to adjust or replace the current LGAR
17 to address the costs of serving load growth between rate
18 cases. " In addition, for the 2008 PCA, it was decided
19 that "the LGAR will be $62.79 per MWH applied to one-half
20 of the load growth occurring during each month within the
21 PCA year."
22 How was that Order received by the financialQ.
23 community?
24
25
2163 S. KEEN, DI 16
Idaho Power Company
.
.
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1 A.It was viewed as somewhat posi ti ve but
2 inadequate. It did not fully settle certain issues, such
3 as the LGAR, in a manner that lessened the impacts on the
4 Company. When the proposed settlement was announced,
5 Standard and Poor's responded by lowering the corporate
6 credi t ratings for both Idaho Power and IDACORP from BBB+
7 to BBB. Additionally, both Fitch Ratings and Moody's
8 Investors Service made reference to short-comings in the
9 PCA mechanism and negative impacts from the load growth
10 adj ustment as contributing to their negative ratings
11 outlooks later in 2008.
12 RBC Capital Markets also made reference to both
13 the settlement and the load growth issues in their
14 February 14, 2008, Equity Research Company Update. Under
15 a column headline of "Disappointing rate case settlement
16 leaves important questions unresolved," they stated:
17 . . changes to the LGAR mechanism and
discussions about a forecasted test year18 were tabled pending further discussions.
S&P downgraded IDA to BBB from BBB+ due to19 the pending rate case outcome and its
impact on cash flows.
20
21 RBC Capital Markets also indicated additional concern
22 about the load growth adjustment mechanism stating: "The
23 current Load Growth Adjustment Mechanism (LGAR) in place
24 essentially punishes IDA for this growth."
25
2164 S. KEEN, DI 17
Idaho Power Company
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1 Q. Does your rate of return recommendation reflect
2 the financial community's concerns regarding the load
3 growth adjustment?
4 A.My rate of return is intended to reflect the
5 Company's current level of risk. At 11.25 percent, the
6 return is higher than the Company's prior authorized rate
7 of return and the changes to load growth-related power
8 costs have contributed to that increase. My recommended
9 rate of return on common equity would need to be
10 increased further if the upcoming load growth adjustment
11 workshops were to result in the Company bearing any
12 greater portion of the costs associated with serving
13 increases in customer load. Likewise, a reduction in, or
14 removal of, the Company's exposure to load growth related
15 costs would allow for a reduction in my recommended
16 return on common equity rate and would be welcomed by the
17 financial community. I would expect a favorable change
18 in this risk category to be noticed in future Company
19 ratings actions and the credit rating is a key component
20 of determining the cost of future debt issuances.
21 4.Water Issues
22 Q.Are, there any other water or weather-related
23 risks of the Company that you would like to comment on?
24
25
2165 S. KEEN, DI 18
Idaho Power Company
.
.
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1 A. Yes. Comments from credit rating agencies and
2 analysts have expressed concern about the potential
3 impacts from aquifer recharge and water rights. Reliance
4 on hydro generation in general has come under scrutiny
5 with recent history delivering so many below-normal water
6 years in our region. While it is difficult to quantify
7 potential exposures, the heightened level of discussions
8 and disagreements wi thin the state on these issues have
9 increased the Company's risk profile in the financial
10 community.
11 Q.Has, anyone in the financial community tried to
12 quantify the risks relative to hydro exposure for the
13 Company?
14 A. Yes. While all of the rating agencies and much
15 of the equity analyst community have commented on the
16 significant level of risk the Company faces in regard to
17 its high reliance on hydro power, Standard & Poors
18 actually reviewed the hydro issue specifically for
19 Northwest utilities.
20 On January 28, 2008, Standard & Poors issued a
21 report titled "Pacific Northwest Hydrology And Its Impact
22 On Investor-Owned Utili ties' Credit Quality." This
23 report took an in-depth look at hydro implications for
24 investor owned utilities in the Northwest. In regard to
25 Idaho Power
2166 S. KEEN, DI 19
Idaho Power Company
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10
11
1 specifically, Standard & Poor's stated that "Idaho
2 Power's regulatory mechanisms are strong, relative to the
3 other companies in our survey, but not strong enough to
4 overcome significant exposure to the variable flows of
5 the Snake River." They went on to indicate the financial
6 implications to the Company related to this and other
7 factors as described below:
8 Despi te having both a PCA and an update
process, the mechanisms have not been able
to fully insulate the company from the
highly variable and generally low flow
conditions that have persisted on the
Snake River for the greater part of thepast decade. Idaho Power's financial
performance has been also hampered by a
load growth adjustment mechanism that has
resulted in a cash loss on new customers,
and regulatory lag due to the use of a
historical test year for the non-fuel
component of rates.
9
12
13
14
15 Relicensing the Hells Canyon Complex5.
16 Please describe the risks regarding the renewalQ.
17 of federal licenses for the Company's hydroelectric
18 projects.
19 Idaho Power Company is the only investor-ownedA.
20 electric utility in the United States with 55 percent of
21 its generation derived from hydro generating facilities
22 under normal water conditions. With such a large portion
23 of the Company's generation resources based on hydro
24
25
2167 S. KEEN, DI 20
Idaho Power Company
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1 facili ties, a negative result from efforts to renew the
2 federal licenses of these facilities could have a
3 significant financial impact on the Company and the
4 prices its consumers pay for electricity. Because of its
5 importance, the Company has committed to expend
6 significant financial and human resources to obtain new
7 licenses for its hydro generating capacity from the FERC.
8 What are the associated financial risks to theQ.
9 Company from relicensing its hydro generating capacity?
10 Once an application is filed, the time frame toA.
11 actually receive an order from the FERC is unknown. This
12 uncertainty combined with the potential loss of
13 generation capability due to operational changes, and the
14 magnitude of the financial impact of unknown Protection,
15 Mitigation, and Enhancement ("PM&E") costs are financial
16 risks to the Company.
17 Are there other hydro relicensing-basedQ.
18 financial risks considered by the investment community?
19 Yes. For any particular generating facility,A.
20 the worst possible outcome would be the loss of the
21 license to a competing party. Along with the uncertainty
22 as to the eventual receipt of licenses and the costs
23 involved in preparing for the license applications, costs
24 of PM&E related to these projects are also difficult
25
2168 S. KEEN, DI 21
Idaho Power Company
.
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1 to quantify. The potential financial magnitude of these
2 PM&E and their effect on the Company's low-cost hydro
3 generation resources threaten the financial stability of
4 a company the size of Idaho Power and the ultimate rates
5 it must charge its customers. These amounts will vary
6 between each facility; however, in all cases, they can be
7 significant due to lost generation capacity, generation
8 at a higher cost, and the decreased ability of the
9 Company to time and control water releases.
10 If the Company cannot generate when it is most
11 advantageous for the system, then some of the economic
12 value of the generation has been lost even if the amount
13 of total generation does not change. In addition to the
14 hydro relicensing risk, the Company continually faces
15 significant capital, operating, and other costs relating
16 to compliance with current environmental statutes, rules,
17 and regulations. These costs may be even higher in the
18 future as a result of, among other factors, changes in
19 legislation and enforcement policies and the potential
20 additional requirements imposed in connection with the
21 relicensing of the Company's hydroelectric proj ects.
22 Please address the risk specifically associatedQ.
23 with the Company's relicensing effort before the FERC for
24 the Hells Canyon generating facilities.
25
2169 S. KEEN, DI 22
Idaho Power Company
.
.
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1 A. The Hells Canyon generating facilities
2 comprised of Hells Canyon, Oxbow, and Brownlee dams make
3 up 67 percent of the Company's hydro generation capacity
4 and 40 percent of its total generation capacity. The
5 Hells Canyon license application was filed in July 2003
6 and accepted by the FERC for filing in December 2003.
7 The FERC process moves at a slow and deliberate pace due
8 to the large number of interested parties involved in
9 evaluating the application, thus the timing of the
10 issuance of a new Hells Canyon facilities license remains
11 uncertain. Historically, FERC has given the Company an
12 annual license renewal (under the existing old license)
13 until the formal new license is issued. It is difficult
14 to predict the ultimate financial impact of the relicense
15 until the new FERC license is issued and all of the
16 relicense conditions are known.
17 Please comment on the relicensing efforts thatQ.
18 the Company has already undertaken.
19 As part of the FERC relicensing regulations andA.
20 pursuant to the Federal Power Act, the Company is
21 required to conduct numerous studies and evaluations
22 concerning botanical issues, land management issues,
23 hydraulic issues, flow modeling issues, sedimentary
24 issues, water quality issues, aquatic issues, recreation
25 issues,
2170 S. KEEN, DI 23
Idaho Power Company
.
.
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1 cul tural resource issues, and fish and wildlife issues.
2 Q. How does the Company account for the cost of
3 these proj ects?
4 Although Company witness Miller describes thisA.
5 in greater detail in her testimony, Idaho Power books the
6 proj ect costs to CWIP because they are part of the
7 relicensing process pursuant to FERC and state accounting
8 requirements. While the costs are included in CWIP, the
9 Company accrues a capitalization charge commonly referred
10 to as an Allowance for Funds Used during Construction
11 ("AFUDC"). The AFUDC is a non-cash item that represents
12 the cost of related debt and equity financing. The
13 component for AFUDC attributable to borrowed funds is
14 included as a' reduction to interest expense, while the
15 equi ty component is included in other income. The total
16 amount of AFUDC is charged to CWIP.
17 What will occur when the Company receives a newQ.
18 license for the Hells Canyon facilities?
19 The amounts in CWIP will be transferred toA.
20 plant in service and the accumulation of AFUDC will
21 cease. The result will be a large increase in rate base
22 with earnings, of the Company declining since there will
23 be no AFUDC. Because this is a relicense of an existing
24 hydro facility, there will be no increase (if not a
25 decrease due
2171 S. KEEN, DI 24
Idaho Power Company
.
.
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1 to operational changes) in the generation of power and
2 thus no increase in sales revenues. The financial
3 industry sees this as a risk that confronts the Company
4 which can be summarized as follows: upon receipt of a
5 relicense, (1) the Company's earnings will go down (no
6 AFUDC), (2) the Company's rate base will go up (transfer
7 from CWIP), and (3) no additional sales revenues (same
8 plant but new license). For the period of time the new
9 rate base is under review by the Commission, the Company
10 will earn no return on roughly $100 million of
11 investment. This lag combined with the potential for
12 some disallowance is a significant risk factor.
13 Q. The Company is suggesting certain changes in
14 the methodology surrounding AFUDC regarding CWIP balances
15 for relicensing. If adopted, will this remove the risk
16 that you refer to above?
17 No. The recommended change will keep this riskA.
18 factor from continuing to grow but it does not fully
19 remove the exposures described above. If accepted by the
20 Commission, the recommendation by Company witness Miller
21 will keep the CWIP balance related to relicensing from
22 growing but it does not deal with the large accumulation
23 of costs already in CWIP that will need to one day be
24 transferred to rate base. As of December 31, 2007, that
25
2172 S. KEEN, DI 25
Idaho Power Company
.
.
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1 balance was $ 95.6 Million.
2 6. QF Concerns
3 Does the regulatory treatment of energyQ.
4 purchases the Company makes from PURPA QFs increase the
5 financial risk to Idaho Power?
6 Yes. The regulatory treatment of QFA.
7 expendi tures provides for a one-for-one recovery of
8 dollars expended, but does not provide for a return to
9 compensate the Company for this acti vi ty. The Company
10 is, in effect, buying and selling energy pursuant to a
11 legal mandate, without any compensation for providing
12 this service. Simplistically, this regulatory treatment
13 is similar to requiring a person operating a business to
14 buy a product at the same price it must be sold. The
15 mere dollar-for-dollar recovery of QF expenditures, but
16 no return for the use of the Company's balance sheet and
17 liquidity in managing QF programs, is viewed as a
18 significant risk by the rating agencies. They are not
19 making a judgment related to the appropriateness of QF
20 energy purchase programs, but merely pointing out the
21 cost of the financial risk (s) arising from a QF
22 transaction, and that this risk should be reflected in a
23 higher return on equity to credit the Company for its QF
24 contracts.
25
2173 S. KEEN, DI 26
Idaho Power Company
.
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10
1 Q. Has the Commission previously considered a
2 proposal to compensate the Company for its management of
3 QF programs?
4 Yes. In determining the appropriate rates toA.
5 be paid for power and energy sold to Idaho Power pursuant
6 to section 210 of the PURPA Act of 1978, the Commission
7 through Order 18190 at page 21 indicated:
8 In another context, Staff witness Drummond
proposed that Idaho Power be given a
management fee amounting to five percent
of the gross payments made to CSPP' s
CQFs). The Commission will do all in its
power to encourage Idaho Power to manage
such proj ects in an orderly fashion.
Orderly management includes adequate
staffing and clear lines of authority
among personnel assigned to deal with
CSPPs; good faith negotiating of contracts
and expeditious processing of worthy
applications; and, above all, a showing
that the Company has integrated
cogeneration and small power resources
into its own planning, construction and
financing programs. When orderly
management is demonstrated, the Commission
will reconsider the question of an
appropriate management fee or an equity
adj ustment.
9
11
12
13
14
15
16
17
18
19
20 According to Company witness Said, the current expected
21 normalized cost for QF purchases is approximately $63.3
22 million. Utilizing a five percent management fee, as
23 recommended above by Staff witness Drummond, on these
24 normalized QF costs would result in a payment to the
25
2174 S. KEEN, DI 27
Idaho Power Company
.
.
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1 Company of approximately $3.165 million. Mr. Said
2 evaluated the impact of an additional $3.165 million of
3 required revenues and approximated that the increase
4 would correlate to an additional 20 basis points of ROE.
5 That increase would bring my recommended ROE to 11.45
6 percent.
7 Do the rating agencies recognize the financialQ.
8 costs of QF-related transactions?
9 Yes. Like other electric utilities, when theA.
10 Company adds to its rate base, it must use some portion
11 of shareholder equity to fund the investment. The
12 Company must maintain its proportion of equity to debt
13 above a certain level as it continues this investment
14 process. If it does not, the debt level increases and
15 the Company will face the threat of a bond rating
16 downgrade. Conversely, when the Company enters into a QF
17 contract for purchased power, an obligation not reflected
18 in its financial statements, an increase in equity is
19 needed to maintain credit quality. Unless an equity
20 component is provided to offset the debt-like obligation
21 of long-term QF purchase power contracts, the Company
22 faces off-balance sheet financial risk. For financial
23 commitments that do not appear on the balance sheet,
24 credit rating analysts impute the debt and interest
25 equivalents on the financial statements of the Company to
achieve a more accurate
2175 S. KEEN, DI 28
Idaho Power Company
.1 picture of the risk associated with their investment.
2 The added equity needed to offset this imputed debt and
3 interest represents the effect that long-term purchased
4 power commitments have on the cost of capital. Any
5 increase in the long-term obligation of a utility related
6 to its capacity and energy resources will have to be
7 backed by an appropriate amount of equity in the eyes of
8 the investment community.
9 In reviewing its evaluation of the credit
10 implications of QF-related expenditures, S&P in May of
.
. 25
11 2003, noted that such agreements are "debt-like in
12 nature" and that the increased financial risk must be
13 considered in evaluating a utility's credit risks.
14 Standard & Poor's Ratings Services views
electric utility purchased-power
agreements (PPA) as debt-like in nature,
and has historically capitalized these
obligations on a sliding scale known as a
"risk spectrum." Standard & Poor's
applies a 0% to 100% "risk factor" to the
net present value (NPV) of the PPA capacity
payments, and designates this amount as
the debt equivalent.
15
16
17
18
19
20 * * *
21 Standard & Poor's evaluates the benefits
and risks of purchased power by adjusting
a purchasing utility's reported financial
statements to allow for more meaningful
comparisons with utili ties that buildgeneration. Utili ties that buildtypically
22
23
24
2176 S. KEEN, DI 29
Idaho Power Company
.
.
.
10
1 finance construction with a mix
of debt and equity. A utility that leases
a power plant has entered into a debt
transaction for that facility; a capital
lease appears on the utility's balance
sheet as debt. A PPA is a similar fixed
commi tment. When a utility enters into a
long-term PPA with a fixed-cost component,
it takes on financial risk. Furthermore,utili ties are typically not financially
compensated for the risks they assume in
purchasing power, as purchased power is
usually recovered dollar-for-dollar as an
operating expense.
2
3
4
5
6
7
8
9 7.Growth and Timely Cost Recovery
Q.Please describe the risks relative to the
11 Company's ability to recover significant capital
12 investment required for present and growing electrical
13 requirements.
14 A. As the Company's generation and transmission
15 systems age and customer electrical requirements
16 increase, additional investment is required to meet
17 reliability standards and the additional demand on its
18 electrical infrastructure. The Company's latest forecast
19 projects a construction budget of between $270 to $290
20 million in 2008 and an approximate $900 million of new
21 construction expenditures over the three-year period of
22 2008 through 2010. The $900 million estimate excludes
23 any estimated expenditures related to certain large
24 transmission proj ects or costs associated with a base
25 load combined cycle
2177 S. KEEN, DI 30
Idaho Power Company
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1 combustion turbine that could increase construction costs
2 during this time frame. Construction investments of this
3 magni tude introduce two elements of risk: first, the
4 ability of the Company to attract the required capital
5 and, secondly, the recovery of these investments is on a
6 deferred basis and subj ect to the regulatory process.
7 Has the Company been able to earn itsQ.
8 authorized return on equity during recent years?
9 No. In fact, the Company's actual return onA.
10 equi ty has been less than 9 percent for the last five
11 years.
12 What has prevented the Company from earning itsQ.
13 authorized or allowed return on equity?
14 A. I have previously addressed in my testimony
15 several issues which I believe adversely impact the
16 Company's ability to earn its authorized return.
17 However, in my opinion, the reliance on historical test
18 year information is a primary reason the Company fails to
19 earn its authorized or allowed return on equity at this
20 time. I believe this opinion is universally held by
21 financial analysts that follow Idaho Power /IDACORP.
22 Idaho Power is in a consistent position of always
23 recovering it$ costs on a historical basis when its costs
24 are constantly increasing on a prospective basis. As a
25 resul t, there is a consistent
2178 S. KEEN, DI 31
Idaho Power Company
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1 recovery lag. As long as Idaho Power is building to meet
2 future demands while collecting rates based in the past,
3 it can never "catch-up."
4 What effect does growth have on the use ofQ.
5 historical data?
6 Growth inherently worsens the effects.A.
7 Operation & Maintenance ("O&M") expenses typically rise
8 faster than inflation as new facilities and personnel are
9 added to meet growing customer demands. Yet recovery is
10 based on lower historical costs and staffing levels from
11 a prior period. Likewise, the allowed rate of return is
12 applied to a rate base from a prior historical period and
13 new plant additions suffer some period of zero percent
14 return awaiting eventual rate base treatment.
15 8.Declining Credit Ratings
16 What is the status of Idaho Power Company'sQ.
17 credit ratings?
18
19
20
21
22
23
24
25
2179 S. KEEN, DI 32
Idaho Power Company
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. 25
1 A. Idaho Power Company's credit ratings as of June 20,
2 2008, are as follows:
3 S&P Moody's Fitch
Corporate Credit BBB Baa 1 None
Rating
Senior Secured Debt A-A3 A-
Senior Unsecured BBB-Baa 1 BBB+
Debt (prelim)
Short-Term Tax-BBB/A-2 Baa 1/None
Exempt Debt VMIG-2
Commercial Paper A-2 P-2 F-2
Credit Facility None Baa 1 None
Rating Outlook Stable Negative Negative
4
5
6
7
8
9 Standard & Poor's downgraded the Company'sQ.
10 credit rating in January of 2008. What prompted this
11 action?
12 Standard and Poor's lowered the corporateA.
13 credit ratings for both Idaho Power and IDACORP from BBB+
14 to BBB, citing cash flow concerns, the proposed general
15 rate settlement, and specifically mentioning the impacts
16 of load growth. Their research update on January 31,
17 2008, stated:
18 The rating action was driven by a gradual
deterioration of cash flow coverage and19 last week's proposed general rate case
settlement, which does not sufficiently20 address long-term ratemaking issues tied
to rising costs and load growth pressures.21 Over time, average credit metrics have
deteriorated, and the company has been22 unable to stabilize returns and cash flow
wi th existing rate mechanisms. The23 proposed settlement
24
2180 S. KEEN, DI 33
Idaho Power Company
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. 25
1 calls for an average 5.2% rate increase
but does not settle some important,
policy-related issues in the case, such as
the use of a forecasted test year or the
appropriate level of the load growth
adjustment credit.
2
3
4
5 Q.Have there been other ratings actions in 2008?
6 A.Yes. Both Fitch Ratings and Moody's Investors
7 Service recently changed their ratings outlooks for both
8 Idaho Power and IDACORP to "negative" from "stable" on
9 March 20, 2008, and June 03, 2008, respectively.
10 Q.Do you believe that the current credit ratings
11 of Idaho Power Company are adequate?
12 A.Other utili ties with the same credit ratings as
13 Idaho Power Company are able to raise capital in today' s
14 markets. However, these new debt/bond issues are at a
15 higher cost than if these utili ties had a higher credit
16 rating (the higher the credit rating, the lower the
17 cost). This results in passing on higher interest costs
18 to customers over the life of the bonds.
19 One large threat to Idaho Power Company's
20 current ratings is unforeseen risk. Should an unforeseen
21 event cause Idaho Power Company's short-term credit
22 ratings to be lowered, Idaho Power Company would no
23 longer be able to
24
2181 S. KEEN, DI 34
Idaho Power Company
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1 issue commercial paper. This would limit the options
2 Idaho Power Company has available to meet on-going cash
3 requirements, such as funding capital improvements and
4 paying for deviations in power supply costs, and would
5 likely result in higher interest costs to the customer.
6 The unforeseen risk has a potentially greater impact when
7 a company is closer to the bottom of what is considered
8 "investment grade."
9 Q.What is the lowest rating that is considered
10 investment grade?
11 A.For Standard & Poors that rating is BBB-.
12 Idaho Power's corporate credit rating is currently one
13 step above that bottom rating. Its senior unsecured debt
14 rating is actually at that bottom level and its secured
15 debt rating is currently at A-. A significant concern
16 for me, as the officer primarily responsible for
17 providing the Company's capital, is how close Idaho Power
18 is to the bottom of investment grade status. The concern
19 is only heightened by the need to raise increasing
20 amounts of capital in the near future for some
21 fundamental infrastructure improvements. The last time
22 Idaho Power faced this situation we carried much better
23 credit ratings than today.
24
25
2182 S. KEEN, DI 35
Idaho Power Company
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1 9.Reasonable Actual Results
2 Why do you think the rating agencies have takenQ.
3 their recent actions to reduce Idaho Power's credit
4 ratings?
5 I think the single largest contributor is theA.
6 fact that actual results have varied so significantly
7 from any type of expected return. Idaho Power's last
8 return on equity arising from the settlement of the 2005
9 general rate case was 10.6 percent and while several rate
10 actions have been completed since that time, the
11 approximate expectation for a regulated return has stayed
12 very close to that figure. Yet in actuality, the
13 realized returns have been far below that figure, not
14 reaching double digits since 2002.
15 Has the Company been able to earn its allowedQ.
16 return on equity in recent years?
17 No. During the years 2004 and 2005, IdahoA.
18 Power's autho~ized return on equity was 10.25 percent.
19 In those years the Company earned a return on equity of
20 7.2 percent and 7.7 percent, respectively. In 2006,
21 Idaho Power's actual return on equity was higher but
22 still barely over 9 percent in a year that enj oyed good
23 hydro conditions. In 2007, Idaho Power only earned an
24 actual return on equity of 6.9 percent. In fact, the
25 actual
2183 S. KEEN, DI 36
Idaho Power Company
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1 return on equity for the Company has not been above 10
2 percent since 2002 when the Company earned 10.9 percent
3 against an allowed return on equity of 11.5 percent.
4 Q.What drives this continual earnings short-fall?
5 A.I believe the primary contributors to be the
6 effects of regulatory lag and a combination of negative
7 impacts arising out of variability in hydroelectric
8 generation. Although I have addressed several other risk
9 factors in my testimony that also contribute to the
10 short-fall, I would like to emphasize that the financial
11 community and the recent ratings actions are looking very
12 directly at the actual results of Idaho Power's
13 regulatory efforts. They expect realized rates of return
14 to be near allowed levels, or at least occurring at or
15 above allowed levels as often as they fall below them.
16 The financial' community is also certainly looking for
17 more consistency in cash flows.
18 CAITAL STRUCTUR
19 Q.Would you please describe Exhibit No.2 7?
20 Exh~bi t No. 27 details the calculation of theA.
21 Idaho Power Company capital structure for long-term debt,
22 the common equity balance resulting from the Company's
23 forecasted year-end 2008 capital structure as
24
25
2184 S. KEEN, DI 37
Idaho Power Company
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1 provided to me by Ms. Lori Smith, and the resulting
2 overall rate of return that I am recommending.
3 The capital structure presented on Exhibit No.Q.
4 27 incorporates changes to the Company's financial
5 reporting of its capital structure. Could you please
6 discuss the rationale for the variance?
7 For financial reporting purposes, the AmericanA.
8 Falls Bond Guarantee and the Milner Dam Note Guarantee
9 are included in the long-term debt portion of the capital
10 structure. For ratemaking purposes, the interest costs
11 associated with both the American Falls and the Milner
12 debt securities are treated as O&M expenses. Even with
13 these exclusions, the capital structure presented in my
14 Exhibi t No. 27 is reasonable in light of industry and
15 rating agency criteria.
16 Would you please comment on Exhibit No.28?Q.
17 Exhibi t No. 28 details the calculation of theA.
18 cost of debt used in the estimated year-end 2008 capital
19 structure. The cost of debt is 5.927 percent. Please
20 note that one forecasted bond issuance of $125 million
21 appears on line 12. The $125 million issue will be used
22 to redeem outstanding short-term commercial paper as well
23 as financing ongoing capital expenditures. The interest
24 rate for this issuance was derived by averaging
25
2185 S. KEEN, DI 38
Idaho Power Company
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1 quotes for ten-year First Mortgage bonds from three
2 investment banks as of April 7, 2008. In addition, the
3 Company assumed that the Sweetwater and Humboldt County
4 bonds would be remarketed in a fixed, ten-year mode
5 before the end of the year. Idaho Power averaged quotes
6 from two investment banks for similarly rated bonds.
7 These rates were estimated at the time the overall cost
8 of capital rates were needed to prepare a rate case
9 filing.
10 Q.Does the Company utilize variable rate
11 securities in' its long-term capitalization?
12 A.Yes. The Company currently utilizes one
13 variable rate security in its long-term capitalization.
14 The Port of Morrow (Boardman) Pollution Control Revenue
15 Bonds Variable Rate Series 2000 ($4.36 million) is listed
16 on line 15 of the exhibit.
17 Q.Would you please describe the variable rate
18 nature of this pollution control bond?
19 A.This variable rate pollution control bond,
20 al though considered a long-term security, has features
21 that allow the Company to take advantage of rates
22 applicable to short-term securities. The interest rate
23 is determined the first day of a weekly period by a
24 Remarketing Agent. The Remarketing Agent examines
25 tax-exempt obligations comparable to the Boardman
Variable Bonds known to have
2186 S. KEEN, DI 39
Idaho Power Company
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10
1 been priced or traded under the then-prevailing market
2 condi tions and finds the lowest rate which would enable
3 sale of the Boardman Variable Rate Bonds.
4 Q.How did you determine what rate to use for the
5 Boardman Variable Rate Bond?
6 A.I used the methodology authorized in the 2003
7 rate case (Order No. 29505) that utilizes the average
8 rates observed for this specific bond over the last five
9 years.
Q.Please comment on the structure and rates for
11 the Humboldt and Sweetwater County bonds and how they
12 differ from the last rate case.
13
14
A. In the last rate case, the Sweetwater and
Humboldt County bonds were in an auction rate mode that
15 reset periodically (every seven days for Sweetwater and
16 every 35 days for Humboldt). The mode had produced
17 short-term rates for the long-dated securities even lower
18 than the Boardman Variable rate bonds and these benefits
19 have been passed on to the customer through a lower
20 overall cost of capital structure since 2003. However,
21 in February of 2008, the entire auction rate market began
22 to deteriorate rapidly based on overall credit worries in
23 the market, specifically around the mono-line insurers
24 which guarantee a large portion of the debt in this
25 market. Both the
2187 S. KEEN, DI 40
Idaho Power Company
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20
21
22
23
24
25
1 Sweetwater and Humboldt bonds began to experience much
2 higher reset rates through the auction process (e. g. ,
3 between seven - ten percent for Sweetwater). The Company
4 arranged for a short-term loan and used the proceeds to
5 purchase these bonds and hold them in Idaho Power's name.
6 This is a temporary solution, and the Company expects to
7 remarket these bonds in a longer term fixed mode before
8 the short-term loan expires in March of 2009.
9 OVERAL COST OF CAITAL
10 Q.What is the overall cost of capital for Idaho
11 Power Company?
12 A.As shown on Exhibit No. 27, using the proj ected
13 year-end 2008 capital structure provided to me by Ms.
14 Smi th, the cost of capital presented in my testimony, and
15 incorporating the 11.25 percent cost of equity, the
16 resultant overall cost of capital for Idaho Power Company
17 is 8.55 percent.
18 Q.Does this conclude your direct testimony in
19 this case?
A.Yes, it does.
2188 S. KEEN, DI 41
Idaho Power Company
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1 Q.Please state your name.
2 A.My name is Steven R. Keen.
3 Q.Are you the same Steven R. Keen that has
4 previously presented direct testimony in this proceeding?
5 A.Yes.
6 Q.Have you reviewed the direct testimony and
7 exhibi ts filed by the Commission Staff relating to cost
8 of capital in this proceeding?
9 A.Yes. My comments will relate primarily to the
10 testimony provided by Staff Witness Ms. Carlock as well
11 as the testimony of Mr. Matthew I. Kahal on behalf of the
12 U.S. Department of Energy ("DOE") and testimony of Dr.
13 Dennis E. Peseau on behalf of Micron Technology, Inc.
14 ("Micron") concerning return on equity ("ROE")
15 What have you concluded based on your review ofQ.
16 these testimonies?
17 A.I would first state that I agree with the
18 representations made by the Company's expert witness, Dr.
19 Avera, in his rebuttal testimony. The conclusions drawn
20 by Ms. Carlock, Mr. Kahal, and Dr. Peseau are indeed
21 biased downward and I think the rebuttal testimony of Dr.
22 Avera does an excellent job of directly categorizing the
23 shortcomings of each of the other recommendations. I do
24 appreciate that Mr. Kahal acknowledges that Idaho Power's
25
2189 KEEN, S., DI REB 1
Idaho Power Company
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1 current risk profile is high by choosing a recommended
2 rate of return that is at the high end of his range of
3 estimates. His recommended rate of return is also higher
4 than the last return authorized for the Company by the
5 Idaho Public Utilities Commission (" IPUC") in the
6 litigated 2003 rate case so as to reflect a relative
7 shift higher , albeit slight, based on increased risks.
8 Q.What are the primary drivers for your
9 assessment that the Staff-, DOE-, and Micron- recommended
10 returns on equity are too low?
11 I look to three factors. First of all, historyA.
12 suggests that these recommended levels of return will
13 yield actual returns on equity in the single digits. The
14 returns from years 2003, 2004, 2005, 2006, and 2007,
15 illustrated in LaMont Keen's Exhibit No.1, speak for
16 themselves. In those years, granted or implied allowed
17 ROEs of 10.25 percent and 10.6 percent delivered actual
18 earnings well below 10 percent.
19 Second, the rating agencies have clearly indicated
20 that the Company has experienced significant stress and
21 is in a less secure position today than in the past.
22 Since the year 2000, as illustrated in LaMont Keen's
23 Exhibi t No.2, credit ratings for Idaho Power have been
24 on a steady march downward. The ratings trend from A+ to
25 A- to BBB+ to
2190 KEEN, S., DI REB 2
Idaho Power Company
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1 BBB again speaks for itself. This decline will not be
2 turned or hal ted without some improvement in the
3 Company's allowed return on equity. In 2003, the
4 Company's allowed ROE was 10.25 percent. In 2005, the
5 Company's Idaho Case No. IPC-E-05-28 was settled and
6 resul ted in an implied ROE of 10.6 percent. Ms. Carlock,
7 Mr. Kahal, and Dr. Peseau all argue to reduce the allowed
8 return on equity at the very time an increase is
9 required. The downgrades from the rating agencies send a
10 clear and united statement to the regulating agencies
11 that the Company is more at risk today, from a bond
12 holders perspective, than it was five years ago. The
13
14
interests of equity investors fall behind those of the
bond holders so their risks are at least equally raised.
15 Finally, I look to the recent events in the
16 financial marketplace as indicators that the risks this
17 Company is facing now are greater than anyone considered
18 when original testimony was filed. Admittedly, much of
19 the market turmoil has been realized very recently and
20 may not have been adequately factored into prior direct
21 testimony, but current market conditions signal much
22 higher levels of risks in terms of both cost and
23 availability for all capital. Mr. Kahal indicates he did
24 not include any impact of the financial crisis in his
25 10.5 percent ROE
2191 KEEN, S., DI REB 3
Idaho Power Company
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1 recommendation. His reason for not doing so is that he
2 feels it would not be proper to set fair rate of return
3 based on a crisis which likely will be temporary. Yet
4 how could it be fair to completely ignore any impact from
5 a financial crisis that may well be the largest in more
6 than 50 years? As Dr. Avera noted in Figure 1 of his
7 rebuttal testimony, bond yields have skyrocketed since
8 September of this year. Apparently, bond investors are
9 choosing not to ignore the implications of this
10 particular crisis.
11 Q.If the Commission adopts Staff's
12 recommendations, will the Company be able to earn an
13 adequate and reasonable rate of return in the year 2009?
14 A. No. I do not believe the Staff's recommended
15 10.25 percent return on equity is an adequate, risk
16 adjusted return for the Company. I also do not believe
17 the full compliment of Staff recommendations will allow
18 the Company to earn anywhere close to an actual return of
19 equity of 10.25 percent. The Staff has not adequately
20 reflected the' risks associated with serving load in an
21 environment of rising costs, limited resources and
22 constrained capital, especially in light of the recent
23 turmoil in the financial markets.
24 Q.In its testimony, the Commission Staff makes
25 allowances for elements of a forecast test year that are
2192 KEEN, S., DI REB 4
Idaho Power Company
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1 intended to compensate for the effects of regulatory lag.
2 Do you agree with the conclusions of Staff witnesses that
3 Staff's recommendations will properly compensate the
4 Company for regulatory lag?
5 A.No. In my opinion, if the Commission adopts
6 the Staff's recommended approach to a forecast test year,
7 the Company will not be properly compensated for
8 regulatory lag and will not be able to earn an actual
9 rate of return anywhere near the allowed rate. The
10 Company continues to experience increasing costs and
11 faces needed investment in aging generation and
12 transmission systems that will not be recovered if the
13 significant reductions in allowed costs under the Staff's
14 methodology are implemented.
15 Q.Do the recent economic challenges stemming from
16 the financial crisis offer relief from dealing with
17 growth issues and rising costs?
18 A.Partially. While the economy is certainly
19 expected to be negatively impacted by the financial
20 crisis and prospects for growth much lower, I have not
21 heard a single projection that would indicate that growth
22 would completely stop or reverse in the Company's service
23 territory.
24
25
2193 KEEN, S., DI REB 5
Idaho Power Company
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1 Q. Since you filed your direct testimony, has any
2 new data been presented which addresses Idaho's
3 construction and growth prospects?
4 Yes. In the October 2008 Idaho EconomicA.
5 Forecast, housing starts are projected to range from
6 roughly 9,300 units in 2008 to slightly over 13,000 units
7 in 2011. While these projections are significantly lower
8 than the 18,000 to 20,000 unit figures in recent years,
9 they still portray growth that will require investment to
10 maintain infrastructure in Idaho. Significant generation
11 and transmission infrastructure investments are needed in
12 our service territory that cannot be completely
13 eliminated even if customer growth stops.
14 Q. Do you agree with Staff Witness Ms. Carlock
15 that the Company's low cost hydro generation is a benefit
16 to the Company?
17 No. In fact, Idaho Power's low cost hydroA.
18 generation exacerbates the Company's rate recovery
19 difficul ties. The benefit of the Company's low cost
20 hydro is passed on to the Company's customers in the form
21 of low rates. When the Company must add new investment
22 to serve the new loads, the new costs are high when
23 compared to the Company's low embedded costs. The
24 Company is met with
25
2194 KEEN, S., DI REB 6
Idaho Power Company
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1 price resistance and there is a considerable lag between
2 cost occurrence and cost recovery.
3 Q.Ms. Carlock also commented on the role of
4 rating agencies in the ratemaking process. Would you add
5 any additional comments to her observations?
6 A.Yes. I continue to appreciate that Ms. Carlock
7 recognizes that the services of rating agencies are
8 important to the Company. In addition to impacting the
9 borrowing costs and the costs of investor supplied
10 capi tal, as noted by Ms. Carlock, credit rating decisions
11 can actually impact a company's access to capital.
12 Turmoil in the financial markets in 2007 and again more
13 significantly in 2008 demonstrated that lower credit
14 ratings could, actually result in limited or complete
15 inabili ty to utilize some financial products such as
16 commercial paper.
17 Rating agencies ultimately look at how commission
18 decisions manifest themselves in the actual financial
19 performance of a company. Risk reducing mechanisms and
20 adjustments established in a regulatory environment are
21 important and closely monitored by rating agencies. How
22 these mechanisms and adjustments actually affect the
23 financial health of a company is of even greater
24 importance. It is the effect of the regulatory decisions
25 on a company's actual financial performance that is most
2195 KEEN, S., DI REB 7
Idaho Power Company
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1 cri tical. In light of this, it is again hard to overlook
2 the recent downward ratings changes and actual earnings
3 resul ts that are far below allowed rates of return and
4 not see the need for corresponding recommendations for
5 higher returns on equity.
6 Q.Do you have any specific information on the
7 commercial paper issue you just mentioned?
8 A.Yes. Idaho Power's current commercial paper
9 ("CP") rating of A-2, P-2 recently put the Company in a
10 difficult liquidity situation regarding the issuance of
11 CPo CP issuers carry a rating of A-1, A-2, or A-3 by
12 Standard and Poor's and P-l, P-2, or P-3 by Moody's, with
13 A-I and P-1 being the most highly rated. Of the three
14 ratings criteria for CP issuance, Idaho Power is in the
15 middle tier. When CP markets became very volatile this
16 fall and rates skyrocketed, issuance of CP became nearly
17 impossible for all companies. A government program
18 designed to improve issuance of commercial paper was
19 implemented fairly quickly by the U. S. Federal Reserve
20 but it only included purchase allowances for companies in
21 the top tier rated A-I, P-1. As a result, companies with
22 that rating have had much less difficulty issuing
23 commercial paper and have done so at more competitive
24 rates.
25
2196 KEEN, S., DI REB 8
Idaho Power Company
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1 CP in Idaho Power's category of A-2, P-2 has
2 experienced pricing increases from roughly 3 percent this
3 summer to in excess of 6 percent in October. Instead of
4 being able to issue CP wi th maturities of weeks or
5 months, the only available maturities at certain times in
6 October were limited to days, or even overnight. As a
7 resul t of this credit squeeze, the Company was forced to
8 utilize a loan feature provided for in its credit
9 facili ty. On October 7, 2008, the Company drew down a
10 swing-line loan of $30 million to accommodate short-term
11 liquidity needs. The loan was subsequently repaid when
12 issuance maturities beyond overnight were again
13 available.
14 Q. Is that an unusual circumstance for the
15 Company?
16 A.Yes. Drawing on credit facilities is very rare
17 and is a situation all companies try to avoid. To my
18 knowledge, this is the first time Idaho Power has been
19 forced to use this liquidity mechanism.
20 Q.Can you explain why this occurrence is relevant
21 here?
22 A.Yes~ The reason I mention it here is that it
23 is a very direct signal that the Company is currently
24 operating in a time of significant financial stress. On
25 page 9 of his direct testimony, Mr. Kahal referred to the
2197 KEEN, S., DI REB 9
Idaho Power Company
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1 situation as "a serious economic crisis that has required
2 historical and remedial action by U. S. and foreign
3 governments. " It is indeed serious and the
4 Company-specific liquidity issues point out that the
5 impacts are real and affecting Idaho Power today. It
6 also points out that having weaker credit can cause
7 detrimental results. The increased costs from this
8 short-term borrowing is a very real stress on the actual
9 resul ts for the Company and it demonstrates why higher
10 rates of return on equity are warranted during times of
11 financial distress.
12 Do you have any comments regarding interestQ.
13 rates and equity markets in light of comments made by
14 Staff Witness Carlock?
15 I do. In regard to interest rates, Ms. CarlockA.
16 cites a decline in the prime rate, which is one benchmark
17 for short-term borrowing, and also mentions that the
18 federal funds rate and other rates had also decreased. I
19 do not disagree with those observations; however,
20 benchmark rates are merely a starting point for interest
21 charges to be incurred by a regulated utility. Banks and
22 other lenders charge a spread above the benchmark rates
23 depending on perceived borrowing risks. That spread is
24 added to the benchmark treasury rate to form the coupon
25 rate of interest. This rate ignores an additional small
2198 KEEN, S., DI REB 10
Idaho Power Company
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1 increase for costs of issuance, but it is a good rate for
2 comparison purposes.
3 For example, on July 7, 2008, the Company issued
4 long-term debt with a ten-year term at a coupon rate of
5 6.025 percent. That rate included a spread to the
6 Treasury of 215 basis points over and above the benchmark
7 ten-year Treasury rate of 3.875 percent. Roughly six
8 months earlier, that spread to Treasury was closer to 100
9 basis points and the trend of rising spreads has
10 continued. At the end of October 2008, the benchmark
11 Treasury rate for ten-year bonds was roughly the same as
12 in July; however, the spread to Treasury for Idaho Power
13
14
would have added over 400 basis points. The coupon rate
would have been close to 200 basis points higher than in
15 July of this year. Since the end of October, the
16 Treasury rates have declined further but not nearly as
17 much as the spread to Treasury has risen.
18 The point is that the interest cost to the Company
19 has actually risen significantly over the course of the
20 year, which puts additional stress and risk on funding
21 future capital needs.
22 In addition to that stress on debt issuances, equity
23 prices have fallen significantly. On October 31, 2008,
24 the Company stock was trading 24 percent below its
25 starting
2199 KEEN, S., DI REB 11
Idaho Power Company
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1 point for the year. While the Company's share price held
2 up relatively well compared to peer companies, that
3 significant decline in equity value is an additional
4 stress upon the Company's financial viability.
5 Q.What are industry experts saying in regard to
6 interest rates and the relative issuance spreads going
7 forward?
8 A.The consensus is that spreads will remain wider
9 and that the current higher level of coupon issuance
10 rates will not improve in the near term. As noted in
11 Figure 1 of Dr. Avera's rebuttal testimony, corporate
12 bond yields have seen precipitous increases since
13 September of this year. Those increases are primarily
14 the result of increased spread, or perceived risk, over
15 benchmark Treasuries. With Treasuries already extremely
16 low, reductions in debt costs will only come when the
17 market feels more confident about corporate debt in
18 general, thus allowing spreads to contract.
19 Q.Do you recommend any other changes to the
20 capital structure?
21 A.I do not recommend any change at this time but
22 note that there will be actual outcomes that differ from
23 the Company's, projections. I continue to believe that a
24 forecast methodology is an appropriate and reasonable
25
2200 KEEN, S., DI REB 12
Idaho Power Company
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1 benchmark for setting our cost of capital. However,
2 Staff has introduced modifications for various components
3 of this filing based on a review of actual expenditures
4 to date and I feel compelled to acknowledge that changes
5 have also occurred in regard to cost of capital.
6 In my proposed capital structure, I have included
7 proj ected costs of debt related to planned debt issuances
8 for both taxable and non-taxable debt. One of those
9 issuances occurred on July 7, 2008. The original
10 projection for this issuance was $125 million at a rate
11 of 5.53 percent for ten-year bonds. The actual issuance
12 was for $120 million at a rate of 6.025 percent for ten
13
14
years.
The other planned issuances relate to the Company's
15 Pollution Control Revenue bonds for both Sweetwater and
16 Humbol t Counties. The proj ected interest rates utilized
17 in the Company's embedded cost of debt schedule were
18 derived from pricing estimates as of April 10, 2008, and
19 related to planned issuances for these securities; Idaho
20 Power anticipated the bonds would be outstanding at fixed
21 rates until maturity of each bond. The rates Idaho Power
22 is currently being quoted for this type of issuance are
23 significantly higher than in the Company's forecast.
24 Estimates are, now roughly 100 basis points higher than
25 our assumed 5. 75 percent rate as originally filed.
2201 KEEN~ S., DI REB 13
Idaho Power Company
.
.
.
1 Q.Are there any other components of the current
2 debt structure that are impacted by market changes?
3 A.Yes, Idaho Power has one additional series of
4 variable rate debt outstanding, the Port of Morrow Series
5 2000, due 2027, and that variable rate was originally
6 proposed based on a five-year historical average. The
7 updated average rate for five years through September 30,
8 2008, would be 3.070 percent, which is slightly higher
9 than the filed rate of 2.978 percent.
10 Q.Do you wish to add any other comments regarding
11 the financial crisis and how it may potentially impact
12 ROE recommendations?
13 A. I do want to add some specifics to the quote
14 from Mr. Kahal' s testimony. While this certainly is a
15 "serious economic crisis," I think it is important to
16 reflect on the significance and magnitude of events that
17 occurred in September and October of this year before
18 dismissing too quickly that this situation is temporary
19 or that equity holders will not be factoring in higher
20 risk expectations going forward.
21 Here is a brief time line for perspective:
22 Sept. 7:,Federal takeover of Fannie Mae and
Freddie Mac
23
Sept. 14:Bank of America buys Merrill Lynch
24
25
2202 KEEN, S., DI REB 14
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Sept. 15:Lehman Brothers files for bankruptcy
2 Sept. 17:Federal Reserve Loans $ 8 5 billion to
AIG to avoid bankruptcy
3
Sept. 19:Paulsen rescue plan unveiled
4
Sept. 25:WaMu seized by FDIC, sold to JP
Morgan5
6 Sept. 29:Bailout defeated in the House of
Representati ves
7
Sept. 30:CITI announces FDIC-backed
acquisition of Wachovia8
9 Oct. 1:Senate passes revised bailout
Oct. 3:Wells Fargo announces merger with
Wachovia; Bailout signed into law
Oct. 6:Federal Reserve announces $900
billion in short-term loans to banks
Oct. 8:Federal Reserve reduces emergency
lending to 1.75 percent
Oct. 10:End of the worst week for stockmarket in 75 years.
Oct. 14:US Announces inj ection of $250
billion into US banking system
Oct. 15:US monthly retail sales drop 1.2
percent and DJIA drops 7.87 percent
Oct. 28:US consumer confidence falls to
record low of 38
Oct. 30:Federal Reserve announces Federal
Reserve Funds Rate cut of .5 percent
to 1 percent
Q.Have these events moderated since October?
A.The frequency of events may be slowing but the
reactions in the financial markets continue to be
2203 KEEN, S., DI REB 15
Idaho Power Company
.
.
.
1 severe. On December 1, 2008, the U. S. economy was
2 officially deemed to have been in a recession and the Dow
3 Jones Industrial Average plunged 679 points. The
4 fourth-largest point decline since this index was created
5 in 1986.
6 Q.Did you factor in any allowance for the type of
7 financial market changes outlined above that occurred
8 during 2008 when you filed your original testimony?
9 A.I did not foresee or account for the level of
10 volatility that has occurred in the financial sector.
11 The current financial turmoil is itself a risk factor
12 that was in no way considered when I filled my original
13 testimony.
14 Q. Are these levels of volatility unique?
15 A.Most certainly. Below is a chart that was
16 provided to me by J. P. Morgan and it represents the S&P
17 500 volatility index, or VIX. This index is commonly
18 used in the financial community as a measurement of
19 volatili ty. Typically volatility has the effect of
20 increasing risk and as you see, the level of volatility
21 in the current financial market is extreme. Recent
22 levels depict volatility as high as four times greater
23 than the average over last prior decade.
24
25
2204 KEEN, S., DIREB 16
Idaho Power Company
.
.
.
10
11
1
2
3 80 i
I
70 -1
1,
t¡
~..~4
1998-2007 average: 20.7
5
:: 1ì i40 -! f
30 ktrff\", rt-- ..J
20 ! v ~~l.' \n
i10 ¡ ---------------------------------------------
Of Of 08 1107/08
6
7
8
9
02l2f08 07/26/08 09/ti/0804/13/08 0604/08
Q.In your original testimony, you make reference
12 to the difficulties of achieving actual earnings that
13
14
equal allowed levels of return. Will this current
financial turmoil impact the Company's ability to achieve
15 allowed earnings results?
16 The increased volatility raises uncertainty andA.
17 the market is currently translating that uncertainty into
18 higher risk-adj usted costs to all forms of capital, which
19 in turn will make it harder to achieve allowed earnings
20 results.
21 In your direct testimony you indicated thatQ.
22 potential improvements in the mechanism utilized to
23 recover power. supply costs (" PCA") could influence your
24 recommended rate or return on equity. Do you have any
25 additional comments to add in that regard?
2205 KEEN, S., DI REB 17
Idaho Power Company
.
.
.
1 A. Yes. There has certainly been progress on the
2 PCA and assuming the new methodology is implemented, I
3 feel it will improve the risk profile of the Company.
4 This enhancement should deliver a very modest benefit to
5 the earnings ability of the Company and a greater benefit
6 to the management of cash flows. While this enhancement
7 is significant, it does not entirely close the gap
8 between my recommended return on equity and the 10.25
9 percent recommended by Staff. I also did not anticipate
10 the severe changes that have occurred in the financial
11 markets since that testimony was filed and the
12 significant negative those events introduced in the
13
14
determination of equity return.
I would simply observe that these two events have
15 occurred, one posi ti ve and one negative. The posi ti ve
16 event is significant for the Company but did not remove
17 100 percent of the exposure Idaho Power experiences due
18 to weather and water related fluctuations in its
19 hydroelectric generation. The negative event is
20 significant historically to the entire world and I cannot
21 predict what the ultimate effect will be on Idaho Power.
22 I will simply say that I continue to feel the
23 recommendations for rate of return on equity by Staff,
24 the DOE, and Micron are too low.
25 Q.Does this complete your direct rebuttal
2206 KEEN, S., DI REB 18
Idaho Power Company
1 testimony?.2 A.Yes.
3
4
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
2207 KEEN, S., DI REB 19
Idaho Power Company
.1
2 open hearing.)
(The following proceedings were had in
MS. NORDSTROM: I will make this witness
4 available for cross-examination.
10
11
.
3
5
6
7
8
9
12 BY MR. BRUDER:
13 Q
COMMISSIONER SMITH: Okay. Mr. Boehm.
MR. BOEHM: No questions, Your Honor.
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: Thank you.
CROSS-EXAMINATION
Good afternoon.
Good afternoon.
Sir, a large portion of your rebuttal
16 testimony, really most of it, is devoted to the current
14 A
17 financial situation and the cost of capital implications
15 Q
18 for Idaho Power. I understand from your direct testimony
19 that you were recommending 11.25 percent, that return on
20 equity selected from Dr. Avera's range of 10.8 to 11.8
21 percent; is that correct?
22 A That's correct. Dr. Avera's range of 10.8
23 to 11.8 did not include any flotation costs which he does
24 discuss that would be an adder to those numbers, but my.25 number as you stated is correct.
CSB REPORTING
[phone]
2208 KEEN (X)
Idaho Power Company
1 Q The 11.25?.2
3
A Yes.
Q Okay. After considering current financial
4 condi tions, then you continue to recommend the 11.25 or
5 are you revising that?
6
7
8 recommendation?
9
A No, I continue to recommend that.
Q So the current situation didn't alter that
A No, and I would say that no one more than
10 the Company wishes we could lower our recommendation at
11 this time and if you look at our history of earnings, it
12 would say we're just not in a position that we can do.13 that. I believe that recommendation that I've made is
14 the minimum rate of return that will give us a chance to
15 be competitive going forward.
16
17 pronunciation.
18
19 name.
20
Q And Doctor -- please tell me that
A Avera, I believe, is how Bill says his
Q He hasn't altered his reasonable range of
21 10.8 to 11.8; is that right?
22
23
A He has not, to my knowledge.
Q Would you agree that the current
24 conditions create economic stress and hardship for your.25 retail customers?
CSB REPORTING
[phone]
2209 KEEN (X)
Idaho Power Company
.
.
.
10
1 A Yes, I would.
2 Q And it's true, is it not, that this
3 financial situation has produced severe price decreases
4 in common stocks pretty much across the board, isn't
5 it?
6 A Excuse me, did you say common stocks?
7 Q Yes.
8 A Yes, unprecedented I would say. The stock
9 market is at a 50-year or 70-year low.
Q Probably measured fairly by the S&P 500
11 which is down about 40 percent year to date, yes?
12 A Yes.
13 Q At this point -- may I approach?
14 COMMISSIONER SMITH: You may.
15 (Mr. Bruder approached the witness.)
16 MR. BRUDER: I'll distribute first to the
17 witness and the Commission and then others two documents
18 which I've marked as DOE Exhibit 612 and 613. I show you
19 the two docum~nts I've mentioned. These are notated as
20 DOE Exhibits 612 and 613 which I ask to be marked for
21 identification at this point. Exhibit 612 is titled
22 "Idaho Business Review" and it speaks of IDACORP' s
23 earnings for the third quarter. The second is IDACORP.
24 This is Google Financial and this is a financial report
25 dated December 5th.
CSB REPORTING
[phone]
2210 KEEN (X)
Idaho Power Company
.
.
.
1 (U.S. Department of Energy Exhibit Nos.
2 612 & 613 were marked for identification.)
3 Q BY MR. BRUDER: Looking at DOE Exhibit
4 613, does that show that IDACORP is down about 16
5 percent?
6 A I'm not seeing the percentage on this
7 sheet. It does show that we're down from what period
8 of time are you referring to, I guess?
9 Q My understanding of this measure is that
10 it's from year to date January 2nd through December 5th,
11 sorry.
12 A Okay. I'm not finding 16 percent
13 anywhere.
14 Q No, no, it's a measurement that's taken
15 from the chart. Will you accept, subj ect to check, it's
16 16 percent?
17 A Subj ect to check, sure.
18 Q And since IDACORP pays about a four
19 percent dividend yield, would it be fair to say that this
20 represents an investor loss of about 12 percent for that
21 period of time?
22 A I can see your logic there. Subj ect to
23 check, I would say yes.
24
25
Q And that 12 percent loss for that period
of time is in fact dramatically better than the
CSB REPORTING
[phone]
2211 KEEN (X)
Idaho Power Company
.
.
.
1 performance of the broad stock market; isn't that
2 correct?
3 A I would say compared to the broad market,
4 that would be correct, yes. I'm not sure how it compares
5 to other utili ties, but at 29.50 and we were below that
6 yesterday, we're very close to our book value and I think
7 the decline for utili ties tends to slow as you hit book
8 value.
9 Q Well, thinking, then, in relative or
10 comparative terms, that would suggest that IDACORP might
11 in fact be something of a safe haven stock as things
12 stand today; is that not right?
13
14
A I think you might believe that if you
didn't look back to last year and realize we had a very
15 difficult year in 2007 and we were already in a depressed
16 state when we came in to 2008. 2007 was a very bad
17 earnings year and if you look at the trailing 12 months
18 that I think this Business Review article was talking
19 about, you would see earnings that really show we're
20 still a full two percentage points below our allowed rate
21 of return, so things are relative and when you're having
22 a better year after a bad year, things look good in that
23 perspective, but in a broader sense, we're a long ways
24 from a high performing company.
25 Q Looking at what we've marked as Exhibit
CSB REPORTING
[phone]
2212 KEEN (X)
Idaho Power Company
.
.
.
1 612 which reports that IPC' s third quarter earnings for
2 this year were $47 million compared to 24 million for
3 that same quarter last year, would that reflect at least
4 for that quarter that the Company is doing quite well?
5 A A good part of that $47 million was a, you
6 could say a, regulatory shift from the second quarter and
7 I'm not probably the perfect witness to talk about that,
8 but it had to do with the shape of how we handled our PCA
9 during this year and it actually made for a very
10 distressing second quarter that we spent a lot of time
11 explaining to analysts and the swing, most of it showed
12 back up in the third quarter, so if you look at the two
13 together, you get a much more normal picture of what the
14 year was, but no question in 2008, third quarter was very
15 good, second quarter was very bad and both of those are
16 atypical for the performance of the Company.
17 Q Well, I see by this article that the
18 Company's management attributes this significant upturn
19 to what it refers to as progress from prolonged and
20 purposeful regulatory efforts, as well as good weather
21 and hydro conditions, corporate efficiencies; is that an
22 accurate statement of that?
23 A Yes, and if I've miscategorized -- I'm not
24 saying that the third quarter was a bad quarter and the
25 first three-quarters of this year have been a better year
CSB REPORTING
[phone]
2213 KEEN (X)
Idaho Power Company
1 for us. If you look at our Exhibit 1 that charts.2 earnings, this has potential to be a year much like 2006
3 and compared to 2007 and 2005 and 2004, they look pretty
4 good, but it's still a year that is not going to reach
5 our allowed rate of return and in terms of an investor's
6 perspective, I think that has to be factored in as
7 well.
8 Q My question, and I should have phrased it
9 differently, was I'm looking at Exhibit 612 and there is
10 a third paragraph there which references a quotation
11 about the accomplishments of the Company. All I'm asking
12 you, and I know that the media don't always report things.13 perfectly, is this in fact a valid and correct quotation
14 and explanation for the situation in which the Company
15 finds itself through this third quarter?
16 A Well, this paragraph is not inaccurate.
17 We did have some what we consider regulatory
18 accomplishments and we had good support from this
19 Commission and also we had progress with our Oregon
20 Regulatory Commission. In Oregon, we were able to
21 establish a PCA-type mechanism that hadn't been there in
22 the past. In Idaho, we were able to get a peaker plant
23 approved and able to begin collections of that in our
24 rate structure, so there were regulatory progress in both.25 of those states and so it is accurate, yes.
CSB REPORTING
[phone]
2214 KEEN (X)
Idaho Power Company
.1
2 you.
MR. BRUDER: Nothing further. Thank
COMMISSIONER SMITH: Thank you. Mr. Ward,
4 do you have questions?
10
11
12.13
3
5
6 you.
7
8
9
Madam Chair.
14
15
16
1 7 BY MR. RI CHARDSON :
18 Q
MR. WARD: I have no questions. Thank
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: No questions.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Just a couple,
CROSS-EXAMINATION
Mr. Keen, would you turn to page 27 of
19 your direct testimony?
.
20 A Yes, sir.
And your point ROE estimate in this case
11. 25.
And starting on page 27 over to page 28,
25 you talk about an additional $3 million for managing
CSB REPORTING
[phone]
21 Q
22 is what?
23 A
24 Q
2215 KEEN (X)
Idaho Power Company
.
.
.
1 PURPA contracts and that would add an additional 20 basis
2 points to your ROE. Is that 20 basis points included in
3 the 11.25?
4 A Not specifically, no, it wasn't.
5 Throughout my testimony I alluded to items that could be
6 considered and my point here was really just to say that
7 while in a lot of ways we have a very supportive approach
8 to QF facilities, the rating agencies look at those in a
9 negati ve manner and impute debt and even though we
10 collect 100 percent of what we pay through that, through
11 the PCA, it's factored in on QFs, there is an overhang
12 there and that there's a cost and a charge to that, but I
13 didn't factor that into my recommendation.
14 Q i wasn't talking about the debt imputation
15 of rating agencies. I was talking about the $3 million
16 for managing QF -- management fee is what it's called.
17 A It is related. I'm sorry, I understand
18 that. Really, it's saying that even though it's an asset
19 that we don't own, if it was replaced with an asset we
20 did own, there would be a return component for the fact
21 we have to work with that particular asset and the way
22 the rating agencies look at this is you may not have it
23 on your books as an asset, but you have all the
24 responsibilities of ownership and operation as if you
25 did, yet you're getting nothing for it and that's
CSB REPORTING
[phone]
KEEN (X)
Idaho Power Company
2216
.
.
.
1 perceived as a negative and if there was a fee, as I
2 mentioned in my testimony and talked about in previous
3 discussions, that would tend to take away that negative
4 thinking on the QFs.
5 Q So the management fee you refer to on page
6 27 is equated in your view to debt imputation by rating
7 agencies?
8 A It's the lack of anything beyond a
9 recovery of the cost for an asset that we have to manage
10 and that has impacts on how we operate our system.
11 Q And as far as you know, the Idaho
12 Commission has never authorized a management fee for
13 managing QF contracts?
14 A To my knowledge, it's not been authorized.
15 I reference Staff witness Drummond here had at least
16 discussed it in a previous case.
17 MR. RICHARDSON: That's all I have, Madam
18 Chair.
19 COMMISSIONER SMITH: Thank you,
20 Mr. Richardson. Mr. Price.
21 MR. PRICE: No questions.
22 COMMISSIONER SMITH: Is that everyone?
23 Back to Ms. Nordstrom. Oh, Commission. Commissioner
24 Kempton.
25
CSB REPORTING
[phone]
2217 KEEN (X)
Idaho Power Company
.
.
1 EXAMINATION
2
3 BY COMMISSIONER KEMPTON:
4 Q Madam Chairman, Mr. Keen, in 2007 where
5 you refer to the third quarter 24.1 million, 2007 was a
6 fully forecast year, was it not, by Idaho Power?
7 A In terms of --
8 Q How it presented the rate case to the
9 Commission was a fully forecast?
10 My memory is escaping me here, but it hadA
11 a forecast el~ment. I can't remember if we had six
12 months' actual, plus six months of forecast, but we may
13 have filed it originally with full forecast and then kind
14 of modified back to where we reported a lot of actuals.
15 That's kind of what I'm recalling.
16 Q And it was a part of that forecast that
17 actually caused some of your problems in the third
18 quarter, wasn' t it, specifically related to the runoff?
19 A It was -- you're referring to how the
20 money shifted into the third quarter or are you talking
21 about 2007?
22 Q I'm talking of the absolute ability to
23 incur revenue was a result of deficiency in the amount of
.24 water that came through the Hells Canyon complex.
25 As I recall, that was a difficult waterA
CSB REPORTING
[phone]
2218 KEEN (Com)
Idaho Power Company
1 year, but I'm not sure I -- I'm trying to understand, are.2 you asking about '07 and why '07s third quarter was not
3 as good as '08s third quarter?
4 Q I'm speaking of the 24.1 million where you
5 said you didn't have a chance to make the return on
6 equity that we had provided and I'm just suggesting that
7 perhaps there were other reasons than regulatory lag and
8 some of the other risk factors that were a part of that
9 process and a part of that for Idaho Power was the
10 forecast.
11 A Well, during 2007 we were operating off of
12 rates that were set in previous years, so the forecast.13 test year that was filed on 2007 really factored into
14 where our rates were set at the beginning of this year.
15 '07s rates would have been coming off of what came out of
16 the 2005 case, I believe, and I think the reason 2007 was
17 an under-performing year was largely related to water and
18 purchased power costs and there is an element of
19 regulatory lag, which there was a question earlier on
20 that, but at least for me when I talk about regulatory
21 lag, I don't refer to something that relates to the
22 Commission taking time to get the Order out.
23 It's just that we have to front capital
24 costs. We essentially go build things. We fund growth.25 in O&M and other expenditures and we do that with our
CSB REPORTING
[phone]
2219 KEEN (Com)
Idaho Power Company
.
.
.
1 balance sheet. We either borrow money to do that or we
2 sell stock to do that, but we've incurred those capital
3 charges before we ever get around to filing our case, and
4 so there's a lag there and then the case takes a natural
5 period of time. By the time you get to the end of that
6 stream, there's a period of time that we've had to bear
7 the burden of that construction process and that
8 operating process that isn't rewarded and that is a
9 contributor as well, but I think when you look across our
10 years of performance, you would say the lower of the
11 years is probably contributed to largely by weather and
12 power supply purchases and I think that was a large
13 contributor in 2007.
14 Q Okay; so we kind of shifted the topic a
15 little bit, but in the area of regulatory lag, I think
16 that was addressed pretty much yesterday and I, too, am a
17 little perplexed sometimes when we try to define
18 regulatory lag when you look at the definitions between
19 what the Commission says which is as of the date that's
20 it's filed that we start measuring it and then that
21 period after we measure where we have 30 days, 30 days
22 plus five months, some people call that regulatory lag,
23 other people call that due process.
24 A Sure.
25 And it's a question of how you apply thoseQ
CSB REPORTING
[phone]
2220 KEEN (Com)
Idaho Power Company
.1 and certainly, I don't think it's regulatory lag when
2 we're in a test year like, for example, this year and
3 costs are claimed to be regulatory lag when they're
4 incurred, and this is Idaho Power' s definition, any time
5 between January and June when the filing for this case
6 was in June, I just don't see that as regulatory lag, so
7 sometimes we need to perhaps touch up our definition at
8 least in our communications locally.
9 A I think that's a very fair statement and
10 as I look back to the last case that we filed, if it was
11 a full forecast from the beginning, I believe that was a
12 settled case and I think the settlement didn't get us to.13
14
where we had really looked to the end of 2007 and
incorporated. It had a historical element to it. As I
15 recall, there was a lot of discussion around the mid year
16 point and I think the case we filed this time does do --
17 it eliminates a good part of the lag because it gets us
18 closer to the end of the year and when our rates will
19 actually be available for us to charge is sometime in
20 2009 and at least they're close to the point if we've
21 estimated where our O&M structure is going to be at the
22 end of the year and what capital we've spent through '08,
23 a lot of that. lag will be assisted. There won't be so
24 much to talk about, so it's a term that could probably be.25 misinterpreted at times and I do think the efforts that
CSB REPORTING
[phone]
2221 KEEN (Com)
Idaho Power Company
.
.
.
1 we put forward by trying to advance at least the time
frame that we're looking at when we're in a case helps to
take away some of that lag.
COMMISSIONER KEMPTON:No further
questions.
2
3
4
5
6 COMMISSIONER SMITH: Commissioner Redford.
7
8 EXAMINATION
9
10 BY COMMISSIONER REDFORD:
11 Q In the previous testimony, I don't know
12 exactly where, it was stated that you plan a three
13 percent increase, salary increase, if the dividend
14 exceeds is at $1.20 or exceeds $1.20; is that a fair
15 statement?
16 A Actually, I'm not aware that there's a
17 connection with the general wage adj ustment and the
18 dividend payment. We have had a component of our
19 incentive that motivates us to operate within a budget
20 constraint and other things that had a trigger that if we
21 didn't earn a certain level, it çould be withheld, but I
22 would have to defer to someone else. I'm not aware that
23 the general wage adjustment has a connection to our
24 earnings.
25 Q Well, maybe I'm not correct.
CSB REPORTING
[phone]
2222 KEEN (Com)
Idaho Power Company
.1 But we have talked about a three percentA
2 general wage adjustment and that is actually a change in
3 the structure and then most people would be eligible to
4 get that, not every employee would get that. It can be
5 wi thheld if someone is not performing or not doing their
6 job well.
7 Is there a threshold dividend rate thatQ
8 triggers the wage increases?
9 On incentive payouts, I believe we have toA
10 earn over the amount that we payout in dividends. If
.
.
11 our earnings are so bad that we don't actually earn
12 enough money to cover our dividend payments, I believe
13 all incentives are subject to be withheld.
14 Q But that's just on incentive payments?
15 I believe so, and I would defer toA
16 possibly our policy witness could clean up on that if I'm
17 wrong because that's not my area of expertise.
18 Okay, well, inCOMMISSIONER REDFORD:
19 that case, I have no further questions and I thank you.
20 THE WITNESS: Thank you.
21 COMMISSIONER SMITH: Ms. Nordstrom, do you
22 have any redirect?
23 MS. NORDSTROM: I do. Thank you.
24
25
CSB REPORTING
[phone]
2223 KEEN (Com)
Idaho Power Company
.
.
.
1 REDIRECT EXAMINATION
2
3 BY MS. NORDSTROM:
4 Mr. Bruder introduced the Exhibit 613 andQ
5 based on that exhibit,can you tell me what Idaho Power's
52-week high was for its stock price?
A It says we were at $36.72.
Q Is that considered a high price for Idaho
Power's stock?
A Of late,that seems pretty good,but I
remember when the stock was close to $50.00.
6
7
8
9
10
11
12 Q How long ago was that?
13 A Don't quote me on this, but in five years,
14 say,fi ve-year range.
15 In five years Idaho Power's stock priceQ
16 has dropped almost by half?
17 Yes, and to be fair, an element of theA
18 $50.00 price was when we were in energy trading, but
19 we've certainly been up in the high 30's and $40.00 range
20 post that time period as a utility.
21 Mr. Bruder also talked about utili tiesQ
22 being considered a safe haven and Idaho Power possibly
23 being considered a safe haven. Do you think investors
24 consider Idaho Power a safe haven right now?
25 Well, I would agree with some of theA
CSB REPORTING
[phone]
2224 KEEN (Di)
Idaho Power Company
.
.
.
1 comments that their expert witness Mr. Kahal said that I
2 think investors from the equity side are pretty nervous
3 in general and I'm not sure they recognize any safe haven
4 other than the U. S. government right now, but there's two
5 pieces of our -- I spend a lot of time, also, talking to
6 the rating agencies and how they look at us from the debt
7 side and I can tell you their level of comfort with Idaho
8 Power is the lowest I've ever seen it.
9 I've been having weekly calls and
10 sometimes daily calls from the rating agencies and it
11 varies between S&P, Moody's and Fitch which one is most
12 nervous on which day, but it's truly unprecedented the
13 amount of time they spend watching us right now and I
14 don't believe that's because they feel we're ultra
15 secure.
16 Q How often do they normally contact you?
17 A I would say a typical year we would have
18 contact probably quarterly, basically a quarterly
19 check-in with really two periods of time, a spring and an
20 end-of-year more detailed review and I would say since
21 mid year it has been monthly and since October it's been
22 weekly.
23 Q And what do they seem concerned about when
24 they call you?
25 A Right now they're concerned about any debt
CSB REPORTING
[phone]
KEEN (Di)
Idaho Power Company
2225
.
.
.
1 maturi ties in the future. They're very concerned about
2 the fact that we had difficulties in issuing commercial
3 paper. Liquidity is of the biggest concern, and when we
4 talk about our ratings and when we put forth that it is
5 important we maintain our rating and we don't fall to
6 junk status, one of the biggest pitfalls is that we would
7 lose our ability to sell commercial paper. We're already
8 in the second tier. First tier players have had almost
9 no problems this year. As soon as the government stepped
10 in and guaranteed A-I and P-l commercial paper, their
11 problems essentially went away.
12 We have continued to pay high rates. We
13 have now seen, the rates drop from a high of mid six's,
14 and this is for very short-term money, this is one-week,
15 two-week-type money, down to where we're now borrowing a
16 little over four percent, but for most of the early part
17 of this year and most of last year, those numbers were
18 closer to two, so it has been a very difficult time from
19 a liquidity perspective and that's a place where your
20 ratings really make a difference.
21 Q Commissioner Redford asked a question
22 earlier of Dr. Peseau about that Exhibit 88, the one that
23 has the list of all the utilities on it and where they
24 rank as far as risk. He pointed out that most of the
25 utilities on there are triple B. If that is the case,
CSB REPORTING
[phone]
2226 KEEN (Di)
Idaho Power Company
.
.
.
1 then, you know, why is Idaho Power concerned or is the
2 Company concerned?
3 A I thought Commissioner Redford's comments
4 were very astute in that the entire industry has moved
5 downward and there is a great deal of the industry that
6 is at triple B. I think one of the compelling items
7 about this particular issuance of Standard & Poor's is
8 this an actual physical ranking strongest to weakest, so
9 if you start at the top of this list, that's who Standard
10 & Poor's thinks is strongest. There's 185 companies and
11 we're number 130, so we're quite a ways down the list and
12 if you look how close we are to the triple B' s, the
13 triple B minuses, excuse me, we're kind of at the bottom
14 end of the triple B' s. Currently we're in the middle
15 section. There's triple B plus, triple B' s and then
16 triple B minus. Triple B minus is the last ledge before
17 you fall into junk status and we're getting pretty close,
18 so while everybody is -- you can say it's triple B, this
19 is an interesting document and Standard & Poor's actually
20 stepped out and said here's where we think you are on
21 that continuum, so that's it. That's probably what I
22 would pick out of this.
23 COMMISSIONER REDFORD:I thought he was
24 talking about the Idaho football team.
25 Q BY MS. NORDSTROM: And, Mr. Keen, just to
CSB REPORTING
[phone]
2227 KEEN (Di)
Idaho Power Company
.
.
.
1 be clear, I know we've kind of discussed definitions of
2 regulatory lag. Is the way that you're using regulatory
3 lag the same as the way Commissioner Kempton or
4 Commissioner Redford have been using regulatory lag?
5 A When I think of regulatory lag, I
6 certainly don't think of it as just a component that was
7 caused by regulation. Part of it is just a function of
8 how in a regulated environment we are expected to
9 pre-fund what we do. We're expected to finish our
10 construction, get it in service and then we come to the
11 Commission and we make our case and we try to collect.
12 Forecast test year removes that a little bit, but it's
13 really that period of bearing those costs, and a real
14 good example of it is the Hells Canyon proj ect. That's
15 $100 million that we have expended and yes, we're getting
16 AFUDC which is an allowance, but it's not cash, and we
17 also have $ 100 million currently, and that's a round
18 figure, that we have funded with the PCA that we will
19 collect back, but $200 million when S&P looks at us has
20 been spent that we don't have any cash coming in on and
21 that's concerning for them, and when they look at our
22 cash metrics and they see they're weak, they turn right
23 and they look at those and that's a component of lag, but
24 it's a different connotation, I think, than maybe what I
25 heard from the Commission, so I don't think that's
CSB REPORTING
[phone]
2228 KEEN (Di)
Idaho Power Company
.
.
1 pointing fingers at anybody. It's just how regulatory
2 companies operate and something we have to overcome.
3 Forecast test years help.
4 Q So if I'm understanding you correctly,
5 regulatory lag the way you're using it is the difference
6 between when the expenses were incurred and when the
7 expenses are recovered in rates and that has nothing to
8 do with the amount of time a case is pending before a
9 commission?
10 A No, the amount of time you spend there is
11 maybe the end piece of the lag, but it's certainly not a
12 focal point.
13 MS. NORDSTROM: Thank you. No further
14 questions.
15 COMMISSIONER SMITH: Thank you,
~ 6 Ms. Nordstrom, and Mr. Keen.
.
17 THE WITNESS: Thank you.
18 COMMISSIONER REDFORD:I have one other
19 question, if I could.
20 COMMISSIONER SMITH: Sure.
21
22
23
24
25
CSB REPORTING
[phone]
2229 KEEN (Di)
Idaho Power Company
.
.
20
1 EXAMINATION
2
3 BY COMMISSIONER REDFORD:
4 Q The Company has put forth that triple B is
5 junk bond ratings and I just heard you say that it's the
6 next level down that's the junk bond.
7 A Double B is really what is considered junk
8 bonds. You can be be a triple B minus and you're still
9 considered an investment grade issuer.
10 Q So you're not junk bonds?
11 A No, no, and we don't want to get there.
12 COMMISSIONER REDFORD: Thank you. I have
13 no further questions.
14 COMMISSIONER SMITH: Thank you, Mr. Keen.
15 THE WITNESS: Thank you.
16 (The witness left the stand.)
17 MS. NORDSTROM: Should we continue with
18 the cost of capital witnesses?
19 COMMISSIONER SMITH: I'm indifferent.
MS. NORDSTROM: Well, we've got I
21 believe Dr. Avera is on the phone, so it would be nice if
22 we could finish up with the cost of capital witnesses so
23 we could excuse him.
24.25
COMMISSIONER SMITH: Would that be
Ms. Carlock?
CSB REPORTING
[phone]
2230 KEEN (Com)
Idaho Power Company
.1
2
3 left?
4
5
MS. NORDSTROM: I believe so.
COMMISSIONER SMITH: Is she the only one
MR. PRICE: Staff calls Ms. Terri Carlock.
6 TERRI CARLOCK,
7 produced as a witness at the instance of the Staff,
8 having been first duly sworn, was examined and testified
.
9 as follows:
10
11
12
13 BY MR. PRICE:
DIRECT EXAMINATION
14 Q Could you please state your name for the
25
Terri Carlock.
And who is your employer?
The Idaho Public Utilities Commission.
And what is your job title at the
Deputy administrator of the utilities
And on October 24th of this year did you
24 have occasion to prepare written direct testimony in this
15 record?
16 A
case, including Exhibit No. 128?
CSB REPORTING
[phone]
17 Q
.
18 A
19 Q
20 Commission?
21 A
22 division.
23 Q
2231 CARLOCK (Di)Staff
.1 A Yes, I did.
2 Q Do you have any corrections or additions
3 to that testimony?
4 A No.
5 MR. PRICE: At this time I would move that
6 Ms. Carlock's testimony, including Exhibit No. 128, be
7 spread upon the record as if read.
8 COMMISSIONER SMITH: If there's no
9 obj ection, we will spread the prefiled testimony upon the
10 record as if read and identify Exhibit 128.
11 (The following prefiled direct testimony
12 of Ms. Terri Carlock is spread upon the record.).13
14
20
21
22
23
.25
15
16
17
18
19
24
CSB REPORTING
[phone]
2232 CARLOCK ( Di)Staff
.
.
.
1 Q.Please state your name and address for the
2 record.
3 A.My name is Terri Carlock. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am the Deputy Administrator of the Utili ties
7 Division at the Idaho Public Utilities Commission. I am
8 responsible for the Accounting /Audi t Section and
9 coordinating Staff's policy posi tions with Staff
10 Administrator Randy Lobb.
11 Q.Please outline your educational background and
12 experience.
13 A. I graduated from Boise State University in
14 1980, with B.B.A. Degrees in Accounting and Finance.I
15 have attended various regulatory, accounting, rate of
16 return, economics, finance, and ratings programs. I am
17 currently the Vice-Chair of the National Association of
18 Regulatory Utilities Commissioners (NARUC) Staff
19 Subcommittee on Accounting and Finance. I previously
20 chaired the NARUC Staff Subcommittee on Economics and
21 Finance for more than 3 years. Under this subcommittee,
22 I also chaired the Ad Hoc Committee on Diversification.
23 I have been a presenter for the Institute of Public
24 Utili ties at Michigan State Uni versi ty and for many other
25 conferences. Since joining the Commission Staff in May
CASE NO. IPC-E-08-10
10/24/08
2233 CARLOCK, T (Di) 1
STAFF
.1 1980, I have participated in audits, performed financial
2 analysis on various companies, and have presented
3 testimony before this Commission on numerous occasions.
4 What is the purpose of your testimony in thisQ.
5 proceeding?
6 The purpose of my testimony is to present theA.
7 Staff's recommendation related to the overall cost of
8 capi tal for Iqaho Power Company to be used in the revenue
9 requirement in this case. I will address the appropriate
10 capital structure, cost rates and the overall rate of
.
.
11 return.
12 Please summarize your testimony.Q.
13 A. In my testimony on the overall rate of return,
14 I am recommending a return on common equity in the range
15 of 9.5% - 10.5% with a point estimate of 10.25%. The
16 recommended overall weighted cost of capital is in the
17 range of 7.68% - 8.18% with a point estimate of 8.057% to
18 be applied to the rate base for the test year.
19 Are you sponsoring any exhibits to accompanyQ.
20 your testimony?
21 Yes, I am sponsoring Exhibit No. 128 consistingA.
22 of 3 schedules.
23 Have you reviewed the testimony and exhibits ofQ.
24 Idaho Power witnesses Avera and Steven Keen associated
25 wi th the return components?
CASE NO. IPC-E-08-10
10/24/08
CARLOCK, T (Di) 2
STAFF
2234
1 A. Yes. Much of the theoretical approach used by.2 wi tnesses Avera and Steven Keen in their testimonies and
3 exhibits is generally the same as I have used. My
4 judgment in some areas of application results in
5 different outcomes.
6 Q.What legal standards have been established for
7 determining a fair and reasonable rate of return?
8 A.The legal test of a fair rate of return for a
9 utility company was established in the Bluefield Water
10 Works decision of the United States Supreme Court and is
11 repeated specifically in Hope Na tural Gas.
12 In Bluefield Water Works and Improvement Co. v..13 West Virginia Public Service Commission, 262 U. S. 679,
14 692, 43 S.Ct. 675, 67 L.Ed. 1176 (1923), the Supreme
15 Court stated:
16 A public utility is entitled to such rates as will
permi tit to earn a return on the value of the17 property which it employs for the convenience of the
public equal to that generally being made at the18 same time and in the same general part of the
country on investments in other business
19 undertakings which are attended by corresponding
risks and uncertainties; but it has no20 constitutional right to profits such as are realized
or anticipated in highly profitable enterprises or21 speculative ventures. The return should be
reasonably sufficient to assure confidence in the22 financial soundness of the utility and should be
adequate, under efficient and economical management,23 to maintain and support its credit and enable it to
raise the money necessary for the proper discharge24 of its public duties. A rate of return may be.25 /
CASE NO. IPC-E-08-10
10/24/08
2235 CARLOCK, T (Di) 3
STAFF
1 reasonable at one time and become too high or too
low by changes affecting opportunities for
investment, the money market and business conditionsgenerally..2
3
4 The Court stated in FPC v. Hope Natural Gas Company, 320
5 U.S. 591, 603, 64 S.Ct. 281, 88 L.Ed. 333 (1944):
6 From the investor or company point of view it is
important that there be enough revenue not only for
7 operating expenses but also for the capital costs of
the business. These include service on the debt and
8 di vidends on the stock.
9 . .. By that standard the return to the equity owner
should be commensurate with returns on investments10 in other enterprises having corresponding risks.
That return, moreover, should be sufficient to11 assure confidence in the financial integrity of the
enterprise, so as to maintain its credit and to12 attract capitaL. (Citations omitted.).13
14 The, Supreme Court decisions in Bluefield Water
15 Works and Hope Natural Gas have been affirmed in In re
16 Permian Basin Area Rate Case, 390 U.S. 747, 88 S.Ct 1344,
17 20 L.Ed 2d 312 (1968), and Duquesne Light Co. v. Barasch,
18 488 U. S. 299, 109 S. Ct . 609, 102 L. Ed. 2 d. 646 ( 1989) .
19 The Idaho Supreme Court has also adopted the principles
20 established in Bluefield Water Works and Hope Natural
21 Gas. See In re Mountain States Tel. & Tel. Co. 76 Idaho
22 474, 284 P.2d 681 (1955); General Telephone Co. v. IPUC,
23 109 Idaho 942, 712 P.2d 643 1986); Hayden Pines Water
24 Company v. IPUC, 122 ID 356, 834 P.2d 873 (1992)..25 As a result of these United States and Idaho
CASE NO. IPC-E-08-10
10/24/08 2236 CARLOCK, T (Di) 4
STAFF
.
.
.
1 Supreme Court decisions, three standards have evolved for
2 determining a fair and reasonable rate of return:
3 (1) The Financial Integrity or Credit Maintenance
4 Standard; (2) the Capital Attraction Standard; and,
5 (3) The Comparable Earnings Standard. If the Comparable
6 Earnings Standard is met, the Financial Integrity or
7 Credi t Maintenance Standard and the Capital Attraction
8 Standard will also be met, as they are an integral part
9 of the Comparable Earnings Standard.
10 Q.Have you considered these standards in your
11 recommendation?
12 A.Yes~ These criteria have been thoroughly
13 considered in the analysis upon which my recommendations
14 are based. It is also important to recognize that the
15 fair rate of return that allows the utility company to
16 maintain its financial integrity and to attract capital
17 is established assuming efficient and economic
18 management, as specified by the Supreme Court in
19 Bluefield Water Works.
20 Q.Please summarize the parent/subsidiary
21 relationships for Idaho Power Company.
22 A.Idaho Power's common stock is not traded.
23 Idaho Power Company is a wholly owned subsidiary of
24 IDACORP. Due to this parent/subsidiary relationship
25 there is no direct equity market data available for
CASE NO. IPC-E-08-10
10/24/08 2237 CARLOCK, T (Di) 5
STAFF
.
.
.
1 utili ty operations at Idaho Power. Idaho Power is the
2 primary subsidiary of IDACORP at this time.
3 Q.Why is the return on equity calculation
4 important?
5 A.The return on equity and the overall rate of
6 return provides the method for calculating the return
7 authorized. This return provides the level of
8 compensation to investors for the use of the capital
9 invested in the utility plant and equipment to serve
10 customers. The actual return investors receive is
11 derived from dividends and growth in stock price when the
12 shares are sold. Since the direct required return is not
13 a contractual calculation, the authorized return on
14 equity serves as the proxy.
15 Q.What approach have you used to determine the
16 cost of equity for Idaho Power?
17 A.I have primarily evaluated two methods: the
18 Discounted Cash Flow (DCF) method and the Comparable
19 Earnings method.
20 Q.Please explain the Comparable Earnings method
21 and how the cost of equity is determined using this
22 approach.
23 A.The Comparable Earnings method for determining
24 the cost of equity is based upon the premise that a given
25 investment should earn its opportunity costs. In
CASE NO. IPC-E-08-10
10/24/08 2238 CARLOCK, T (Di) 6
STAFF
.
.
.
1 competitive markets, if the return earned by a firm is
2 not equal to the return being earned on other investments
3 of similar risk, the flow of funds will be toward those
4 investments earning the higher returns. Therefore, for a
5 utili ty to be competi ti ve in the financial markets, it
6 should be allowed to earn a return on equity equal to the
7 average return earned by other firms of similar risk.
8 The Comparable Earnings approach is supported by the
9 Bluefield Water Works and Hope Natural Gas decisions as a
10 basis for determining those average returns.
11 Industrial returns tend to fluctuate with
12 business cycles, increasing as the economy improves and
13 decreasing as the economy declines. Utility returns are
14 not as sensi ti ve to fluctuations in the business cycle
15 because the demand for utility services generally tends
16 to be more stable and predictable. However, returns have
17 fluctuated since 2000 when prices in the electricity
18 markets dramatically increased. Electricity prices have
19 not seen the dramatic spikes lately so earnings are more
20 stable.
21 Q.Please evaluate interest rate trends.
22 A.The prime interest rate has decreased in the
23 last year since Idaho Power's last rate case from 7. 75%
24 to the current rate of 4.5%. The federal funds rate and
25 other rates have also decreased this year.
CASE NO. IPC-E-08-10
10/24/08
CARLOCK, T (Di) 7
STAFF
2239
.
.
.
1 Q. Please provide the current index levels for the
2 Dow Jones Industrial Average and the Dow Jones Utility
3 Average.
4 A.The Dow Jones Industrial Average (DJIA) closed
5 at 8519.21 on October 23, 2008. The DJIA all-time high
6 of 14,000 was reached on July 19, 2007. The Dow Jones
7 Utility Average closed at 348.10 on October 23, 2008. The
8 52-week high was 552. 74 for the Dow Jones Utility
9 Average.
10 Q.Please explain the risk differentials between
11 industrials and utilities.
12 A.Risk is a degree of uncertainty relative to a
13 company. The lower risk level associated with utili ties
14 is attributable to many factors even though the
15 difference is not as great as it used to be. Utili ties
16 continue to have limited competition for distribution of
17 utili ty services wi thin the certificated area. With
18 limited competition for regulated services, there is less
19 chance of losses related to pricing practices, marketing
20 strategy and advertising policies. The competitive risks
21 for electric utili ties have changed with increasing
22 non-utili ty generation, deregulation in some states, open
23 transmission access, and changes in electricity markets.
24 However, competi ti ve risks are limited for Idaho Power
25 utility operations. The demand for electric utility
CASE NO. IPC-E-08-10
10/24/08
CARLOCK, T (Di) 8
STAFF
2240
.
.
.
1 services is relatively stable and certain or increasing
2 compared to that of unregulated firms and even other
3 utility industries.
4 Competitive risks continue to be lower for
5 Idaho Power than for many other electric companies
6 primarily because of the low-cost source of power, the
7 low retail rates compared to national averages, the PCA,
8 and the FCA. The proposed changes to the PCA (Case No.
9 IPC-E-08-19) qn the sharing percentage and the load
10 growth adj ustment are seen as posi ti ve by institutional
11 investors and the investment community. This case
12 presents the settlement of parties, but has not been
13 decided by the Commission. The risk differential between
14 Idaho Power and other electric utili ties is based on the
15 resource mix and the cost of those resources. All
16 resource mixes have risks specific to resources chosen.
17 The demand for electric utility services of Idaho Power
18 is increasing at predictable rates. This low demand risk
19 is partially due to the low embedded power cost, the risk
20 management program to manage power costs and the customer
21 mix of the power users.
22 Under regulation, utilities are generally
23 allowed to recover through rates, reasonable, prudent and
24 justifiable cost expenditures related to regulated
25 services. Unregulated firms have no such assurance.
CASE NO. IPC-E-08-10
10/24/08
2241 CARLOCK, T (Di) 9
STAFF
.
.
.
1 Utili ties in general are sheltered by regulation for
2 reasonable cost recovery risks, even if it isn't 100%,
3 making the average utility less risky than the average
4 unregulated industrial firm.
5 As everyone is aware, current market trends and
6 earnings levels have dramatically declined. I believe
7 Idaho Power continues to be in a better position than
8 many to fund its capital requirements. The current
9 credi t and investment markets are making capitalization
10 more difficult for all. In my opinion, as investors
11 reevaluate their investment portfolios, utility stocks
12 wi th the primary operation being the utility; will be
13 favored over higher risk operations. On July 10, 2008
14 Idaho Power issued 10-year First Mortgage Bonds at
15 6.025%. This issuance meets current needs at a
16 reasonable rate and places Idaho Power in a reasonable
17 posi tion to meet near-term needs with its credit lines.
18 Company credit lines extend through 2012.
19 Nationally the electric utility industry as
20 shown on Exhibit No. 128, Schedule 1 has seen common
21 equity ratios decline from 46% at 12/31/2006 to 45% at
22 12/31/2007 and 44% at 6/30/2008. This means long-term
23 debt ratios increased over the respective time periods;
24 54%, 55% and 56%. Company witness Avera, Exhibit No. 26
25 shows similar historical averages with 43.3% equity and
CASE NO. IPC-E-08-10
10/24/08 2242 CARLOCK, T (Di) 10
STAFF
.
.
.
1 55.7% debt. This exhibit also shows projected average
2 ratios of 47.6% equity and 51.9% debt. The capital
3 structure recommended for Idaho Power Company is
4 approximately 49% common equity and 51% long-term debt.
5 The recommended equity ratios for Idaho Power are better
6 than the national average, historical and proj ected,
7 reflecting lower risk for Idaho Power.
8 Authorized returns by State Commissions for
9 electric utili ties during 2007 and the First Quarter of
10 2008 range from 9.1% in New York to 11.25% in Georgia.
11 During this period, 25 states decided cases authorizing
12 rates of return on equity. Many of the decisions, 14 out
13 of 25 or 56%, authorized a return on equity between 9.5%
14 and 10.5%.
15 Considering all of these comparisons, I believe
16 a reasonable return on equity attributed to Idaho Power
17 is 9.5% - 10.5% under the Comparable Earnings method.
18 Q.You indicated that the Discounted Cash Flow
19 method is utilized in your analysis. Please explain this
20 method.
21 The Discounted Cash Flow (DCF) method is basedA.
22 upon the theory that (1) stocks are bought for the income
23 they provide (i. e., both dividends and/or gains from the
24 sale of the stock), and (2) the market price of stocks
25 equals the discounted value of all future incomes. The
CASE NO. IPC-E-08-10
10/24/08
CARLOCK, T (Di) 11
STAFF
2243
.
.
.
1 discount rate, or cost of equity, equates the present
2 value of the stream of income to the current market price
3 of the stock. The formula to accomplish this goal is:
4 01 PN02ON
Po PV ------ + ------ +... + ------ + ------
( 1 + ks) 1 ( 1 + ks ) 2 ( 1 + ks ) N ( 1 + ks ) N5
6 Po = Current Price
7 D Dividend
8 Capitalization Rate, Discount Rate, or Requiredks
9 Rate of Return
10 N = Latest Y~ar Considered
11 The pattern of the future income stream is the
12 key factor that must be estimated in this approach. Some
13 simplifying assumptions for ratemaking purposes can be
14 made without sacrificing the validity of the results.
15 Two such assumptions are:(1) dividends per share grow
16 at a constant rate in perpetuity and (2) prices track
17 earnings. These assumptions lead to the simplified DCF
18 formula, where the required return is the dividend yield
19 plus the growth rate (g):20 D
ks =+ g
21 Po
22 Have you factored flotation costs in with yourQ.
23 cost of capital analysis?
24 Yes, I have considered direct flotation costsA.
25 in my analysis by increasing the dividend yield component
CASE NO. IPC-E-08-10
10/24/08
2244 CARLOCK, T (Di) 12
STAFF
1 of the DCF analysis. Because only direct costs should be.2 considered, I have used a flotation factor of 2% assigned
3 to the utility operations. This practice continues to be
4 reasonable with recent issuances and expected near-term
5 issuances placed though the Company's Investment Plans
6 where the actual flotation costs are substantially lower
7 than direct market issuances. I have therefore adjusted
8 the DCF formula to include the direct flotation costs as
9 "df" .10 D
ks = C--- (1 + df))+ g11 Po
12 Q.What is your estimate of the current cost of.13 capi tal for Idaho Power using the Discounted Cash Flow
14 method?
15 A.The current cost of equity capital for Idaho
16 Power, using the Discounted Cash Flow method with IDACORP
17 data, is between 8.9% - 9.8%. The low range of 8.9% is
18 calculated using an analyst target stock price of $31 and
19 the growth rate of 5%.
20 C($1.20/$31)1.02)+5%
21 The high range of 9.8% is calculated using a current
22 stock price of $25.64 and a growth rate of 5%.
23 C($1.20/$25.64)1.02)+5%
24 Due to ongoing capital requirements, I believe a dividend.25 yield of 4.4%, with an average growth rate of 5% is
CASE NO. IPC-E-08-10
10/24/08
2245 CARLOCK, T (Di) 13
STAFF
.
.
.
1 reasonable and representative resulting in a DCF return
2 on equity of 9.4%.
3 Q.How is the growth rate (g) determined?
4 A.The growth rate is the factor that requires the
5 most extensive analysis in the DCF method. It is
6 important that the growth rate used in the model be
7 consistent with the dividend yield so that investor
8 expectations are accurately reflected and the growth rate
9 is not too large or too small.
10 I have used an expected growth rate of 4% - 6%.
11 This expected growth rate was derived from an analysis of
12 various historical and proj ected growth indicators,
13 including growth in earnings per share, growth in cash
14 dividends per share, growth in book value per share,
15 growth in cash flow and the sustainable growth.
16 Q.What are the costs related to the capital
17 structure for debt?
18 A.The cost of debt of 5.927% is shown on Exhibit
19 No. 128, Schedule 2. The actual debt costs vary slightly
20 from this projection but result in an insignificant,
21 0.001%, change in the weighted debt cost. This
22 information is not yet public so I have not used it due
23 to the minor difference.
24 Q.What capital structure has Staff used for Idaho
25 Power to determine the overall cost of capital?
CASE NO. IPC-E-08-10
10/24/08
2246 CARLOCK, T (Di) 14
STAFF
.
.
.
1 A.Exhibi t No. 128, Schedule 3 shows the capital
2 structure, debt cost utilized and the overall rate of
3 return. Staff has accepted the estimated December 31,
4 2008 capital structure and debt cost as shown on Company
5 witness Keen Exhibit Nos. 27 and 28 as reasonable. The
6 actual capital structure and debt cost rates at June 30,
7 2008 and September 30, 2008 vary slightly. The current
8 market availability of funds will impact the capital
9 structure with slightly more debt being utilized so the
10 capital structure of 50.7% debt and 49.3% equity as shown
11 on Exhibit No. 128, Schedule 3 is reasonable.
12 Q.You indicated the cost of common equity range
13 for Idaho Power is 9.5% - 10.5% under the Comparable
14 Earnings method and 8.9% - 9.8% under the Discounted Cash
15 Flow method. What is the cost of common equity capital
16 you are recommending?
17 A.The fair and reasonable cost of common equity
18 capital I am recommending for Idaho Power and is in the
19 range of 9.5% - 10.5%. Although any point within this
20 range is reasonable, the return on equity granted would
21 not normally be at either extreme of the fair and
22 reasonable range. I utilized a point estimate of 10.25%
23 in calculating the overall rate of return for the revenue
24 requirement.
25 What is the basis for your point estimate beingQ.
CASE NO. IPC-E-08-10
10/24/08
CARLOCK, T (Di) 15
STAFF
2247
.1 10.25% when your range is 9.5% - 10.5%?
2 The 10.25% return on equity point estimateA.
3 utilized is based on a review of market data and
4 comparables, average risk characteristics for Idaho
5 Power, operating characteristics and the capital
6 structure. A point above the midpoint recognized the
7 requirement for system capital investments to serve
8 customers.
9 What is the overall weighted cost of capitalQ.
10 recommended for Idaho Power?
11 A.The overall weighted cost of capital
12 recommended by Staff is in the range of 7.68% - 8.18%..
.
13 For use in calculating the revenue requirement, a point
14 estimate consisting of a return on equity of 10.25% and a
15 resulting overall rate of return of 8.057% was utilized
16 as shown on Schedule 3, Exhibit No. 128.
17 Does this conclude your direct testimony inQ.
18 this proceeding?
19 Yes, it does.A.
20
21
22
23
24
25
CASE NO. IPC-E-08-10
10/24/08
2248 CARLOCK, T (Di) 16
STAFF
.1
2 open hear ing . )
(The following proceedings were had in
MR. PRICE: I would now tender this
4 witness for cross-examination.
.
.
3
5
6
7 Honor.
8
9
10
11
12 no questions.
13
14
15
16
17
18
19
20 BY MR. WARD:
21
22 you?
23
24
Q
A
Q
COMMISSIONER SMITH: Mr. Boehm.
MR. BOEHM: I have no questions, Your
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: No questions.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Thank you, Madam Chair,
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Ward.
MR. WARD: Just quickly.
CROSS-EXAMINATION
Ms. Carlock, do you have Exhibit 156 with
Yes, I do.
If you look at page 3 of 4, this is where
25 Staff highlighted the Electric Utility West companies, so
CSB REPORTING
[phone]
2249 CARLOCK (X)Staff
.
.
.
1 fi ve electric utility companies in the West. Do you see
2 that?
3 A Yes, I do.
4 Q And on the far right-hand side you'll see
5 the column headed "Estimated 3-5 Year Price Appreciation"
6 or let me represent that's what those abbreviations mean,
7 price appreciation. Can you tell the Commission what
8 that means in Value Line terms?
9 A In Value Line terms, that looks at where
10 the price is expected to go over the next three to five
11 years and in this case, it's from nil to 20 percent.
12 Q For IDACORP?
13 A For I DACORP .
14 Q Now, if you'd look back to the first page,
15 in the middle of the page -- and by the way, this page
16 and its data repeats every week in Value Line, doesn't
17 it?
18 A It does.
19 Q And as of -- this is December 19th, as of
20 December 19th, if you look at the middle of the page,
21 Value Line reports the median price appreciation
22 potential for all 1,700 stocks in the hypothesized
23 economic environment three to five years hence as 155
24 percent. Do you see that?
25 A Yes, I see that.
CSB REPORTING
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2250 CARLOCK (X)Staff
.
.
20
1 Q So would it be correct to say that what
2 Value Line is saying is if we're right about the
3 hypothetical stock market or stock environment three to
4 fi ve years out, the median appreciation potential for all
5 stocks in our coverage universe is roughly
6 double-and-a-half, 155 percent?
7 A That's correct, in that three- to
8 five-year time frame.
9 Q And when you see that as an investor, it's
10 kind of an obverse signal; that is, compared to times
11 when Value Line has been at the market high, you can see
12 just below the 155 percent the appreciation potential was
13 35 percent and at the previous market low, it was only
14 115 percent, so what the 155 percent means is, not
15 surprisingly, Value Line thinks, at least hypothetically,
16 the market is very cheap.
17 A I would interpret that to mean that we're
18 in a down market right now and in three to five years
19 it's going to increase 155 percent.
Q And by comparison, flipping back over to
21 page 3 of 4, Value Line has seen only a nil -- the"N"
22 represents nil, doesn't it?
23
24.25
A That's correct.
Q -- nil to 20 percent appreciation
potential for IDACORP and would that suggest that there
CSB REPORTING
[phone]
2251 CARLOCK (X)Staff
.
.
.
1 has been a huge flight to safety in IDACORP and other
2 utili ty stocks in the West?
3 A The 20 percent appreciation indicates that
4 they expect only 20 percent appreciation from the current
5 market, so compared to the market in general, IDACORP
6 would be in a better situation. That's the same as what
7 you would see in looking at the ranking changes from the
8 industry as a whole. They have increased from a rank of
9 60 up to a rank of 24 for the Electric Utility West
10 industry.
11 Q And maybe putting it more crudely, what
12 Value Line is saying here is even three to five years
13 out, these five timely stocks, as they characterize them,
14 in the Western Electric Utility grids are nearly fully
15 valued suggesting that they've been very desirable to
16 investors, have they not?
17 A I would think that the utility stocks in
18 general and particularly the ones in the West are more
19 desirable for many reasons. One of them is just this
20 price appreciation.
21 MR. WARD: Thanks. That's all I have.
22 COMMISSIONER SMITH: Ms. Nordstrom. Oh,
23 actually, Mr. Purdy, did you have any questions?
24 MR. PURDY: No, thank you.
25 COMMISSIONER SMITH: Ms. Nordstrom.
CSB REPORTING
[phone]
2252 CARLOCK (X)Staff
.
.
.
1 MS. NORDSTROM: Thank you.
2
3 CROSS-EXAMINATION
4
5 BY MS. NORDSTROM:
6 Q Referring to Staff Exhibit 154, page 3 --
7 A That's 156. I'm sorry, it was
8 mislabeled.
9 Q I've corrected, like, three of them, but
10 apparently not this one. If you look at those five
11 electric utili ties, isn' t it true that Idaho Power is
12 second from the bottom as far as potential to
13 appreciate?
14 A If you're looking at the range of N to 20
15 versus the N to 10 percent, it is second from the bottom
16 in the range to appreciate, but that also means that it
17 has not dropped as much potentially as the other stocks
18 may have.
19 Q Or it's not expected to grow as much;
20 correct?
21 A That could be one interpretation. In the
22 current market, I believe it's more associated with price
23 appreciation, though, from the market.
24 Q So say Idaho Power were to appreciate 20
25 percent in its stock price, wouldn't that get Idaho Power
CSB REPORTING
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2253 CARLOCK (X)Staff
.
.
.
1 back to a stock price approximately where it was at the
2 beginning of this year?
3 A I'd have to look at where the price was
4 the beginning of this year. It seems like it was in the
5 30's.
6 Q Well, ~o your knowledge, does that sound
7 about right?
8 It WOUld increase, yes, closer to thatA
9 range.
10 Q During the year since Idaho Power's last
11 rate case, financial market volatility has increased;
12 correct?
13 A Yes.
14 Q And Id~ho Power's credit ratings have
15 decreased; correct?
16 A In 2007 and early 2008 there was a rating
1 7 decrease.
18 Yet yomr recommendation in this case forQ
19
¡, ireturn on equity has mot changed; correct?
20 A That's correct. The return on equity
21 piece of that for the change in the ratings, that's
22 behind the Company at this point in time. Now the
23 Company is on' a buy recommendation which also ties in
24 wi th where investors lay see utili ties and where they see
25
¡i
the market going in general as well as for the utility
CSB REPORTING
[phone]
.CARLOCK (X)Staff2254
.
.
.
1 industry going forward. It also represents that -- I was
2 trying to tie it back to your question and I lost your
3 question. I'm sorry, please repeat it.
4 Q You know, you answered my question, so I'm
5 good.
6 A Okay.
7 MS. NORDSTROM: Thank you. I have nothing
8 further.
9 COMMISSIONER SMITH: Do we have questions
10 from the Commissioners?
11 COMMISSIONER REDFORD:No.
12 COMMISSIONER SMITH: Nor I. Do you have
13 redirect, Mr. Price?
14 MR. PRICE: No redirect on that.
15 COMMISSIONER SMITH: Thank you,
16 Ms. Carlock.
17 (The witness left the stand.)
18 COMMISSIONER SMITH: Well, we have Smith
19 and Reading.
20 MS. NORDSTROM: Could we release Mr. Avera
21 or excuse him from participating on the telephone any
22 further?
23 COMMISSIONER SMITH: Certainly, unless
24 there's an objection. He may be excused.
25 MS. NORDSTROM: Thank you very much.
CSB REPORTING
[phone]
2255 CARLOCK (X)Staff
.1
2
3
DR. AVERA: Thank you very much.
MS. NORDSTROM: Thank you, Bill.
COMMISSIONER SMITH: I'm sure he can't
4 have a better time anywhere else.
5
6 call Lori Smith.
7
MS. NORDSTROM: Well, Idaho Power will
8 LORI SMITH,
9 produced as a witness at the instance of the Idaho Power
10 Company, having been first duly sworn, was examined and
11 testified as follows:
.12
13
14
15 BY MS. NORDSTROM:
16 Q
DIRECT EXAMINATION
Good afternoon.
Good afternoon.
Please state your name and spell your last
19 name for the record.
17 A
My name is Lori Smith, S-m-i-t-h.
By whom are you employed and in what
I'm employed by Idaho Power Company. I am
24 the vice president of corporate planning and the chief.
18 Q
20 A
21 Q
22 capacity?
23 A
25 risk officer.
CSB REPORTING
[phone]
2256 SMITH (Di)
Idaho Power Company
.
.
.
1 Q Are you the same Lori Smith that filed
2 direct testimony on June 27th, 2008 and prepared Exhibit
3 Nos. 29 through 34?
4 A Yes.
5 Did you also file rebuttal testimony onQ
6 December 3rd, 2008 and prepare rebuttal Exhibits 83
7 through 86?
8 A Yes.
9 MS. NORDSTROM: Idaho Power is currently
10 distributing a list of your corrections for the
11 convenience of the Commission and the parties.
12 Q BY MS. NORDSTROM: Could you please
13 describe those corrections?
14 A Yes. I have two corrections in my direct
15 testimony and five corrections in my rebuttal testimony.
16 Many of them are just number changes, slight number
17 changes, so beginning on page 5, line 18, at the end of
18 that sentence, please add the word "adjustments" after
19 the words "annualizing." Page 24, line 22, replace
20 "6.72" with "6.27."
21 In my rebuttal testimony on page 15, line
22 20, replace "Order 888" with "Orders 693, 705, 706 and
23 706A." On page 33, line 14, replace "884,747" with
24 "884,788." Page 44, line 17, replace "3,445" with
25 "10,768," and' on 53, line 6, replace "193,901" with
CSB REPORTING
[phone]
2257 SMITH (Di)
Idaho Power Company
.
10
.
.
1 "163,901," and finally, on my rebuttal Exhibit No. 83,
2 replace "Exhibit X" with "Exhibit 83."
3 Thank you. Is that all the correctionsQ
4 you have?
5 That's all that I'm aware of, yes.A
6 If I were to ask you the questions set outQ
7 in your corrected prefiled testimony, would your answers
8 be the same today?
9 A Yes.
MS. NORDSTROM: I would move that the
11 prefiled direct and rebuttal testimony of Lori Smith be
12 spread upon the record as if read and Exhibits 29 through
13 34 and 83 through 86 be marked for identification.
14 COMMISSIONER SMITH: Without obj ection, it
15 is so ordered.
16 (The following prefiled direct and
17 rebuttal testimony of Ms. Lori Smith is spread upon the
18 record.)
19
20
21
22
23
24
25
CSB REPORTING'
[phone]
2258 SMITH (Di)
Idaho Power Company
.1 Q. Would you please state your name, business
2 address, and present occupation?
3 A.My name is Lori Smith and my business address
4 is 1221 West Idaho Street, Boise, Idaho. I am employed
5 by Idaho Power Company ("Idaho Power" or "Company") as
6 Vice President of Corporate Planning and Chief Risk
7 Officer.
8 Q.What is your educational background?
9 A.I graduated in 1983 from Boise State
10 University, Boise, Idaho, receiving a Bachelor of
.
.
11 Business Administration degree in Information Sciences.
12 In 1999, I was awarded the designation of Chartered
13 Financial Analyst. In 2008, I completed a two-part
14 course in Decision Analysis and Decision Quality in
15 Organizations at the Stanford Center for Professional
16 Development. I have also attended numerous seminars and
17 conferences related to utility accounting, corporate
18 finance, and risk related topics.
19 Would you please outline your businessQ.
20 experience?
21 From 1983 to 1986, I was employed by IdahoA.
22 Power Company .and assigned to the Materials Management
23 Department. From 1986 to 1994, I served as a Financial
24 Accountant and later as a Budget Accountant. I was
25 promoted to Business Analyst in 1994. In 1996, I was
2259 SMITH, DI 1
Idaho Power Company
.
.
.
1 promoted to Strategic Analysis Team Leader. In 2000, I
2 assumed the position of Director of Strategic Analysis.
3 In 2003, I was named Director of Strategic Analysis and
4 Risk Management. In 2004, I was promoted to the position
5 of Vice President of Finance and Chief Risk Officer. In
6 2008, I assumed my current position as Vice President of
7 Corporate Planning and Chief Risk Officer.
8 What are your duties as Vice President ofQ.
9 Corporate Planning and Chief Risk Officer?
10 My responsibilities include the oversight ofA.
11 corporate development, strategic planning, and risk
12 management processes for Idaho Power Company. Corporate
13 development includes acquisitions , divestitures, and
14 joint-ventures. Strategic planning includes development
15 of analyses, strategies, and operating plans. Risk
16 management includes activities related to managing
17 market, credit, and operational risk exposure from an
18 enterprise perspective.
19 I am tasked with ensuring the best use of Idaho
20 Power's resources by defining and planning the Company's
21 strategic and, long-range goals. I am also responsible.
22 for the analysis of the financial impacts of regulatory
23 strategy to ensure successful implementation and provide
24 meaningful insight into strategic alignment, offer
25 return-enhancing decision support, and identify
opportunities' for
2260 SMITH, DI 2
Idaho Power Company
.
.
.
1 revenue growth. I direct the development of operational
2 forecasts and analysis both long- and short-term. In
3 addi tion, I am the corporate board representative for
4 Ida-West Energy and IDACORP Financial Services. I have
5 subsidiary leadership responsibilities that include
6 setting goals and defining investment criteria and
7 performance requirements. I direct the acti vi ties
8 related to the organization's market risk and credit
9 exposure to protect against adverse movements in net
10 Finally, I am responsible forpower supply costs.
11 designing, developing, and implementing an Enterprise
12 Risk Management process for IDACORP, Inc., and Idaho
13 Power Company.
14 Q. What is the purpose of your testimony in this
15 proceeding?
16 The purpose of my testimony is three-fold.A.
17 First, I will present the Company's historical actual
18 audi ted financial information for the twelve-month period
19 ended December 31, 2007. My testimony also identifies
20 certain adjustments to operating expenses and rate base
21 that result in an adjusted historical actual twelve-month
22 period ended December 2007. Second, my testimony will
23 present the methodologies used to adjust historical 2007
24 financial data to test year 2008 levels. Third, I will
25 present the traditional and other ratemaking adjustments
2261 SMITH, DI 3
Idaho Power Company
.
.
.
1 also used in the development of the Company's proposed
2 2008 test year. The adjusted historical actual
3 twelve-month period ended December 31, 2007, was the
4 basis by which the Company's proposed 2008 test year was
5 developed and is discussed in the latter part of my
6 testimony.
7 Q.Please describe the types of adjustments you
8 have made to the 2007 actual data.
9 A.The adjustments to 2007 actual data to arrive
10 at the 2007 adjusted actual data are what I describe as
11 standard regulatory adjustments. These adjustments
12 included removing structures and certain properties
13 wi thin Plant Held for Future Use for which the use is
14 uncertain (e. g., subj ect to being split or possibly
15 removed prior to the utilization of the property) as well
16 as removal of other expenses as previously directed by
17 the Commission. These Commission-directed adjustments
18 include the removal of general advertising expenses,
19 specific memberships and contributions, certain
20 management expenses, and other exclusions that, although
21 justified, may appear inappropriate for regulatory
22 recovery. Also removed is the unamortized portion of the
23 Electric Plant Amortization Adjustment associated with
24 the Prairie Power Rural Electric Cooperative purchase,
25 plant deemed not used and useful at Bridger Coal, the
operating portion of Financial Accounting
2262 SMITH, DI 4
Idaho Power Company
.
.
.
1 Standard 87 Pension expense, the financial impacts of the
2 Energy Efficiency Rider revenues and expenses, and,
3 finally, the removal of specific intervenor funding
4 amortization that was included in the 2007 test year for
5 recovery.
6 Q.Please describe the methods you developed to
7 further adjust 2007 data to 2008 test year levels.
8 A.There are three primary methods that were
9 developed and applied to adjust 2007 financial data to
10 test year 2008 levels: compound growth rates, known and
11 measurable adj ustments, and annuali zing adj ustments.
12 Q.Please describe how compound growth rates were
13 applied.
14 A. Where appropriate, methodologies to address
15 growth were applied to the 2007 adjusted actuals.
16 Compound growth rates were either three- or five-year
17 compounded annual growth rates and were applied to
18 investments less than $2 million and certain O&M expenses
19 and annualizing adjustments. Known and measurable
20 adjustments were made for scheduled investments of
21 greater than $2 million. Annualizing adjustments are
22 those adj ustments that are made to certain expense and
23 rate base items to reflect them as though they have been
24 in existence for the entire year, or at year-end levels.
25 These include' year-end payroll, incentive pay, the
2263 SMITH, DI 5
Idaho Power Company
.
.
.
1 2009 salary structure adjustment, depreciation expense
2 and reserve, plant placed in service during 2008 in
3 excess of $2 million with the associated property taxes
4 and insurance, and the Company-directed spending
5 containment.
6 Q.Will you be supporting any of the normalizing
7 adjustments to the 2008 forecasted test year?
8 A.No. Ms. Schwendiman will address the
9 normalizing adj ustments to sales and revenues and Mr.
10 Said will address the normalization of power supply
11 costs.
12 HISTORICA 2007 TEST YEA DATA WITH ADJUSTMNTS
13 Q. What are the components of the historical
14 actual financial information that you are sponsoring?
15 A.In referring to these components in my
16 testimony, I will use the account names from the
17 Commission-approved Uniform System of Accounts ("USA").
18 The components include the following items: (1) other
19 operating revenues, (2) other revenues and expenses, (3)
20 operation and maintenance expenses, (4) property
21 insurance expenses, (5) regulatory commission expenses,
22 (6) depreciation and amortization expenses, (7)
23 amortizations, adjustments, gains, and losses, (8)
24 regulatory debits, (9) taxes other than income taxes,
25 (10) Idaho Energy Resources Company (" IERCo") Statement
2264 SMITH, DI 6
Idaho Power Company
.
10
.
.
1 of Income and Rate Base Components, (11) electric plant
2 in service and related
3
4 /
5
6 /
7
8 /
9
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
2265 SMITH, Dr 6a
Idaho Power Company
.
.
.
1 items, (12) materials and supplies, (13) deferred
2 conservation programs, (14) other deferred programs, (15)
3 plant held for future use, (16) deferred income taxes,
4 (17) customer advances for construction, and (18) certain
5 deductions from operating and maintenance expenses.
6 Are you sponsoring exhibits in this proceeding?Q.
7 Yes. I am sponsoring Exhibits No. 29 throughA.
8 34. The work papers supporting my testimony and exhibits
9 have also been included with the Company's general rate
10 case filing.
11 Would you please describe Exhibit No. 29?Q.
12 Exhibi t No. 29 is a compilation of theA.
13 Company's supporting schedules for the adj usted
14 historical actual data for the twelve-month period ended
15 December 2007. Page 1 of Exhibit No. 29 reflects the
16 detail for Other Operating Revenues - Accounts 451, 454,
17 and 456. Pag~ 2 reflects the detail of Other Revenues -
18 Account 415 and Expenses 416. Pages 3 through 6 reflect
19 the Operations and Maintenance Expenses ("O&M") by USA
20 account.
21 Please describe the adjustment you have made toQ.
22 operations and maintenance expense on Exhibit No. 29,
23 page 6, lines 16 and 20.
24
25
2266 SMITH, DI 7
Idaho Power Company
.
.
.
1 A.Account 926 - Employee Pension and Benefits on
2 line 20 is where FAS 87 Pension expense is recorded. It
3 is then offset in Account 922 - Administrative Expenses
4 Transferred-Credit on line 16 and then spread among all
5 accounts in which labor is charged. The temporary effect
6 of this adjustment is to remove FAS 87 Pension expense
7 from these accounts so that when escalated for 2008 the
8 FAS 87 Pension expenses are not escalated as well. The
9 net effect of this adj ustment results in a zero impact to
10 the revenue requirement. I discuss the complete removal
11 of the FAS 87 Pension expense, in accordance with
12 Commission Order No. 29505, included in operations and
13 maintenance expenses later in my testimony.
14 Q. Would you please describe pages 7 through 13 of
15 Exhibit No. 29?
16 A.Page 7 of Exhibit No. 29 reflects the detail of
17 Property Insurance Expense - Account 924. Page 8 shows
18 the detail of Regulatory Commission Expenses - Account
19 928. Pages 9' and 10 include Depreciation and
20 Amortization Expense by plant account. Page 11 of
21 Exhibit No. 29 presents the Prairie Power acquisition
22 amortization adj ustment. Page 12 reflects Regulatory
23 Debits - Account 407.3 for Professional Fees amortization
24 that was created by Order No. 29505. Page 13 shows the
25 detail of Taxes
2267 SMITH, DI 8
Idaho Power Company
.
.
23
1 Other Than Income Taxes.
2 Q.Please explain the adjustments you have made to
3 page 13 of Exhibit No. 29, Taxes Other Than Income, to
4 arrive at the adjusted 2007 actuals.
5 A.The sum of lines 1, 2, and 20 on page 13,
6 column 1, of Exhibit No. 29 for Federal Unemployment,
7 Social Security, and State Unemployment taxes
8 respectively are eliminated by line 23, column 1, the
9 State and Federal payroll loading. The payroll loading
10 effectively removes these amounts from Taxes Other Than
11 Income and spreads them over all accounts that receive
12 labor charges. Therefore, the adjustment on page 13,
13 column 2, linès 1, 2, 20, and 23 eliminates these
14 expenses in their entirety from this schedule as they
15 have no impact to the revenue requirement.
16 Q.Would you please describe page 14 of Exhibit
17 No. 29?
18 A.Page 14 of Exhibit No. 29 develops the net
19 earnings from IERCo that are added to the booked
20 operating income for rate making purposes.
21 Q.How, does the Company treat IERCo' s earnings and
22 investment for rate making purposes?
A.The primary purpose of IERCo is to mine the
24 coal that fuels the Jim Bridger thermal power plant in.25 Wyoming. Consistent with prior Commission orders, the
2268 SMITH, DI 9
Idaho Power Company
.
.
.
1 Company treats IERCo' s coal operations as a part of its
2 utili ty operation and accordingly adds the current year
3 IERCo earnings to electric operating income and the
4 investment in IERCo to the net electric rate base.
5 Accordingly, the interest expense (line 13, page 14 of
6 Exhibi t No. 29) on notes payable to Idaho Power Company
7 has been added back to IERCo' s Net Income from
8 Operations. Additionally, the notes payable (column 3,
9 line 14, page 24 of Exhibit No. 29) to Idaho Power
10 Company have been added to IERCo' s rate base in
11 determining the Company's net investment in IERCo to be
12 included in total system rate base.
13 Q.Why have you made these adj ustments to IERCo' s
14 net earnings and rate base in this proceeding?
15 A.These adj ustments were made to increase IERCo' s
16 rate base for notes payable to Idaho Power in the amount
17 of $14,794,368 and the associated interest expense
18 adjustment net of income tax of $545,915 to allow IERCo's
19 rate base and earnings to reflect only the cash required
20 to fund IERCo operations for the year 2007. If IERCo
21 were to use these funds to make a distribution of
22 earnings to the Company, or if the Company were to
23 actually fold' IERCo into its own operations, the result
24 would be the same as presented herein.
25
2269 SMITH, DI 10
Idaho Power Company
.
..
22
1 Q.Would you please describe the data contained on
2 pages 15 through 24 of Exhibit No. 29?
3 A.Pages 15 through 24 of Exhibit No. 29 reflect
4 the development of all the components applicable to the
5 combined system rate base of the Company for the year
6 2007. Page 15 reflects the balance by month and the
7 thirteen month average of Electric Plant in Service -
8 Account 101. Page 16 reflects the balance by month and
9 the thirteen-month average of Accumulated Provision for
10 Depreciation - Account 108. Page 17 reflects the balance
11 by month and the thirteen month average of Accumulated
12 Provision for Amortization - Account 111. Page 18
13 reflects the balance by month and the thirteen-month
14 average of Materials and Supplies - Accounts 154 and 163.
15 Page 19 and Page 20 of Exhibit No. 29 reflect the balance
16 of the Company's Conservation and Other Deferred
17 Programs. For these programs the Company includes the
18 December 31, 2007, ending balance in rate base consistent
19 wi th prior orders of this Commission. Page 21 reflects
20 the year-end balance of Plant Held for Future Use -
21 Account 105.
Q.Would you please describe in more detail Other
23 Deferred Programs on Page 20 of Exhibit No. 29?
24.25
A.Yes,. Previous Commission-approved programs
included on page 20 of Exhibit No. 29 are the American
2270 SMITH, DI 11
Idaho Power Company
.
.
1 Falls Bond Refinancing costs, the 2003 Incremental
2 Security Costs and Intervenor Funding costs that resulted
3 from the following Idaho cases: (1) the 2005 general rate
4 case (IPC-E-05-28), (2) the load growth adj ustment case
5 (IPC-E-06-08), and (3) the fixed cost adjustment case
6 (IPC-E-04-15). The American Falls Bond Refinancing is
7 being amortized over the life of the American Falls bond
8 and will be fully amortized in 2025. The 2003
9 Incremental Security Costs that were incurred as a result
10 of concerns relating to the September 11, 2001, attacks
11 are being amortized over 5 years and will be fully
12 amortized in 2008. The Intervenor Funding cost is being
13 amortized over one year and will be fully amortized in
14 2009.
15 Also, included on this exhibit are Oregon's and
16 the FERC' s jurisdictional portion of unrecovered costs of
17 the Grid West, Loans.
18 Q.Could you also describe in more detail Plant
19 Held for Future Use - Account 105 on page 21 of Exhibit
20 No. 29?
21 A.Yes. As it did in its 2007 general rate case
22 (IPC-E-07-08), the Company has included Plant Held for
23 Future Use as part of its 2007 actual costs. Idaho Code
24 Section 61-502A allows the Commission to set rates for.25 utili ties that include a rate of return on property held
2271 SMITH, DI 12
Idaho Power Company
.
.
.
1 for future use if the Commission makes an explicit
2 finding that such a return is in the public interest. In
3 preparing this case, the Company performed a review and
4 identified those parcels of land included in Account 105,
5 Plant Held for Future Use, that are anticipated to be
6 used in their entirety for operating property in the
7 future. As a result of this review, $1,642,753 in this
8 account has been moved to rate base and the 2007 year-end
9 balance of $3,365,527 has been reduced by $1,642,753 in
10 column 2, line 33 to arrive at an adjusted year-end
11 balance of $1,722,774.
12 Q.Why is the acquisition of these properties in
13 the public's interest?
14 A. Purçhasing land for substations and other
15 facili ties prior to the time the facilities are
16 constructed benefits the Company and ultimately the
17 customer. With the increased growth in Idaho Power's
18 service territory, it has become increasingly difficult
19 and expensive to compete with developers to acquire
20 strategically located properties. In addition to the
21 financial benefits, early acquisition of these properties
22 reduces opposition and assists local planners by
23 identifying where Idaho Power's infrastructure will be
24 located.
25 Q. Would you please describe the remaining pages
in Exhibit No. 29?
2272 SMITH, DI 13
Idaho Power Company
.
.
.25
1 A.Page 22 of Exhibit No. 29 reflects the balance
2 at the beginning and end of 2007 and the average balance
3 for Accumulated Deferred Income Taxes - Accounts 190,
4 282, and 283. Page 23 reflects the balance by month and
5 the thirteen-month average balance of Customer Advances
6 for Construction - Account 252. Page 24 reflects the
7 balance by month and thirteen-month average of the rate
8 base components for IERCo consistent with prior
9 Commission orders.
10 Q.Would you please describe Exhibit No. 30?
11 A.Exhibi t No. 30 reflects the detailed support of
12 deductions from the O&M expense of the Company for
13 general advertising expenses, certain memberships and
14 contributions, senior management expenses, and
15 miscellaneous other expenses. These adj ustments have
16 been made by the Company consistent with prior orders of
17 the Commission and are responsive to concerns raised
18 during the 2003 general rate case, Case No. IPC-E-03-13.
19 Q.Would you please describe in more detail pages
20 2 through 9 of Exhibit No. 30?
21 A.In light of some of the concerns expressed in
22 the 2003 rate case, the Company has put processes in
23 place to review and screen its accounting records to
24 identify memb~rships and contributions in an effort to
2273 SMITH, DI 14
Idaho Power Company
.
.13
14
1 properly identify, account for, and share the costs of
2 each. All contributions and one-third to one hundred
3 percent of certain memberships have been removed. This
4 screening process is consistent with Idaho Power's last
5 two general rate case filings . Additionally, senior
6 management expenses have been reviewed and adj usted by
7 (1) removing one hundred percent of charges to the Arid
8 Club and Oregon jurisdiction direct charges, (2) removing
9 one-third of Edison Electric Institute ("EEI") expenses,
10 and (3) allocating the balance of expense account charges
11 of senior management between Idaho Power and IDACORP on
12 the basis of how their payroll is charged. Seven
officers had no further allocation based on payroll as
their expenses are reviewed monthly for proper allocation
15 between IDACORP and Idaho Power, thus not requiring
16 further allocation. Lastly, the Company has reviewed all
17 expense account charges to O&M in an effort to identify
18 and exclude charges from regulatory recovery based on
19 prior concerns expressed in other filings based solely on
20 the name of the business establishment. While many of
21 these expense account charges are legitimate business
22 expenses, out of an abundance of caution, they were
23 removed. These reductions are consistent with the
24 Commission Order No. 29505 in Case No. IPC-03-13..25
2274 SMITH, DI 15
Idaho Power Company
.
.
.
1 Q.Would you please describe Exhibit No. 32?
2 A.Exhibi t No. 32, lines 1 through 3 reflect the
3 unamortized portion of the Electric Plant Acquisition
4 Adj ustment associated with the Prairie Power Rural
5 Electric Cooperative purchase in July 1992.
6 Line 4 of Exhibit No. 32 reflects a decrease to
7 Investment in Associated Companies (IERCo) - Account 123,
8 for a portion of plant deemed not used and useful at the
9 Bridger Coal per Commission Order No. 29505.
10 Lines 5 through 9 of Exhibit 32 reflect FAS 87
11 Pension Expense to be removed from Administrative
12 Expenses Transferred-Credit - Account 922, which removal
13 is consistent with Commission Order No. 29505.
14 Lines 10 and 11 of Exhibit No. 32 remove the
15 income statement impact of the Energy Efficiency Rider
16 (formerly DSM Rider) accounting effecting Other Electric
17 Revenues - Account 456 and Customer Assistance Expenses
18 Account 908 in accordance with Commission Order No.
19 30189.
20 Lines 12 through 14 of Exhibit 32 record the
21 decrease of amortization expense included in Regulatory
22 Commission Expenses - Account 928, for amounts included
23 in the 2007 test year that resulted from Commission Order
24 Nos. 30035, 30215, and 30267.
25
2275 SMITH, DI 16
Idaho Power Company
.
.
.
1 Lines 15 and 16 of Exhibit No. 32 are
2 adjustments to the 2008 test year and are discussed later
3 in my testimony.
4 Q.Would you please describe in more detail the
5 adj ustment to Exhibit No. 32 related to pension expense
6 removal?
7 A.Yes. Exhibit No. 32, line 5 shows $4,238,191
8 total FAS 87 Net Periodic Pension Cost that the Company
9 reported in the Company's financial statements prior to
10 receiving Commission Order No. 30333 allowing for the
11 deferral of this cost as a regulatory asset. The
12 operating expense percentage of 64.89 percent is then
13 applied to the total FAS 87 cost less the premium expense
14 to arrive at the operating expense portion of $2,683,699
15 on line 9 of Exhibit No. 32 to be removed from this case.
16 In accordance with Generally Accepted Accounting
17 Principles ("GAAP"), the Company capitalized the
18 remaining period cost of $1,452,068 related to pension.
19 2008 TEST YEA METHODOLOGIES
20 Q.In your above testimony, you describe the
21 various adjustments that were made to the 2007 historical
22 actuals to arrive at the 2007 adjusted actuals. Do these
23 same adjustments need to be made in 2008?
24 A.No. These adj ustments are standard rate making
25 adjustments based on prior Commission orders and are
2276 SMITH, DI 17
Idaho Power Company
.
.
.
17
1 adjustments to charges included in the 2007 actuals. By
2 removing them from 2007 actuals prior to applying the
3 various methodologies to arrive at the Company's proposed
4 2008 test year data, the same adjustments are already
5 accounted for.
6 Q.Do you have an exhibit that identifies the
7 methodologies, that were applied to actual adjusted
8 historical 2007 results to arrive at the proposed test
9 year 2008 levels?
10 A.Yes. Exhibit No. 33, pages 1 through 2,
11 provides the actual methodologies and multipliers to the
12 2007 adj usted actual historical data discussed above.
13 Q. Have the data and the associated adj ustments
14 made to your exhibits and supporting schedules been
15 calculated on a total system basis?
16 A.Yes.
Q.How was the 2008 test year selected for this
18 proceeding?
19 A.In order to meet the legal requirement that
20 rates be fair, just, reasonable, and sufficient, the
21 Commission must establish a test year that most closely
22 reflects the investment and expense levels that will
23 exist at the time new rates are implemented. At this
24 time, the Company believes that a 2008 test year best
25 satisfies that
2277 SMITH, DI 18
Idaho Power Company
.
.
.
1 requirement. In response to the concerns Staff expressed
2 regarding the Company's filing of a forecasted 2007
3 general rate case in Case No. IPC-E-07-08 and their
4 desire that the Company provide audi table data as the
5 starting point for the forecasted test year, the Company
6 explored multiple al ternati ves to establish methodologies
7 to adj ust audi table historic data to establish the 2008
8 test year that would be representative of the Company's
9 anticipated levels of spending. As discussed in the
10 March 12, 2008, future test year workshop, the consensus
11 objective is the development of a test year that provides
12 a normalized level of rate base and expenses to establish
13 just and reasonable rates and timely rate relief. The
14 Company's expectation is that Staff will be able to
15 review and audit the 2007 adjusted historical actual
16 expenditures as the basis upon which to evaluate the 2008
17 test year presented by the Company.
18 Q.What methodologies did the Company consider as
19 appropriate candidates for developing the 2008 test year?
20 A.The Company considered using 2007 actuals,
21 averaging, trending, and indexing. Ultimately, the
22 Company determined that for auditing purposes, trending
23 based on 2007 actual data would provide Staff with a
24 smoother transition to the 2008 test year. The Company,
25 in
2278 SMITH, DI 19
Idaho Power Company
.
.
.
1 accordance with Staff's request, minimized the number of
2 methodologies while still maintaining the validity of the
3 data used to develop the 2008 test year.
4 Q.Have you provided a detailed description of the
5 methodologies and multipliers used to adjust 2007
6 financial data to the 2008 test year?
7 A.Yes. Each methodology is included in the
8 detailed Methodology Manual with a summary of the
9 mul tipliers my department provided to Pricing and
10 Regulatory Services (Exhibit No. 34). The methodologies
11 are applied to the 2007 adjusted actual results included
12 in the cost of service modeling with the exception of the
13 methodologies applied to rate base and rate base-related
14 items.
15 Q.Did you use 2007 actuals as a methodology to
16 apply to the financial inputs?
17 A.Yes. The Company reviewed the individual
18 accounts included in revenue, expense, and rate base to
19 determine the appropriate level of spending and revenues
20 that are anticipated for 2008 and, where appropriate,
21 used 2007 actuals for the 2008 test year instead of a
22 trending multiplier. The accounts and descriptions for
23 which 2007 adjusted historical actuals were used include:
24 (1) Account 454 - Transformer and Distribution Rentals,
25 (2) Account 456
2279 SMITH, DI 20
Idaho Power Company
.
.
.
1 - Antelope Facilities Charges, (3) Account 415 - Hydro
2 Services Revenues, Water Management Services Revenues and
3 Joint Use Revenues for both Idaho and Oregon, (4) Account
4 416 - Hydro Services Expenses, Water Management Services
5 Expenses and Joint Use Expenses for both Idaho and
6 Oregon, (5) Account 565 - Transmission of Electricity by
7 Others, (6) Account 924 - Property Insurance Expense, (7)
8 Account 406 - Amortization of Electric Plant Acquisition
9 Adj ustment for Prairie Power, (8) Account
10 408.1-Shoshone-Bannock Licenses, (9) Account 182304 -
11 FERC Grid West Expense, and (10) Account 105 - Plant Held
12 for Future Use (except for the expected acquisition of
13 the Lakeshore substation property included as a Known and
14 Measurable Adjustment to the 2008 test year).
15 Q.Was the Methodology Manual reviewed by Idaho
16 Power's management?
17 A.Yes. The Methodology Manual has been reviewed
18 and approved by senior managers of Idaho Power from
19 Pricing and Regulatory Services, Finance, Power Supply,
2 0 Delivery , Administrative Support business units, and the
21 Corporate Planning Department.
22 Q.Is the rationale for determining the various
23 growth rates included in the Methodology Manual?
24 A.Yes.
25
2280 SMITH, DI 21
Idaho Power Company
.
.
.
1 Q.Please summarize the methodologies included in
2 Exhibi t No. 33.
3 A.The methodologies applied to the various
4 accounts are listed in column 2 of Exhibit No. 33. Each
5 of the methodologies is described in more detail within
6 the Methodology Manual. To develop the Method Manual,
7 the Company performed a review of each group of accounts
8 included within the test year and based upon specific
9 knowledge and analysis of that account grouping, either
10 used 2007 actuals or applied another methodology to that
11 account that represents the most appropriate level of
12 anticipated spending.
13 Besides 2007 actuals, other methodologies
14 include application of the three- or five-year compounded
15 annual growth rate, which is the average growth rate over
16 the number of years that represents a steady level of
17 growth from the beginning period to the ending period and
18 smoothes out uneven amounts within these years.
19 Another methodology listed in the Manual is
20 described as Known and Measurable. Known and Measurables
21 are those in which specific knowledge of that account
22 requires application of that knowledge to estimate the
23 2008 spending level. An example of Known and Measurables
24 is Account 454 - Substation Equipment for which the
25 Company
2281 SMITH, DI 22
Idaho Power Company
.
.
.
1 has specific facilities agreements that specify the
2 revenues to be received from customers.
3 Finally, normalization was used for all power
4 supply cost accounts. Power supply normalization is
5 discussed in detail in Mr. Said's testimony.
6 Q.Please provide an overview of the methodologies
7 incl uded in the Methodology Manual (Exhibit No. 34).
8 A.I will start with test year revenues. The test
9 year data reflects 2008 Other Operating Revenues (Accts.
10 451, 454 & 456). With the exception of revenues from
11 substation equipment rents, transformer and distribution
12 rentals, station and line rentals, network services and
13
14
other Long Term Firm ("LTF"), point-to-point
transmission, and Antelope Substation revenues, all
15 operating revenues were updated using a three-year
16 compounded annual growth rate.
17 The 2008 Other Operation and Maintenance
18 expense was based on a five-year compounded annual growth
19 rate methodology which excluded pension expense, third
20 party transmission, Energy Efficiency Rider, and
21 compensation at-risk incentives in its determination.
22 Account 565 - Transmission of Electricity by Others and
23 Account 924 - Property Insurance used 2007 actuals.
24 Account 908 - Energy
25
2282 SMITH, DI 23
Idaho Power Company
.
.
20
1 Efficiency Rider was removed in its entirety from the
2 test year.
3 Q.Is the five-year compounded growth rate
4 appropriate?
5 A.Yes. The five-year compounded growth rate is
6 the most appropriate method to estimate the Company 2008
7 test year operations and maintenance expense based on
8 continued growth in its service territory and the
9 resul ting financial needs balanced with the forecasting
10 obj ecti ves identified by the Company, IPUC Staff, and
11 Intervenors in the forecast test year workshop held on
12 March 12, 2008.
13 Q. What is the average five-year compounded growth
14 rate that the, Company applied to determine 2008 test year
15 O&M expenses?
16 A.The average rate applied is 5.82 percent.
17 Q.Can the use of a 5.82 percent compounded annual
18 growth rate be supported by comparison to other growth
19 measuring factors?
A.Yes. For example, the Consumer Price Index
21 ("CPI") and the Company's customer growth over the last
22 fi ve years have grown at the combined rate of 6.27
23 percent. This combined 6.72 percent growth rate covers
24 the same expenses as the average of all functional.25 fi ve-year compound growth rates applied to the FERC
operations and
2283 SMITH, DI 24
Idaho Power Company
.
.
.
1 maintenance accounts, which is the source of the 5.82
2 percent growth rate the Company used.
3 Q.Please describe more fully how the Company
4 determined the 5.82 percent growth rate.
5 A.The Company's other operations and maintenance
6 in 2003, excluding pension, incentive, Energy Efficiency
7 Rider, and third party transmission expense was $208.8
8 million dollars compared to the 2007 amount of $261.9
9 million dollars. Therefore, the compounded annual
10 five-year growth in these expenses is 5.82 percent.
11 Q.How did you compute the 6.27 percent amount?
12 A.For, a similar time frame, between 2003 and
13 2007, and indexed to a base 2003 starting point, the
14 combined growth of new customers and CPI is 6.27 percent.
15 Q.Is the use of the 5.82 percent growth rate
16 reasonable?
17 A.The Company's increase in operation and
18 maintenance expenses has been slower than the 6.27
19 percent combined rate of increase for new customer growth
20 and the CPI. In my opinion, using the 5.82 percent
21 compound annual growth rate, on average, to adjust the
22 operating expenses, where applicable for 2007, is a
23 reasonable multiplier to include in the 2008 test year
24 other operations and maintenance expense and provides for
25 just
2284 SMITH, DI 25
Idaho Power Company
.1 and reasonable rate relief in 2009.
2 Q.Please explain any other methods used to
3 escalate other expense items.
4 A.The 2008 depreciation, amortization expense,
5 and reserve were calculated on the monthly estimated
6 plant balances based on the rates authorized by Order No.
7 29363 for the months of January through July 2008
8 calculation. For the August through December 2008 time
9 period, the proposed depreciation rates from the
10 currently filed depreciation case (IPC-E-08-06) were
11 used.
12 The 2008 construction.13
14
expenditures ("Construction") were bifurcated into two
separate and distinct parts, those proj ects in excess of
15 $2 million and those under $2 million. This separation
16 is explained more fully in the Methodology Manual
17 (Exhibi t No. 34). The proj ects in excess of $2 million
18 were reviewed, by the individual project managers who,
19 based on actual expenditures for each proj ect through
20 February 2008, estimated the costs to complete and the
21 in-service date of each proj ect. After analyzing the
22 under $2 million proj ects (excluding vehicles) closing to
23 Electric Plant in Service as a group, it was determined
24 that a five-year compounded annual growth rate be applied.25 to closings under $2 million dollars.
2285 SMITH, DI 26
Idaho Power Company
.
.
.
1 Taxes Other Than Income were based on a
2 three-year compounded annual growth rate with the
3 exception of Real and Personal Property taxes, Shoshone
4 Bannock licenses, Idaho regulatory commission fees, and
5 Kilowatt Hour Taxes.
6 Finally, Materials and Supplies were based on a
7 three-year compounded annual growth rate. All other 2008
8 test year amounts were either 2007 actuals, or calculated
9 using a methodology based on specific knowledge of that
10 account. These exceptions are discussed in more detail
11 in the Methodology Manual (Exhibit No. 34).
12 Q.Please summarize how the 2008 test year
13 methodologies were applied to the 2007 historical actual
14 adj usted data.
15 A.The forecast process began with calendar
16 year 2007 historical actuals. Adjustments were then made
17 to expenses incurred in 2007 to arrive at an adjusted
18 2007 actual. These adjusted 2007 actuals were the basis
19 upon which the methodologies (2007 actual, or three- and
20 five-year growth rates, or known and measurable
21 adjustments) were applied. Annualizing, intervenor
22 funding and spending containment adjustments were made
23 for all non-normalized components for the test year 2008.
24
25
2286 SMITH, DI 27
Idaho Power Company
.
.
.
1 ANALIZING AN OTHER ADJUSTMNTS TO THE 2008 TEST YEA
2 Q.Please summarize the annualizing and other
3 regulatory adjustments made to the 2008 test year.
4 A.The traditional regulatory adjustments the
5 Company has made for the 2008 test year are included on
6 Exhibit No. 31, pages 1 through 5, which I am also
7 sponsoring. This exhibit. details the support to the 2008
8 annualizing adjustments. These adjustments reflect
9 changes to certain expense and rate base items to treat
10 them as though they have been in existence for a full
11 year or to year-end 2008 levels, whichever is applicable.
12 These include the operating expense adjustments for:(1 )
13 a payroll annualizing increase of $2,593,733, (2) an
14 incentive decrease of $3,838,832 to remove incentive
15 above the normalized incentive target rate, (3) a 2009
16 salary structure adjustment increase of $3,019,804 on
17 Exhibit No. 31, pages 1 and 2, (4) the annualized
18 accumulated reserve adjustment of $227,404 and
19 depreciation expense adjustment of $471,026 on Exhibit
20 No. 31, page 3, and (5) the 2008 major plant addition
21 annualizing adjustment of $91,267,282 with the associated
22 property tax adjustment of $337,000 and insurance expense
23 of $38,971 on Exhibit No. 31, pages 4 and 5.
24
25
2287 SMITH, DI 28
Idaho Power Company
.1 Q. Have you made any other adjustments to the 2008
2 test year?
3 A.Yes. In addition to the annualizing
4 adj ustments, the Company has made adj ustments to
5 Regulatory Commission Expenses - Account 928 (Exhibit No.
6 32, lines 15 and 16) for the amortization of intervenor
7 funding amounts that had been previously deferred as a
8 regulatory asset as instructed by the Commission Order
9 Nos. 30488 and 30508. These orders directed the Company
10 to defer treatment until a future ratemaking procedure.
11 The Company in the 2008 test year has assumed a one year
12 amortization period..13
14
Q. Please describe the purpose of the Known
Spending Containment adj ustment on page 6 of Exhibit No.
15 31.
16 A.The negative impact of seven out of eight years
17 of below normal stream flows has continued to deteriorate
18 the financial position of the Company, as evidenced by
19 recent rating agency actions by Moody's and Fitch Rating
20 Agencies on June 3, 2008, and March 24, 2008,
21 respectively, more fully described in the testimony of
22 Mr. Steven Keen.
23 To respond to this situation the Company has
24 directed its senior management to find areas of spending.25 that can be deferred or eliminated. This spending
2288 SMITH, DI 29
Idaho Power Company
.
.
.
12
1 containment directive has identified an estimated
2 reduction to Other Operations and Maintenance of
3 $3,834,000 which is identified in my Exhibit No. 31, page
4 6. These budget reductions are in the deferral of hiring
5 new positions throughout the Company for 2008 and the
6 deferral of certain maintenance proj ects. Such deferral
7 is not expected to degrade service or reliability in the
8 near term. The reduction in other operations and
9 maintenance expenses is the most controllable expense
10 reduction that can be quickly implemented to offset the
11 decline in earnings for 2008.
Q.Does this conclude your direct testimony in
13 this case?
14
15
16
17
18
19
20
21
22
23
24
25
A.Yes, it does.
2289 SMITH, DI 30
Idaho Power Company
.1 I . INTRODUCTION
2 Q.Please state your name.
3 A.My name is Lori Smith.
4 Q.Are you the same Lori Smith that presented
5 direct testimony in this proceeding?
6 A.Yes.
7 Q.What issues will you be addressing in your
8 rebuttal testimony?
9 A.My testimony explains why the Company's test
10 year in this çase better reflects the operating
11 condi tions the Company expects to experience during the
12 time rates will be in effect than does Staff's proposed.13
14
test year. I will also provide information on the
Company's 2008 actual third quarter results that show
15 that the methodology the Company used to prepare its 2008
16 Test Year produces reasonably accurate results. I will
17 explain why Staff's adjustments to the 2008 Test Year are
18 arbi trary, rely on speculation, and are inconsistent with
19 the framework Staff and Intervenors supported in the
20 Forecast Test Year Workshop that was held prior to the
21 Company filing this case. Finally, I will respond to
22 several adjustments proposed by Commission Staff
23 Witnesses Cecily Vaughn, Joe Leckie, John Nobbs, and
24 Micron Witness Dr. Dennis E. Peseau..25
2290 SMITH, DI REB 1
Idaho Power Company
.
.
.
1 Q.Your rebuttal testimony responds to Staff's
2 proposed adjustments in considerable detail. Why have
3 you taken this approach rather than focus on just the
4 larger revenue requirement issues?
5 A.Over the course of several recent rate cases,
6 Idaho Power believes it is making progress on developing
7 a test year methodology that addresses the concerns of
8 the Company, Staff, and other parties. Because new test
9 year methodology is developing, Idaho Power wants to
10 clearly address the new issues that arise from the
11 proposed methodology as identified by Staff auditors.
12 This necessarily requires delving into some of the
13 intricacies of the revenue requirement issues present in
14 this case.
15 II. TEST YEA METHODOLOGY
16 Q.Idaho Power has proposed a test year that
17 trends 2007 actual results to 2008 levels to set rates in
18 2009 ("2008 Test Year"). Why is it important that the
19 test period and the rate-effective period closely match
20 each other?
21 A.In order to provide the Company a reasonable
22 opportuni ty to earn its allowed rate of return, the new
23 rates from a test year would ideally take effect with the
24 commencement of the actual year. With this underlying
25 premise in mind, the Company filed the proposed 2008 Test
2291 SMITH, DI REB 2
Idaho Power Company
.
.
.
1 Year based on its intimate knowledge of the contributing
2 factors that hinder the Company's ability to earn its
3 allowed rate of return. These factors include the costs
4 of serving both new and existing customers. These costs
5 continue to out pace the revenues generated by rates set
6 based on an historical test year or a hybrid test year
7 adj usted for actuals. As a result of load growth, the
8 Company must acquire new generating resources, build new
9 transmission lines and stations for reliability purposes,
10 and maintain its existing base fleet of resources in an
11 environment of significant cost escalations.
12 Q.Haven't current economic conditions slowed load
13 growth?
14 A.To some extent, yes. However, even with the
15 lower than expected additions of new customers
16 experienced so far in 2008, the need for timely rate
17 recovery of operating expenses and capital expenditures
18 is still present.
19 Q.Do you believe the Company's proposed test year
20 revenue requirement is reasonable?
21 A.Yes. The Company's test year values are: (1)
22 based on a compound average growth rate ("CAGR")
23 developed from historical spending patterns; (2)
24 reflective of realistic and systematic cost and revenue
25 proj ections
2292 SMITH, DI REB 3
Idaho Power Company
.1 that fairly represent the 2008 Test Year; (3) validated
2 by actual expenditures incurred thru September 2008; (4)
3 closely scrutinized by business unit management, Idaho
4 Power Company management, and the Idaho Power Company
5 Board of Directors; and (5) determined using a period of
6 time (2008) that precedes the rate implementation period
7 (2009) .
8 Q.By adopting a test year approach as proposed by
9 the Company in this proceeding, would the Commission be
10 required to accept all of the amounts reflected in the
11 Company's filing?
12 A.No. There may be differences of methodology.13 used to prepare a test year. Such differences are
14 unavoidable in a general rate case where the parties have
15 different perspectives. Idaho Power is not asking the
16 Commission for a blanket validation of this specific test
17 year. However, the Company is asking the Commission to
18 accept the widely used regulatory model of future test
19 year as being the most appropriate way to provide the
20 level of rates to produce timely recovery for the
21 increased level of expenditures that are required to
22 serve Idaho Power's growing load and to keep Idaho Power
23 a financially viable company, especially in light of
24 current economic conditions locally, nationally, and.25 internationally. Mr. Gale's
2293 SMITH, DI REB 4
Idaho Power Company
.
.
.
1 direct and rebuttal testimony explains the Company's
2 approach in greater detail.
3 Q.Have you reviewed the Company's September 2008
4 year-to-date expenditures?
5 A.Yes. Based on that review, I have included a
6 chart which summarizes the major components included in
7 the Company's filing with the amounts updated to reflect
8 September 2008 actual year-to-date values.
9 Q.What does that chart show?
10 A.It shows that the Company has done a very good
11 job of quantifying its 2008 Test Year expenses.
12 Q.Please explain how you came to that conclusion.
13 A. First, I selected significant components of the
14 2008 Test Year to compare them to actual September 2008
15 year-to-date values. These components are key variables
16 in the determination of the Company's revenue
17 requirement. The primary components I have included are
18 Electric Plant in Service (excluding Asset Retirement
19 Obligations ("ARO")) ("EPIS"), Accumulated Provision for
20 Depreciation and Amortization, Net Electric Plant in
21 Service, Other Operating Revenues, Operation and
22 Maintenance Expenses ("O&M"), Depreciation and
23 Amortization, and IERCO operating net income. I then
24 compared the actual September 2008
25
2294 SMITH, DI REB 5
Idaho Power Company
.
.
16
17
1 year-to-date to the test year totals. The results of
2 that comparison are as follows:
3
4 Year-To-Date
Septemer 2008
2008 Proposed
Test Year Total
5
EPIS (ex ARO)$3,953,058,903 $3,883,565,221
6
7
Accumulated Provision
for Depreciation &
Amortization 1,654,111,059 1,640,626,080
8
Net EPIS 2,298,947,844 2,242,939,141
9
10
Other
Operating Revenues 38,855,83430,258,709
11 O&M Expenses 221,779,540 295,910,705
12 (excluding Net Power
Supply Expenses and
Energy Efficiency13
14 Depreciation
& Amortization 78,112,259 105,290,34215
IERCO Net Income 1,925,252 6,828,651
Q.Do the 2008 year-to-date actual values validate
18 the escalated values contained in the 2008 Test Year used
19 by the Company?
20 A.Yes. Year-to-date EPIS is already greater than
21 the test year level and will only grow. O&M expenses
22 excluding net power supply expenses and Energy Efficiency
23 expenses ("O&M") through September are approximately
24 three-fourths of test year values just as should be.25 expected.
2295 SMITH, DI REB 6
Idaho Power Company
.
.
.
1 Q.Please provide more detail on why O&M expenses
2 are three-fourths of the Company's test year values.
3 A.For the period January 2008 through September
4 2008, actual O&M equaled $215,197,715 with the incentive
5 accrual expenses normalized to reflect only the
6 operational t~rgets. This amount can be compared to what
7 Idaho Power filed for its 2008 Test Year with a few
8 adj ustments. Please refer to Exhibit No. 83.
9 Idaho Power's 2008 Test Year O&M equaled
10 $295,910,705, which includes annualizing adjustments for
11 operating payroll of $2,593,733 and a 2009 Salary
12 Structure Adjustment of $3,019,804 as detailed on Exhibit
13 No. 31 to my direct testimony. As these annualizing
14 adjustments reflect 2009, they must be removed to .
15 properly compare what Idaho Power is actually
16 experiencing through September 2008 to what was included
17 in its 2008 Test Year.
18 To further improve the accuracy of the comparison,
19 Account 565-Transmission of Electricity by Others is also
20 removed from both the 2008 Test Year O&M ($10,469,726)
21 and the year-to-date September 2008 actuals ($6,137,531).
22 After making these adjustments, the 2008 Test Year O&M
23 equals $279,827,442 ($295,910,705 minus $2,593,733 minus
24 $3,019,804 minus $10,469,726). Year-to-date September
25 2008
2296 SMITH, DI REB 7
Idaho Power Company
.
.
.
1 actual O&M equals $209,060,184 ($215,197,715 minus
2 $6,137,531) after adjustments.
3 One would expect that 75 percent (three-quarters of
4 the entire year) of the Company's 2008 Test Year O&M as
5 adj usted above would be reflected in actual O&M through
6 the nine months ended September 2008. This is in fact
7 the case. Through September 2008, the Company has
8 experienced 75 percent ($209,060,184 divided by
9 $279,827,442) of its comparable 2008 Test Year O&M.
10 Another way to view the analysis is to annualize the
11 year-to-date September 2008 actuals which yields
12 $278,746,912 ($209,060,184 divided by 9 months and
13 mul tiplied by 12 months) and comparing the result to the
14 Company's comparable 2008 Test Year O&M. As shown on
15 Exhibi t No. 84, Idaho Power's comparable test year O&M is
16 just $1,080, 5jO or 0.4 percent higher than an annualized
17 amount based on year-to-date September 2008 actuals.
18 Q.How does Staff's methodology for calculating
19 O&M compare with what the Company is currently
20 experiencing in 2008?
21 A.Staff's methodology severely understates the
22 level of 2008 O&M expenses the Company is likely to
23 incur. Please refer to Exhibit No. 83 for detailed
24 calculations., Staff's test year 2008 O&M equals
25 $271,553,813. For valid
2297 SMITH, DI REB 8
Idaho Power Company
.
.
.
1 comparison purposes, Staff's annualizing adj ustment for
2 operating payroll of $1,157,432 must be removed from its
3 test year 2008 O&M along with Account 565-Transmission of
4 Electricity by Others of $10,469,726. After making these
5 adj ustments, Staff's comparable test year 2008 O&M equals
6 $259,926,655 ($271,553,813 minus $1,157,432 minus
7 $10,469,726). When compared to year-to-date September
8 2008 actuals, as defined in the previous question, the
9 Company has already experienced 80 percent of what Staff
10 has proposed for its comparable 2008 test year.
11 As presented on Exhibit No. 84, when compared to the
12 annualized year-to-date September 2008 O&M, Staff's
13 comparable test year 2008 O&M is $18,820,257 or 6.8
14 percent below the expenses the Company is currently
15 experiencing.
16 Q.What conclusion do you draw from this analysis?
17 The' methodology Idaho Power used to forecastA.
18 test year O&M is a very good representation of the
19 expenses that the Company is currently experiencing and
20 is much more accurate than Staff's proposed methodology.
21 Idaho Power's' methodology provides the Company the
22 opportuni ty to earn its allowed rate of return
23 established by the Commission while recovering operating
24 expenses in a more timely fashion. Staff's methodology
25 and resulting, position
2298 SMITH, DI REB 9
Idaho Power Company
.
.
.
1 exacerbates the mismatch between the timing of when
2 expenses are incurred versus their recovery in rates and
3 denies the Company an opportunity to earn its allowed
4 rate of return.
5 Q.What other conclusions do you draw from the
6 data in your table and in Exhibits Nos. 83 and 84?
7 A.This information supports the Company's
8 position that a historical test year inadequately
9 reflects the operating costs and capital expenditures
10 that Idaho Power Company is currently experiencing to
11 operate effectively. By the end of 2008, the Company
12 will have made significantly more capital investments in
13 property plant and equipment and will have spent
14 significantly more money operating its system to provide
15 reliable service to its customers than a historic test
16 year would reflect. The Company proposed 2008 Test Year
17 is a more reasonable representation from which to set
18 rates for the coming year and will provide the Company
19 the opportunity to earn its allowed rate of return
20 established by the Commission.
21 III. O&M ADJUSTMNTS
22 Q.Do you agree with Staff's adj ustments to the
23 Company's 2008 Test Year O&M expenses?
24 A.No. I believe that the adj ustments by Staff
25 Witnesses Vaughn, Leckie, and Nobbs that reduce the
revenue
2299 SMITH, DI REB 10
Idaho Power Company
.
.
1 requirement by $24,314,269 are flawed. I will
2 specifically discuss why I disagree with reductions in
3 Other Operations and Maintenance, payroll-related items
4 including reductions to target employee incentive, the
5 elimination of the 2009 salary structure adjustment, the
6 revision to the annualizing methodology, and the
7 reduction of Plant Materials and Supplies revenue later
8 in my testimony.
9 Q.How did the Company determine the O&M
10 escalation methodology it applied in this case?
11 A.For the O&M escalation methodology, the Company
12 accepted a "trending" approach agreed to in the Forecast
13 Test Year Workshop (held on March 12, 2008, and described
14 in my and Mr. Gale's direct testimony), which emphasized
15 identification of the expected operating conditions in
16 2008 and the ease of auditability of 2007 as a base year
17 to be trended forward to 2008. As stated in Ms. Vaughn's
18 testimony and consistent with the trending approach, the
19 Company developed a CAGR that was applied to maj or
20 Federal Energy Regulatory Commission ("FERC") account
21 groupings. Idaho Power Company's proposed maj or
22 groupings and CAGRs were as follows:(1) Steam Power
23 Production, CAGR 7.14 percent; (2) Hydro Production, CAGR
24 8.03 percent; (3) Other Production, CAGR 11.76 percent;.25 (4) Transmission, CAGR 3.98 percent; (5) Distribution,
CAGR 0.70 percent; (6)
2300 SMITH, DI REB 11
Idaho Power Company
.
.
.
1 Customer Accounting, Service and Selling, CAGR 0.06
2 percent; (7) Administration and General, CAGR 9.41
3 percent; and (8) for the total Company, an overall CAGR
4 of 5.82 percent before considering the known and
5 measureable cost containment adjustment of $3.8 million
6 and the traditional ratemaking adjustments for
7 annualizing and known and measureable adjustments. This
8 compares to the Staff's overall percentage increase in
9 O&M expense of 0.64 percent or $1,750,020.
10 Q.Please quantify the overall increase in O&M
11 expense based on the Company's use of this trending
12 methodology.
13 A. The overall increase in O&M expense as a result
14 of this trending methodology is $15,985,407.
15 Q.Do you agree with Ms. Vaughn's recommendation
16 that the Commission reduce the Company's O&M expense by
17 $14,235,387?
18 A.No., Ms. Vaughn made two major adjustments.
19 First, Ms. Vaughn reduced the O&M revenue requirement by
20 adjusting the 2007 base amount by $1,537,989 for P-card
21 expendi tures and a 2003 FERC billing settlement. Both of
22 these adj ustments are faulty and I will explain why later
23 in my testimony.
24
25
2301 SMITH, DI REB 12
Idaho Power Company
.
.
.
1 Secondly, Ms. Vaughn created a methodology used for
2 escalation purposes that excluded all escalation on
3 Administration and General ("A&G") expenses including
4 labor, materials, purchased services, and other expenses,
5 and all escalation for labor, materials, and purchased
6 services from the other six areas of FERC O&M Account
7 expense categories (Steam Production, Hydro Production,
8 Other Production, Transmission, and Customer Accounting,
9 Selling and Service).
10 Q.On page 7, lines 8-18 of her testimony, Staff
11 Witness Vaughn characterizes labor escalation as being
12 duplicated in two different areas of the Company's case.
13 Do you agree?
14 A.No. The Company's adj ustments to labor for
15 annualization and structured salary adjustment ("SSA")
16 match rates to the costs that will be incurred in the
17 2009 time period when these rates will be in effect. The
18 Company's 2008 Test Year assumption for labor costs, as
19 Ms. Vaughn correctly states, was based on 2007 values
20 escalated to 2008 by the FERC account grouping escalation
21 rate. The effect of this escalation is to produce an
22 ini tial 2008 Test Year for the O&M expense component.
23 The December known and measurable adjustment that
24 annualizes the 2008 Test Year labor is then made to
25 reflect the
2302 SMITH, DI REB 13
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
.
.
expected cost at the end of 2008 for labor expenses.
This adjustment provides a December 2008 test year
estimate of prospective employee count levels versus an
average of employment levels for the previous year that
would be in effect beginning January 1, 2009. These are
two separate and distinct adjustments, both of which are
appropriate for the test year.
The SSA adj ustment is consistent with methodologies
accepted in past filings and is used to reflect salary
adjustments necessary to represent the 2009 expense level
of labor when new rates take effect. The SSA is a
market-based adjustment reviewed and approved by Idaho
Power Company's Board of Directors to provide
market-based pay to employees in order to attract and
retain the employee talents necessary for the Company to
operate effectively. Company Witness Ric Gale discusses
the appropriateness of the adjustments in greater detail
in his rebuttal testimony . Despite the criticism of
these adj ustments, Staff provides no evidence that these
labor expenses are not increasing.
Q. Do you agree with Ms. Vaughn's decision to
exclude any escalation or trending on the FERC O&M
Accounts listed above?
2303 SMITH, DI REB 14
Idaho Power Company
.
.
.
12
13
14
1 A.No. Ms. Vaughn provides no empirical data or
2 verifiable evidence suggesting that the escalation rate
3 on the A&G category is incorrect or inappropriate. She
4 bases her disallowance recommendation solely on the fact
5 that the trending increase occurs coincidently with the
6 unrelated IDACORP divestiture of multiple subsidiaries.
7 Q.Staff Witness Vaughn attributes the 9.41
8 percent increase in A&G Accounts 920-935 to the one-time
9 di vesti ture of corporate subsidiaries. Please describe
10 the type of expenses that are included in this category
11 of expenses.
A.The type of expenses included in this group of
accounts are varied and include: regulatory commission
fees paid to regulatory agencies such as the state public
15 utili ties commissions, the Federal Energy Regulatory
16 Commission, as well as property and casualty and excess
17 liabili ty insurance premiums. This expense category also
18 includes the expenses required to meet the significantly
19 expanding compliance requirements for reliability
20 mandated activities required by FERC Orders 693, 705,
21 706, AND 706A for Critical Infrastructure Protection,
22 plus expenses related to the large increase in
23 reliability standards to be managed from a compliance
24 perspective. SEC mandated Sarbanes-Oxley ("SOX")
25 expenses, legal expenses to implement these new
2304 SMITH, DI REB 15
Idaho Power Company
.
.
16
1 standards and compliance-related activities, and the
2 maintenance of general plant expenses are part of this
3 expense category as well.
4 The requirements listed above have also increased
5 the labor associated with this account group in order to
6 meet the compliance requirements, all of which are
7 incorporated in the A&G portion of the 5.82 percent
8 overall increase in O&M expenses. The di vesti ture of
9 IDACORP' s subsidiaries has changed the expense allocation
10 between Idaho Power and IDACORP but to a significantly
11 smaller degree than Staff Witness Vaughn has inferred in
12 her testimony.
13 Q. Do you agree with Staff Witness Vaughn's
14 conclusion that the growth in A&G expense is attributable
15 to the di vesti ture of IDACORP subsidiaries?
A.No.I disagree with Ms. Vaughn's conclusion
17 for three reasons. First, Ms. Vaughn draws this
18 conclusion from incomplete and inadequate analysis. On
19 page 8 of her testimony, Ms. Vaughn states that 2007 A&G
20 expense has increased $17,597,452 over the average of
21 2004 through 2006. She then states that it is
22 "coincident with the di vesti ture of multiple IDACORP
23 subsidiaries" and concludes that "it is apparent that the
24 growth in G&A is the result of one-time corporate.25 divestitures. "
2305 SMITH, DI REB 16
Idaho Power Company
.
.
.
1 In response to Production Request No. 30, Ms. Vaughn
2 indicates that her only rationale for drawing this
3 conclusion is her review of a handout for the November
4 16, 2006, presentation to the Idaho Power Board of
5 Directors where four factors, listed simply as discussion
6 points, were given for expected 2007 O&M expense
7 increases. Then, for additional support, she cites Audit
8 Question and Response No. 106 from Case No. IPC-E-07-08
9 where she asked the Company "to provide copies of any
10 additional materials made available to the Board, before,
11 during, or after the meeting that provide additional
12 information related to these four factors." The Company
13 responded that no additional materials were made
14 available to the Board.
15 In fact, in Audit Question and Response No. 140,
16 Case No. IPC-E-07-08, the Company estimated the impact on
17 the 2007 O&M budget to be approximately $560,000 in
18 additional labor costs resulting from IDACORP selling two
19 non-regulated subsidiaries and refocusing its efforts on
20 Idaho Power. Wi thout adequate analysis and supporting
21 data, Ms. Vaughn incorrectly concluded that the $17.6
22 million increase was due to the divestiture of the
23 IDACORP subsidiaries.
24 Second, actual costs transferred from Idaho Power to
25 IDACORP and its non-regulated subsidiaries are very small
2306 SMITH, DI REB 17
Idaho Power Company
.
.
.
1 in comparison to the $17.6 million Ms. Vaughn attributes
2 to the one-time cost of divesture. Since the mid-1990s,
3 Idaho Power has had in place Service Level Agreements
4 which transfer direct and indirect costs (fully loaded
5 labor, materials, purchased services, etc.) incurred by
6 Idaho Power for the benefit of IDACORP' s subsidiaries.
7 The results of these Service Level Agreements have been
8 included in general rates cases beginning with the 2003
9 Rate Case. From 2003 through 2007, the average annual
10 expenses transferred to IDACORP from Idaho Power equaled
11 $3.1 million. From 2003 to 2007 (used in determining the
12 Company's 5-year CAGR), transferred costs have decreased
13 $1.6 million ($2.8 million less $1.2 million). This $1.6
14 million is significantly less than the $17.6 million Ms.
15 Vaughn suggests is the result of IDACORP' s divesture of
16 subsidiaries.
17 And finally, any expenses due to divesture of
18 IDACORP subsidiaries were properly recorded to either the
19 divested subsidiary or to the IDACORP holding company in
20 accordance with generally accepted accounting principles
21 ("GAAP") and not to Idaho Power.
22
23
Q.Did Ms. Vaughn trend any O&M expenses?
A.Yes~ Ms. Vaughn did escalate the Other Expense
24 cost category in her summarized Power Generation
25
2307 SMITH, DI REB 18
Idaho Power Company
.
.
.
1 category and Distribution category by 5 percent,
2 resulting in an increase of $2,876,561. This amount was
3 then offset by her methodology applied to the Accounting
4 Entries cost element resulting in a $1,126,541 reduction
5 to the $2,876,561, or a net escalation of $1,750,020.
6 Q.Do you agree with Ms. Vaughn's approach to
7 escalation or trending methodologies?
8 A.No. Actual experience in 2008 demonstrates the
9 flaw in these methodologies. Ms. Vaughn's escalation
10 resul ts in a 0.64 percent increase in O&M expenses for
11 the 2008 Test' Year. The Company's year-to-date actuals
12 support an overall increase of 5.82 percent as proposed
13 by the Company. The Company's actual expenditure levels
14 to date in September 2008, including cost containment
15 efforts since, the spring of 2008, have resulted in a 75
16 percent realization of the Company's 2008 Test Year O&M
17 expendi tures. By ignoring the 75 percent of the test
18 year completed, the Staff adj ustments to the Company's
19 test year O&M will not allow rates to match expenses and
20 diminishes Idaho Power Company's ability to remain
21 financially viable so as to meet customer loads during
22 these financially difficult times. To add insult to
23 injury, Staff Witnesses Mr. Leckie's and Mr. Nobbs's
24 adjustments continue to erode the requested O&M increase
25 to a level that is below the
2308 SMITH, DI REB 19
Idaho Power Company
.
.
.
1 actual 2007 expenses used as the base for the 2008 Test
2 Year presented in this case.
3 Q.Why do you disagree with Staff's methodology?
4 A.The Company prepared a 2008 Test Year to reduce
5 the timing differences between its costs and effective
6 rates necessary to recover them. While the Staff has
7 aligned partially with the Company's approach of test
8 year determination for rate base adjustments, the Staff
9 adj ustments to reduce the O&M expenses exacerbate the
10 timing differences between the Company's costs and the
11 rates necessary to recover them that the proposed test
12 year methodology sought to address. I believe the
13 Company's test year continues to closely match the
14 expendi tures required to provide safe and reliable
15 service to our customers.
16 Q.Do you agree with Dr. Peseau' s suggestion to
17 introduce an obj ecti ve standard like the Producer Price
18 Index, the rate of system load growth, or employee load
19 growth in establishing an inflator for test year
20 purposes?
21 A.I agree with the recommendation to use an
22 obj ecti ve standard for establishing an inflation
23 indicator in a test year process. I do not agree with
24 Dr. Peseau' s proposal to use a single factor inflator
25 because I believe
2309 SMITH, DI REB 20
Idaho Power Company
.
.
.
1 the combination of both inflation and customer growth
2 impact the Company's expense level. For the time period
3 2003 to 2007, the rate of combined growth for inflation
4 and customer growth has been 6.3 percent.
5 Q.How does this two-factor indicator compare to
6 the Company's filed test year in this case?
7 A.For the O&M FERC account groups that were grown
8 by an inflator as indentified in my Exhibit No. 33, lines
9 33-46, the average for all accounts is 5.82 percent.
10 This is a smaller inflator than the 6.3 percent
11 two-factor inflator composed of the Consumer Price Index
12 combined with the additions of new customers to Idaho
13 Power's system between 2003 and 2007. The combination of
14 these two factors more reasonably represents the expense
15 impact versus' a single-factor inflator suggested by Dr.
16 Peseau.
17 Q.Are there other comparisons that would support
18 your O&M methodology of escalating the 2007 Base Year on
19 average by 5.82 percent?
20 A.Yes. A review of the rates of growth other
21 regional Northwest utilities have experienced also
22 reinforces the Company's use of a 5-Year CAGR of 5.82
23 percent in th~s filing. Using FERC Form 1 data, Idaho
24 Power's reported customer growth from 2003 to 2007 of
25 3.21 percent is 1.6 times greater than the peer group of
2310 SMITH, DI REB 21
Idaho Power Company
.
.
.
1 utili ties at 1.96 percent. By comparison the expense
2 growth rate for Idaho Power of 6.39 percent is only 1.1
3 times that of the other companies' expense growth rate of
4 5. 74 percent. The result of reviewing a combination of
5 the actual O&M growth and the actual customer growth from
6 2003 to 2007 indicates that Idaho Power Company has had a
7 slower rate of O&M expense growth compared to this peer
8 group on average given the larger growth rate in new
9 customer additions during this time frame. This is
10 depicted in Exhibit Nos. 85 and 86, column 6, rows 1, 2,
11 and 10.
12 Q.What is your conclusion on applying the
13 Company's CAGR of 5.82 percent as the rate of escalation
14 of O&M expenses, where appropriate?
15 A.When reviewing the actual adj usted expenses
16 through September 2008 and reviewing the Northwest
17 utility peer group included in Exhibit Nos. 85 and 86,
18 the Company's request for an increase in O&M expense of
19 $16 million through this test year methodology is a
20 reasonable approach to set sufficient rates, not
21 excessive rates, as some witnesses have indicated, to
22 provide the Company with the opportunity to earn a
23 reasonable return.
24 iv. PLAT ANALIZATION ADJUSTMNTS
25 Q. Why has the Company included $91.3 million in
annualizing adj ustments to rate base?
2311 SMITH, DI REB 22
Idaho Power Company
.
.
.
1 A. Annualizing adjustments are intended to reflect
2 proj ects at a year-end level so that rates in place
3 beginning in 2009 will reflect the end-of-yearinvestment
4 in these proj ects versus an average year investment in
5 these proj ects, therefore reducing timing differences
6 related to recovery of rate base investments in 2009.
7 Q.Do Idaho Power and Staff generally agree on how
8 best to adj ust rate base for investments in plant?
9 A.Yes~ Proj ects greater than $2 million are
10 typically included as a known and measurable adjustment
11 to rate base. Although Staff did not recommend an
12 adjustment to the Company's proposed escalation of
13 capi tal expen~i tures less than $2 million, the Company is
14 open to discussing other ways it can capture growth in
15 investments less than $2 million given the large volume
16 of projects (approximately $110.4 million) that are
17 included in this category.
18 Q.Micron Witness Dr. Peseau criticizes the
19 Company's proposed plant annualizing adjustment, alleging
20 that it does not match costs and revenues. Do you agree
21 with Dr. Peseau's recommendation to remove $91.3 million
22 in annualizing adjustment to the 2008 rate base?
23 A.No. The Company proposed an annualizing
24 adjustment to 2008 rate base in Company Witness Greg
25 Said's
2312 SMITH, DI REB 23
Idaho Power Company
.
.
.
1 Exhibi t No. 52. This exhibit identifies large
2 construction proj ects greater than $2 million that were
3 classified as Reliability/Compliance, Load Growth, or
4 Other. The Company removed $1,489,324, or 11.6 percent,
5 of the requested ratebase-related revenue requirement to
6 reflect offsetting revenues from those proj ects in the
7 Load Growth category that could be revenue producing.
8 More than 50 percent of the $91.3 million in
9 annualized plant, or $45.8 million, has an offsetting
10 imputed revenue included in the revenue requirement per
11 the Commission's direction in Order No. 29505.Over
12 $37.6 million, or 41 percent, of the $91.3 million of
13 annualizing adjustments are included and categorized as
14 Reliabili ty or Compliance-related proj ects that the
15 Company is either mandated to construct or has identified
16 as a critical' proj ect to reliably serve load. These
17 proj ects do not have revenue producing capability.
18
19
V. DEPRECIATION ADJUSTMNT
Q.Do you agree with Staff Witness Leckie's
20 $1,471,189 depreciation expense adjustment and the
21 adjustment to Accumulated Depreciation account or
22 depreciation reserve of $227, 440?
23 A.Yes. Mr. Leckie has correctly adj usted the
24 Company' s fil~ng to reflect the Commission Order No.
25 30630.
2313 SMITH, Dr REB 24
Idaho Power Company
.
.
.
1 VI . PURCHASING CAS
2 Q.As a preliminary matter, what are purchasing
3 cards and how are they utilized at Idaho Power?
4 A.Idaho Power has a OneCard Solution Purchasing
5 Card ("P-Card") program implemented for Company employees
6 to use for purchases. This program was implemented to
7 replace a variety of processes including petty cash,
8 local check writing, cash advances by check, expense
9 accounts, open vendor accounts, and certain purchase
10 orders. The intent of the P-Card is to allow the Company
11 to better manage high volume, low-dollar transactions and
12 to improve cash flow management by simplifying payments,
13 reducing paperwork, reducing processing expense, reducing
14 multiple checks, and providing a centralized listing of
15 all expenses.
16 Q.How does the use of P-Cards add value to Idaho
17 Power's operations?
18 A.P-Cards are commonly used by many businesses to
19 effectively administer and manage the reimbursement of
20 business related expenses. P-Cards allow employees to
21 make emergency field purchases and fund business related
22 travel expenses. Also, the use of P-Cards for small
23 dollar purchases saves the Company money by eliminating
24 the need
25
2314 SMITH, DI REB 25
Idaho Power Company
.1 to create purchase orders and process invoice payments
2 for small items.
3 Staff Witness Vaughn claims that "theQ.
4 widespread use of P-cards and the ability of an Idaho
5 Power employee to take cash withdrawals to self-reimburse
6 for expenditures prior to approval opens the door to the
7 possibili ty of employee abuse." Do you agree?
8 No. In fact, in Staff Witness Vaughn'sA.
9 testimony, she specifically states that Staff did not
10 find any evidence of employee abuse. Company policy
11 expressly prohibits personal use of the P-Card and
12 employees that violate the policy are subj ect to.13
14
discipline, including termination.
Q. How do Idaho Power's internal controls and the
15 culture it promotes minimize the potential that exists
16 for employees to misuse Company assets?
17 A.Idaho Power has established a culture that
18 promotes honesty and integrity. This control environment
19 includes:
20 Tone at the Top - Officers and Senior Management
21 have established a culture with a strong value system
22 founded on integrity. This is evidenced through
23 consistent and frequent messaging, our mission statement,
24 corporate.25
2315 SMITH, DI REB 26
Idaho Power Company
.
.
.
1 leadership ini tiati ves, and training programs, and
2 through the actions of management.
3 Code of Business Conduct and Ethics ("Code") - Each
4 Idaho Power employee is required to sign a statement of
5 acknowledgement that they will comply with the Code. The
6 Code not only, outlines legal requirements and guiding
7 principles but also sets forth the Company's commitment
8 to an ethical way of doing business. The Manager of
9 Corporate Compliance oversees the Code and is a resource
10 to employees.
11 Ethics Line - Suspected violations may be reported
12 anonymously through a third-party hotline, a website, or
13 other internal resources. The third-party hotline allows
14 for a direct reporting conduit to the Board of Directors.
15 All reports are promptly investigated and acted upon.
16 Hiring and Promoting Appropriate Employees - Idaho
17 Power has established various proactive hiring and
18 promotion procedures to hire and promote qualified
19 employees. These procedures include the use of detailed
20 position descriptions, targeted selection interview
21 standards, background investigations, drug testing, and
22 the incorporation of regular performance reviews.
23 SOX Compliance Program - As part of the SOX
24 compliance program, fraud risk is considered in
25 developing
2316 SMITH, DI REB 27
Idaho Power Company
.
.
.
1 key controls. These controls are evaluated and tested as
2 part of the SOX compliance program.
3 Annual Business Planning - Management performs an
4 annual business planning process. In this process, fraud
5 risk factors to the Company are identified and catalogued
6 based on industry research, brainstorming/focus
7 group/interviews, existing event inventories, and process
8 flow analysis. Results are evaluated and presented to
9 Senior Management as part of the annual business planning
10 process.
11 Fraud Risk Assessment - The SOX Proj ect Manager
12 compiles a fraud risk assessment as part of the SOX
13 compliance program, which is reviewed in detail with the
14 Vice President, Audit and Compliance and the Vice
15 President, Chief Risk Officer.
16 Q.How does Idaho Power's internal control
17 structure specifically limit the potential for employees
18 to misuse P-Cards?
19 A.Moni toring controls have been established to
20 deter or detect errors specific to the P-Card expense
21 process. P-Card charges must be approved for each
22 employee. Managers review their cost center charges,
23 which include P-Card expenses. Accounts Payable ("AP")
24 Team Members review P-Card expenses to ensure that
25 documentation,
2317 SMITH, DI REB 28
Idaho Power Company
.
.
.
1 provided is appropriate to support the expense. AP Team
2 Members are empowered to escalate any questionable
3 expenses to the AP Team Leader for further review.
4 Finally, the AP Team Leader, Vice President/Treasurer and
5 Senior Vice President, Administration/Chief Financial
6 Officer review and sign off on the monthly P-Card
7 reconciliation.
8 Q.On page 33 of her testimony, Staff Witness
9 Vaughn states that because P-Cards can be used for cash
10 advances without pre-approval, an employee can use it for
11 personal expenses or a cash advance similar to a payday
12 loan. Is that an accurate assessment?
13
14
A. No. All expenses related to cash advances must
be properly supported and approved. If these
15 requirements are not met, the amount in question will be
16 deducted from the employee's next paycheck. In addition,
17 because Company policy expressly prohibits personal use
18 of the P-Card, employees that violate the policy are
19 subj ect to disciplinary action including termination.
20 This may explain why Staff identified no instance of
21 P-Cards being used intentionally for employee personal
22 expenses.
23 Q.On page 33 of her testimony, Staff Witness
24 Vaughn states that this practice gives an employee
25 "unfettered" access to $5,000. Is she accurately
describing Company policy?
2318 SMITH, DI REB 29
Idaho Power Company
1 A. No. All employees with a P-Card do not have.2 cash advance access. The cash advance function can only
3 be granted to an employee based on a manager's approval.
4 For those employees granted cash advance access , limits
5 range from $150 to $3,000, depending on the employees'
6 job duties. The cash advance limit for most employees is
7 $300.
8 Q.Do you have any concerns about the auditing
9 methodology used by Staff to come up with their critique
10 of the Company P-Card system?
11 A.Yes. The Company has put in a great deal of
12 time and effort in reviewing Staff workpapers and.13 discovery responses to understand the basis for their
14 conclusions and findings related to P-Card expenditures.
15 Our review was guided by the standards issued by the
16 American Institute of Certified Public Accountants
17 ("AICPA"), which state that:
18 The auditor must prepare audit documentation in
connection with each engagement in sufficient19 detail to provide a clear understanding of the
work performed (including the nature, timing,20 extent, and results of audit procedures
performed), the audit evidence obtained and its21 source, and the conclusions reached.
22 (AICPA, Professional Standards, Vol. 1, AU sec. 339)
23 It certainly does not appear that Staff complied with
24 those standards. In its review of Staff's workpapers,.25 Idaho Power was unable to gain a clear understanding of
the work
2319 SMITH, DI REB 30
Idaho Power Company
1 performed or the basis for the conclusions reached..2 Specific concerns include:(1) The criteria for
3 evaluating audit evidence were not defined; (2) it does
4 not appear that Staff used the information obtained
5 through the review of the sample of 900 monthly
6 reconciliations to develop conclusions on the entire
7 population; and (3) Staff's conclusions on the
8 disallowances regarding meals and cell phone usage were
9 subj ecti ve and not supported by the testing
10 documentation.
11 Q.What is your concern regarding Staff's failure
12 to not provide sufficient criteria for evaluating audit.13 evidence?
14 A. Through review of Staff's workpapers , it
15 appears the criteria used by Staff were unreasonably
16 subjective. According to Government Auditing Standards
17 issued by the Government Accountability Office ("GAO"),
18 the criteria should ". provide a context for
19 evaluating evidence and understanding the findings." The
20 GAO guidance further represents that criteria includes
21 "... standards, measures, expected performance, defined
22 business practices, and benchmarks against which
23 performance is compared or evaluated." (Chapter 6.16).
24 In Staff Witness Vaughn's response to Idaho Power.25 Company's Production Request No. 35, she states that
2320 SMITH, DI REB 31
Idaho Power Company
.
.
.
1 ". . expenditures must be considered necessary,
2 reasonable, and prudent in provision of this service" to
3 the customer. She further states that "Expenditures that
4 do not meet these criteria should be recorded below the
5 line."The criteria defined by Staff do not meet
6 the GAO standard because Staff does not cite anything
7 other than Ms. Vaughn's personal belief as the source to
8 define necessary, reasonable, and prudent expenses. For
9 example, there is no reference to an independent study,
10 industry benchmarks, or best practices to support her
11 assertions.
12
13
14
Q.How did Staff use the sample of 900 monthly
reconciliations in performing their audit?
A. It appears that Staff examined a randomly
15 selected sample of approximately 900 reconciliation
16 envelopes. However, the information taken from the
17 sample was not used to evaluate the total population of
18 P-Card expenditures that occurred in 2007. Instead,
19 Staff requested a list of all 2007 calendar year P-Card
20 expenditures and subjectively chose percentages to
21 exclude for meal and cell phone expenditures. As a
22 resul t, there is not a clear logical link between Staff's
23 selected sample for review and the conclusions reached
24 for the disallowances.
25
2321 SMITH, DI REB 32
Idaho Power Company
.
.
.
1 Q.How did you conclude that Staff did not use the
2 information obtained through the review of the sample of
3 900 monthly reconciliations to develop conclusions on the
4 entire population?
5 A.In Ms. Vaughn's response to Production Request
6 No. 46, she stated "No" when asked if she pulled and
7 reviewed the individual P-Card envelopes
8 (reconciliations) that supported the charges included on
9 her Exhibit No. 125, pages 1 and 2 that formed the
10 foundation of Staff's conclusion that the expenses should
11 be excluded from recovery in rates.
12 Q.Regarding P-cards, please identify the
13 components that make up Staff Witness Vaughn's
14 recommended $884,788 adjustment for ratemaking purposes.
15 A.Staff Witness Vaughn's adj ustment includes: (1)
16 $236,274 for restaurant expenditures; (2) $306,475 for
17 cell phone related expenditures; (3) $247,339 for
18 Gifts/Awards; (4) $61,729 for bottled water, coffee, and
19 newspapers; (5) $17,606 for charitable donations;
20 (6)$7,999 for political activity; and (7) $7,366 related
21 to the Company's "keyword" search. I will address each
22 of these adj ustments separately below.
23
24
25
2322 SMITH, DI REB 33
Idaho Power Company
.
.
.
1 A. Restaurant Charges
2 Q.Do you agree with Staff Witness Vaughn's
3 recommendation to exclude $236,274 of restaurant expenses
4 from Idaho Power Company's revenue requirement?
5 A.No. Ms. Vaughn recommends removing $236,274,
6 or 50 percent, of all restaurant and food expenses
7 incurred wi thin the Company's service terri tory stating
8 they were "excessive" and "neither reasonable or
9 necessary" while simultaneously stating that because of
10 the volume "it was clearly impossible for Staff to review
11 all supporting documentation." Although the implication
12 in her testimony is that she reviewed some supporting
13 documentation, Ms. Vaughn's response to Production
14 Request No. 46 was that she did not review the supporting
15 documentation for the P-Card expenditures included in the
16 amount she recommended for removal. To remove 50 percent
17 of all restaurant and food expenses incurred wi thin the
18 Company's service terri tory is both subj ecti ve and
19 arbitrary.
20 Q.Why should these items not be removed?
21 A.Again, based on a limited description provided
22 in a data dump from the Company's general ledger system
23 and with no apparent detailed review, a 50 percent
24 adj ustment removing these expenses is unreasonable. The
25
2323 SMITH, DI REB 34
Idaho Power Company
.
.
.
1 Company has adequate oversight controls in place for
2 these types of purchases in order to ensure they have a
3 legitimate business purpose and are nei ther excessive nor
4 unreasonable.
5 Q.Why do you believe Staff's conclusions
6 regarding meals were arbitrary and not supported by the
7 testing documentation?
8 A.In Staff Witness Vaughn's response to Idaho
9 Power Company's Request No. 36 regarding the 50 percent
10 adjustment to restaurant expenditures, she states that
11 "the 50% was not based on a specific calculation . ."
12 As the rationale for this disallowance, she cites 50
13 percent as a reasonable percentage "to eliminate
14 expendi tures that are believed to be excessive." (Page
15 26 of Vaughn's direct testimony). Further, she cites
16 four "worrisome" examples of meal expenditures that she
17 believes are neither reasonable nor necessary for a
18 regulated utility based on the limited description
19 provided in a data dump from the Company's ledger system.
20 These four examples total less than $150 and serve as her
21 basis for excluding nearly $236,000 in restaurant
22 expendi tures for ratemaking purposes. Her workpapers do
23 not provide an adequate basis to conclude that the meal
24 expenses were neither reasonable nor necessary. There is
25 no evidence that 50 percent of the
2324 SMITH, DI REB 35
Idaho Power Company
.
.
.
1 meal expenses reviewed by Staff met her criteria as
2 "worrisome." Further, Staff did not include any
3 obj ecti ve criteria to support her assertion that these
4 expenses are excessive.
5 B. Cell Phone Expenses
6 Q.Do you agree with Staff Witness Vaughn's
7 recommendation to exclude $306,475 of cell phone
8 expenditures from Idaho Power Company's revenue
9 requirement?
10 A.No. I have the same problems with Staff's
11 conclusions regarding cell phone usage that I did with
12 restaurant charges; Staff conclusions were arbitrary and
13 not supported by the testing documentation. The
14 resul ting Staff adj ustment is not valid and should not be
15 allowed.
16 Q.Why do you believe Staff's conclusions
17 regarding cell phone usage were subj ecti ve and not
18 supported by the testing documentation?
19 A.On page 28 of Staff Witness Vaughn's direct
20 testimony, she states that she "removed 75% of the cell
21 phone expense charged to A&G and 50% of all remaining
22 cell phone expense." In her response to Idaho Power
23 Production Request No. 40, she further states that "the
24 percentage was not calculated, nor was it intended to be
25 . . . ." As rationale for this disallowance, she cites a
belief that
2325 SMITH, DI REB 36
Idaho Power Company
.
.
.
1 the Company has too many employees with cell phones and
2 that cell phones are unnecessarily assigned to employees
3 located in central headquarters. Staff Witness Vaughn
4 further stated in response to Idaho Power Company
5 Production Request No. 39, that Staff believes it is
6 reasonable for certain key employees and many field
7 personnel to carry a Company-provided cell phone. In
8 reviewing the Company provided-workpapers, Staff had
9 access to employee job titles, yet there was no analysis
10 performed to determine which employees should or should
11 not have cell phones based on Staff's cell phone
12 cri teria. Rather, the disallowance was based on
13 assumptions unsupported in Staff's workpapers or
14 testimony.
15 Q.Why should cell phone related expenses be
16 included in the revenue requirement?
17 A.The Company agrees with Ms. Vaughn's statement
18 that cell phones are a necessary expense of doing
19 business and "due to the wide spread and often remote
20 work areas of Company employees, reasonable cell phone
21 communication expense should be included in rates."
22 However, I believe Ms. Vaughn reaches her conclusion that
23 the cell phone charges are excessive on the basis of an
24 inadequate auditing process. The Company takes very
25
2326 SMITH, DI REB 37
Idaho Power Company
.
.
.
1 seriously the prudent use of cell phones and provides
2 them based on business necessity.
3 Q.You mentioned inadequate auditing process in
4 your answer. Would you elaborate on that statement?
5 A.It is apparent Ms. Vaughn failed to follow good
6 audi ting practice and look at the data underlying the
7 numbers. There are numerous items Staff Witness Vaughn
8 identifies in her workpapers as cell phone charges which
9 are not cell phone charges. Among the largest of these
10 individual charges are satellite communication fees
11 incurred in the monitoring of water flows, monitoring of
12 snow levels, and communication service for dams. Most of
13 the noted monitoring equipment charges are included in
14 Account 921. In reviewing Account 921, Ms. Vaughn
15 concludes "145,921 (27%) of the total O&M cell phone
16 expense is charged" to P-cards and because "most A&G
17 employees are employed at the Company central
18 headquarters. ~ She incorrectly concludes that these
19 charges are for only A&G employee use of cell phones.
20 Also included in Ms. Vaughn's analysis of cell phone
21 expenses are charges completely unrelated to cell phones
22 use, such as çharges for ladders and tools for vehicles,
23 an extension cord, parking fees, employee training,
24 trailer stock materials, audit department reference
25 materials,
2327 SMITH, DI REB 38
Idaho Power Company
.
.
.
1 restaurant, lodging and training expenses. In addition,
2 there is a significant amount of charges related to
3 after-hour and on-call support for the call center. It
4 is apparent Ms. Vaughn based her findings on assumptions
5 and not fact.
6 Q.Are there any other cell phone charges that Ms.
7 Vaughn has identified for removal that are in fact
8 reasonable and prudent expenses for ratemaking?
9 A.Yes. There are charges for cell phones that
10 are located in outlying areas that are used to transmit
11 data so that additional labor costs can be averted in the
12 collection of necessary business data. Among these are
13 cell phones located at large customer (Rate Schedule 9P
14 and 19) meter locations and interchange points. These
15 phones are attached directly to the meter and are
16 necessary due to the large amount of daily transmitted
17 data collected from these customers. Additionally, there
18 are charges for cell phones used by meter readers to
19 receive orders for disconnects and connects, to call
20 prior to disconnecting customers for non-payment, and to
21 call other meter readers when they are done with their
22 routes to see if help is needed in other areas.
23 Q.What is your overall assessment of the cell
24 phone charges, Ms. Vaughn has removed?
25
2328 SMITH, DI REB 39
Idaho Power Company
.
.
.
1 A.I have discussed several flaws wi thin Ms.
2 Vaughn's evaluation of data that she used for the basis
3 of her assumptions. While the Company takes Ms. Vaughn's
4 concerns seriously, the Company provides cell phones
5 based solely on business necessity and has adequate
6 controls in place. As part of the Company's ongoing cost
7 containment and prior to the filing of Mrs. Vaughn's
8 testimony, the Company commenced a complete review of aii
9 cell phone policies and procedures, which should be
10 completed by the end of the year.
11 Contracts with carriers are continuously reviewed
12 and renegotiated resulting in more competi ti ve pricing.
13 Corporate pooled accounts were established with two large
14 cell phone carriers in December 2007 and January 2008,
15 which have resulted in additional savings. The Company
16 has negotiated an umbrella contract that will cover all
17 employees, creating a larger group and thereby providing
18 economies of scale, which will provide significant
19 savings to customers. Ms. Vaughn's desire to make
20 assumptions based on a data dump of 14,327 lines, with
21 limi ted descriptions, without a detailed review is
22 unreasonable. Ms. Vaughn has not demonstrated any
23 rational basis for her 50 percent and 75 percent removal
24 percentages.
25
2329 SMITH, DI REB 40
Idaho Power Company
.
.
.
1 Q.In her testimony, on page 32, Staff Witness
2 Vaughn states that P-Cards are used for cell phones and
3 office supplies "in lieu of standard business purchasing
4 practices. " Has she correctly characterized the
5 Company's purchasing practices?
6 A.No. In 2007, each employee with a
7 Company-issued cell phone used Company-negotiated service
8 contracts with an individual pool of minutes. In
9 addi tion, standard purchasing practices are utilized to
10 purchase office supplies and paper. With the exception
11 of emergency purchases, all paper and office supplies are
12 purchased through negotiated contract pricing using an
13 electronic procurement system, which uses P-Cards instead
14 of separate purchase orders to improve the Company's
15 efficiency anq reduce costs.
16 C. Gifts/Awards
17 Q.Do you agree with Staff Witness Vaughn's
18 $247,339 adjustment for Gifts/Awards?
19 No. Blanket removal of all these items shouldA.
20 not be allowed based on a data dump, with limited
21 descriptions of the charges, and no in-depth review. The
22 Company provides certain benefits to employees to foster
23 a positive working environment, good morale, and,
24 although indirect, assist in attracting and retaining
25 quality
2330 SMITH, DI REB 41
Idaho Power Company
.
.
.
1 employees - all of which benefit customers. Although Ms.
2 Vaughn states these expenditures, "though allowable as
3 traditional expenses, do not benefit the customer," she
4 does not articulate why they do not benefit customers.
5 In review of Ms. Vaughn's adj ustments, a large maj ori ty
6 of these items are for Service Award Celebrations,
7 including Retirement Parties ($67,795), Excellence Awards
8 ($50,314), and Company-Sponsored Social Functions
9 ($76,543), all of which are conducted under specific
10 guidelines and are addressed in the Company's employee
11 handbook. For example, the purpose of the Service Award
12 Celebration is for an employee's co-workers to recognize
13 the employee for his or her time and contributions to the
14 Company. The total amount of expenditure is based on
15 years of service, which is $125 for 5 and 10 years, $200
16 for 15 and 20 years, and $300 for 25 years of service and
17 above.
18 Excellence Awards are tools that supervisors,
19 managers, and officers can utilize to recognize
20 "exceptional" employee contributions and motivate
21 employees to perform in a like manner. These awards can
22 be given in the form of cash or gifts for which there are
23 specific guidelines.
24 While in today's environment Company-sponsored
25 social events such as Christmas parties and picnics are
2331 SMITH, DI REB 42
Idaho Power Company
.
.
.
1 kept to a minimum, these events promote employee morale
2 as well as develop posi ti ve working relationships and
3 environments.
4 Q.What other types of items were included in Ms
5 Vaughn's adjustment for gifts and awards?
6 A.There are over 2,500 rows of expenses listed in
7 Ms. Vaughn's exhibit so it is virtually impossible to
8 list each item; however, the list is included in her
9 workpapers for review. Examples of the types of items
10 included in this list are expenses related to team
11 building functions, sympathy cards and flowers for
12 deaths, safety appreciation lunches, employee
13
14
15
appreciation breakfasts, etc.
D. Bottled Water, Coffee, and Newspapers
Q.Do you agree with Staff Witness Vaughn's
16 $61,729 adjustment for bottled water, coffee, and
17 newspapers?
18 A.No. Idaho Power employees, particularly those
19 in the field, frequently work in inhospitable conditions
20 to maintain or restore power in remote areas. In some
21 instances, the Company provides water or coffee for the
22 health and/or safety of employees working in extreme
23 temperatures. Idaho Power utilizes local newspaper
24 subscriptions to stay abreast of new businesses, legal
25
2332 SMITH, DI REB 43
Idaho Power Company
.
.
.
1 notices, and legal publications of local ordinances and
2 laws that may impact the utility business or Idaho Power
3 customers. Staff's proposed adj ustment would disallow
4 appropriate business expenses such as these that enable
5 the Company to provide quality service to its customers.
6 E. Chari table Donations
7 Please address Staff Witness Vaughn's $17,606Q.
8 adj ustment for charitable donations. Is this adj ustment
9 reasonable?
10 No. Ms. Vaughn removed $17,606 in expensesA.
11 classifying them as donations. In the Company's 2003
12 Idaho Rate Case (IPC-E-03- 13), Staff identified and the
13 Commission ordered the removal of 100 percent of all
14 charitable contributions and 1/3 to 100 percent of
15 memberships. In this current rate case, the Company
16 removed $195,563 for those items identified in Exhibit
17 No. 30, pages 2 and 3 of 9, and an additional $10,768 on
18 Exhibi t No. 30, pages 4 and 5 of 9.
19 While the Company reviewed thousands of entries in
20 an attempt to remove all charitable donations, it is
21 inevitable that a few small dollar items might be missed.
22 However, unlike donations made to specific entities, the
23 vast majority of the expenses was incurred in support of
24 employee community involvement, which enhances employee
25
2333 SMITH, DI REB 44
Idaho Power Company
.
.
.
1 morale and benefits the local communities that comprise
2 Idaho Power's service terri tory. A review of these items
3 also indicates that some of these items (less than
4 $2,000) were already removed in my Exhibit No. 30, pages
5 2 and 3 of 9. Ms. Vaughn's adj ustment would remove those
6 amounts twice from Idaho Power's 2008 test year expenses.
7 F. Poli tical Acti vi ty
8
9 Do you agree with Staff Witness Vaughn's $ 7,999Q.
10 adjustment for political activity?
11 Partially. While the Company makes everyA.
12 effort to assure expenses relating to political
13 acti vi ties are removed, some of Ms. Vaughn's adj ustments
14 are valid. However, the Company had already removed
15 $4,733.70 of this amount and thus Ms. Vaughn's adjustment
16 results in double counting. For example, one-third of
17 the $3, 752.50 Boise Metro Chamber membership was removed
18 in Exhibit No. 30, page 2 of 9, line 41. The amount of
19 $404.00 for Mr. Panter's officer physical was removed in
20 Exhibit No. 30, page 8 of 9, line 126, and 17.4 percent
21 of Mr. Keen's travel expenses to the Governor's Cup
22 Scholarship fund raising event has been removed in
23 Exhibit No. 30, page 6 of 9, line 56. These were removed
24 in accordance with Order No. 29505 (Case No.
25 IPC-E-03- 13) .
2334 SMITH, DI REB 45
Idaho Power Company
1.2 G. Keyword Search
3 Q.Do you agree with Staff Witness Vaughn's $ 7,366
4 adjustment related to the Company's keyword search?
5 A.No. Ms Vaughn states she included
6 "expenditures similar to those removed by the Company
7 subsequent to its 'keyword' search as described in Ms.
8 Smith's direct testimony." (Vaughn Dir. 22.) However,
9 this statement is incorrect. In Exhibit No. 30, page 9
10 of 9, the Company removed charges that, although the
11 Company feels are appropriately incurred costs, the
12 vendor name might lead an uninformed individual to come.13 to the wrong conclusion. Included in the Company's
14 initial keyword search was the name "bar." However, the
15 Company has found that a significant number of
16 restaurants include the name "bar" in their names. There
17 are instances when "bar" may not even be stated in the
18 logo on the building, but when employees pay for their
19 meals, they find it is printed on their receipts.
20 Therefore, after discussions with management, it was
21 determined to remove only charges to establishments that
22 included only the word "bar" in their name. If the
23 establishment's name included "bar" but also grill,
24 restaurant, café, or something similar, it was not.25 removed. Therefore, the Company feels it is unreasonable
2335 SMITH, DI REB 46
Idaho Power Company
1 to remove all of these charges..2 VII. INVNTORIES ADJUSTMNTS
3 Q.Staff Witness Vaughn recommends removal of
4 $6,617,514 from rate base based on her assessment that
5 there is "no accurate predictor" of Accounts 154 and 163
6 - Plant Materials and Supplies and therefore "adequate
7 planning, ordering, and inventory management" by the
8 Company will allow inventory levels to be maintained at
9 2007 levels. Is her recommendation valid?
10 A.No. While I do agree that 100 percent accuracy
11 in estimating account balances is difficult, a reasonable
12 estimation is possible. 2008 actual data shows that the.13 Company has done a good job of managing and estimating
14 Accounts 154 and 163 levels. In its original filing, the
15 Company estimated that by the end of 2008 the total of
16 these two accounts to be $50,128,526. As of October
17 2008, the combined balance is $50,407,997, or $279,471
18 higher than the Company's entire 2008 estimate. There
19 were three primary drivers in arriving at the Company's
20 2008 estimate:(1) the Company in 2007 had been applying
21 sales taxes included in Account 163 to the reissuance of
22 Company remanufactured transformers; (2) the Company has
23 seen an increase in the cost of transformers by an
24 estimated 60 percent due to the increased cost of metal.25
2336 SMITH, DI REB 47
Idaho Power Company
.
.
.
1 and oil; and (3) the need for higher inventories to serve
2 a larger customer base.
3 The over-application through the Stores Loading
4 process of sales taxes was discovered in February 2008
5 and corrected through a reduction to Stores Loading rate
6 from February 2008 through October 2008, resulting in an
7 increase to 2008 inventory levels of approximately $2
8 million. The Company only incurs sales tax expense once
9 when a transformer is purchased and subsequently should
10 only be capitalized once when the transformer is
11 originally issued, not when remanufactured and reissued.
12 While the Company is constantly monitoring its
13 inventory levels to assure adequate but minimal
14 inventory, it must ensure that there are sufficient
15 inventories to serve the customers. It takes this
16 responsibility very seriously. Unlike unregulated
17 companies, Idaho Power cannot tell a customer he or she
18 may have to wait while inventory is ordered.
19 VIII. EXECUTIVE DEFERRD COMPENSATION ADJUSTMNT
20 Q. Do you agree with Staff Witness Nobbs that the
21 four entries in sub-account 920.350 identified as
22 Executive Deferred Compensation for 2007 totaling
23 $459,524 should not have been included in the revenue
24 requirement?
25
2337 SMITH, DI REB 48
Idaho Power Company
.
.
.
1 A. Yes, but not for the reasons cited by Mr.
2 Nobbs. Idaho Power has approximately 1,250 active
3 general ledger accounts and many of those accounts have
4 thousands of lines of entries included wi thin them in any
5 given year. While Idaho Power makes every possible
6 attempt to review accounts and remove items that should
7 not be borne by the ratepayer, these costs were
8 inadvertently overlooked in the preparation of the rate
9 case.
10 Do you agree with Mr. Nobbs' s characterizationQ.
11 of the source of the funds included in the $459,524
12 amount?
13 A. No,' I do not. While Mr. Nobbs is correct that
14 these expenses are included in a "Rabbi Trust," he is
15 incorrect in his description of the source of the funds
16 included in the $459,524 amount. As part of Idaho Power
17 Company's Executive Compensation plans, the Company
18 allows executives to defer, at their discretion, some of
19 their compensation until he or she separates from the
20 Company. While the executive's compensation is correctly
21 recorded as a current expense to the Company at the time
22 it is earned, instead of paying the executive at that
23 time, the Company takes the cash the executive elects to
24 defer and deposits it in a participant-directed
25 investment account. This account is very much like a
401 (k) plan and the executive
2338 SMITH, DI REB 49
Idaho Power Company
.
.
.
1 has the same investment options as are available to
2 participants in the Company's ordinary 401 (k) plan.
3 Generally Accepted Accounting Principles ("GAAP") require
4 the Company to set up an asset for the investment and
5 corresponding liability for the benefit of the executive.
6 Any earnings or losses on the trust assets that accrue to
7 the benefit of the employee are recorded as either gains
8 or losses, or interest and dividend income or expense, in
9 the Company's income statement as it is earned and a
10 corresponding' entry is made to gross up the value of the
11 asset. At the same time, an identical amount is recorded
12 as an increase or decrease to compensation expense in the
13 income statement with an offsetting entry credited to the
14 liability acc9unt to recognize the increase or decrease
15 in the liability to the executive. Therefore, the income
16 generated is offset by a corresponding expense. In this
17 case, the income fell below the line while the expense
18 was recorded above the line. Mr. Nobbs is correct that
19 the $459,524 should not have been included in the revenue
20 requirement.
21 Did any executive use this provision to defer aQ.
22 portion of their compensation in 2007?
23 No. The $459,524 represents only earnings onA.
24 amounts executives had deferred prior to 2007.
25
2339 SMITH, DI REB 50
Idaho Power Company
.
.
.
1 Mr. Nobbs stated earlier in his testimony thatQ.
2 businesses often use this type of trust to provide
3 "Golden Parachutes" and later in his testimony that it is
4 a form of non-qualified deferred compensation similar to
5 a golden parachute. Do you agree with these statements?
6 No, I do not. It is not a form of severanceA.
7 pay, bonus, stock option, or a combination thereof.
8 There is also no contract defining it as such. It is
9 purely a plan to permit deferral of base salary or
10 incentive compensation that the participant would
11 otherwise receive in cash. The deferred funds are kept
12 in a participant-directed investment account that is very
13 similar to a 401 (k) account. The term "golden parachute"
14 is certainly an inflammatory term these days and it is
15 unfortunate that Mr. Nobbs chose to use it when it is not
16 applicable to, Idaho Power's situation.
17 Mr. Nobbs stated on pages 3 and 4 of his directQ.
18 testimony that "Cbecause) creditors can exercise a prior
1 9 claim on trust corpus; the trust beneficiaries bear a
20 'substantial risk of forfeiture.' Simply put,
21 contributions can be taken back until they are given to
22 the employee." CEmphasis in original.) Has he correctly
23 described the operation of the deferred compensation plan
24 at issue here?
25
2340 SMITH, DI REB 51
Idaho Power Company
1 A.Not entirely. Trust beneficiaries do bear a.2 risk of forfeiture of their deferral and earnings on
3 their deferral because the trust corpus can be reached by
4 credi tors. However, it is inaccurate for two reasons to
5 say that contributions can be taken back until they are
6 given to the employee. First, the Company does not make
7 contributions to this plan. All amounts contributed to
8 the plan are elective deferrals made by the participants.
9 There is no Company match associated with these
10 deferrals. Second, the statement implies that Idaho
11 Power may redirect these funds to its own purpose, which
12 is not true. Idaho Power holds legal title to the funds.13 until they are distributed but has no access to the funds
14 for its own use. The funds could only be forfeited in a
15 bankruptcy proceeding, in which case the funds would go
16 to satisfy creditor claims.
17 ix. INTEREST ON DIRECTOR'S FEES ADJUSTMNT
18 Q. Do you agree with Mr. Leckie's removal of
19 $15,172 in interest paid to Company directors on their
20 deferred director's fees?
21 A.No. Interest on deferred director's fees is
22 recorded in FERC Account 431 and is a below the line
23 account. Because the interest was not included in the
24.25
2341 SMITH, DI REB 52
Idaho Power Company
.
.
.
1 Company's requested revenue requirement, the $15,172
2 cannot be removed.
3 X. OUT OF PERIOD ACCRUALS ADJUSTMNT
4 Q.Staff Witness Nobbs states that he found two
5 accruals in 2007 recorded in account 928.101 - FERC Order
6 No. 472 containing out-of-period charges totaling
7 $163,901 and that each of these accruals covered a
8 one-year period. Do you agree with this statement?
9 A.No. Idaho Power accrues FERC administrative
10 fees monthly, based on an estimate using the previous
11 twelve-month actual billing. The monthly accrual amount
12 is established in August or September of each year and is
13
14
for the following twelve-month period from October 1
through September 30. When the Company receives the
15 FERC's invoice, the Company adjusts its accruals and by
16 the end of the twelve-month period in September the
17 amount accrued agrees to the actual billing for the same
18 time period. Based on the FERC invoice, the Company
19 would then estimate the monthly accrual for the next
20 twelve-month period.
21 In Mr. Nobbs's exhibit, he reduces the Company's
22 2007 accrual of $480,505 by $163,901, stating that
23 $98,239 of this amount relates to 2006 and $65,662
24 relates to 2008. I am not certain how Mr. Nobbs came to
25 his conclusion but the full $480,505 is the accrual for2008. A reduction of
2342 SMITH, DI REB 53
Idaho Power Company
.
.
.
1 this amount would understate Idaho Power's 2007 expenses
2 and revenue requirement.
3 XI . CONTRIBUTIONS, AL CLOCK AN CAY
4 Staff Witness Nobbs recommends the removal ofQ.
5 contributions, alarm clocks, and candy in the amount of
6 $7,150 from Account 930. 2-Miscellaneous Expenses because
7 these "appear to be personal, a contribution or
8 frivolous. " Do you agree with his assertion?
9 No. None of these items are either personal orA.
10 fri volous in nature. These expenses had a definite
11 business purpose and benefit. The alarm clocks, which
12 were of small individual dollar value ($8.46 each and
13
14
$457 in total' expense), were given out at the EEI Fall
Financial Conference to assist in reminding security
15 analysts (both fixed-income or debt, and equity) that
16 Idaho Power is a viable and prudent investment option.
17 This either reinforces Idaho Power (by a logo on the
18 gifts) to those who already know us or introduces the
19 corporate logo to new analysts and potential investors.
20 As Idaho Power and IDACORP compete for new capital
21 (an even more defining issue today in the
22 credi t-constrained capital markets), it is important to
23 differentiate Idaho Power from others. And to that
24 extent, Idaho Power is not alone in giving out "trinkets"
25 to those
2343 SMITH, DI REB 54
Idaho Power Company
.
.
.
1 who either influence or directly purchase our debt and
2 equi ty securities. At this conference, Idaho Power also
3 met with members of the credit rating agencies (Moody's,
4 Standard & Poor's, and Fitch) and they often take these
5 items after having a thorough dialog with the management
6 team.
7 The $1,718 spent on butter toffee was provided to
8 city and county agencies for providing information, data
9 and assistance with easements, GIS data, and other
10 documentation to Idaho Power. Maintaining city and
11 county relationships and their cooperation is invaluable
12 when gathering easement information.
13 Q. Do you take issue with any other amounts
14 included in the $7,150 that Mr. Nobbs recommends
15 removing?
16 A.Yes. Besides the gifts previously mentioned,
17 the Company had already removed from the Company's
18 revenue requirement the membership for $1,000 to the
19 Idaho Economic Council in Exhibit No. 30, page 2 of 9,
20 line 53. Therefore, this amount does not exist in the
21 revenue requirement such that it can be removed.
22 Q.Are there any amounts included wi thin the
23 $7,150 Mr. Nobbs recommends removing that you do agree
24 should be removed?
25
2344 SMITH, DI REB 55
Idaho Power Company
.
.
.
1 Yes. While the Company feels the remainder ofA.
2 the $7,150 has an appropriate business purposes, in Case
3 No. IPC-E-03-13 the Commission found that certain
4 memberships and contributions should be removed from test
5 year expenses. As a result, the Company reviewed
6 thousands of rows of charges to make every attempt to
7 remove such charges. However, our additional review
8 shows that the Company did in fact fail to remove the
9 memberships for $2,500 to the Caldwell Economic Council
10 and $1,125 to the Eastern Oregon Visitors Association.
11
12
13
14
XII. FERC SETTLEMNT CREDIT ADJUSTMNT
Q.Staff Witness Vaughn describes on page 19 of
her testimony an adjustment to the Staff's actual test
year for a credit received from the FERC involving FERC
15 administration and Other Federal Agency ("OFA") charges.
16 Do you agree that this adjustment is appropriate?
1 7
18
A.No.
Q.Please explain why the Company received
19 reimbursement of the FERC administration and other
20 federal agency charges.
21 A.The FERC and other federal agencies assess
22 utili ties for costs related to their administrative and
23 regulatory duties. Numerous utili ties sued over the
24 accuracy of the charge and the court agreed with Idaho
25
2345 SMITH, DI REB 56
Idaho Power Company
.
.
.
1 Power' s position on the charges. As a result, Idaho
2 Power received reimbursement for fees collected from 1999
3 through 2006.
4 Ms. Vaughn recommends that the Company flowQ.
5 through this reimbursement to its customers over a five
6 year period. Do you agree with this recommendation?
7 No. There are essentially two reasons for myA.
8 disagreement. First, Ms. Vaughn contends that the
9 Company over-collected its expenses in prior years. This
10 would only be true if the Company had over-earned since
11 the period of'time she uses; i.e., from 2003 forward. As
12 Company Witnesses Steve Keen demonstrated on page 31 of
13 his direct testimony and LaMont Keen explained on pages 9
14 and 10 of his direct testimony, the Company actual return
15 on equity for, those time periods was well below the
16 allowed return established in those two cases and
17 accordingly there was no overcharge. Second, Ms. Vaughn
18 has simply selected one expense item out of many to make
19 a retroactive, adjustment for ratemaking purposes. She is
20 artificially increasing the Company's revenues for the
21 next five years when she creates the amortization of her
22 credi t. This amortization has no relationship to the
23 actual ongoing costs of the Company. It will simply
24 cause the Company to under-earn through the device of
25 creating a revenue stream
2346 SMITH, DI REB 57
Idaho Power Company
.
.
.
1 from a prior period by assuming that the Company has
2 over-collected on an expense item for a prior period.
3 What would be the financial impact on theQ.
4 Company of Ms. Vaughn's recommendation?
5 The Company would be required to write offA.
6 approximately $3.3 million to 2008 net income.
7 XIII. ARCHITECTS' SERVICES ADJUSTMENT
8 Do you agree with Staff Witness Nobbs' sQ.
9 characterization that the architects' services of ZGA
10 Architects and Planners totaling $36,375 should be
11 capitalized rather than expensed?
12
13
14
A.No. Mr. Nobbs appears to have assumed that
because these' particular expenses were incurred to an
architectural and planning firm, that these costs
15 represent architectural costs for capi tali zed items.
16 However, this firm not only provides architectural
17 services but also consulting services. Idaho Power
18 requested the firm's consulting services be provided in
19 the Corporate Headquarters Master planning efforts to
20 identify alternative solutions to physically
21 accommodating employee growth. This effort has resulted
22 in the decision to relocate approximately 20 percent of
23 the Company's employees from the Corporate Office to the
24 Boise Plaza
25
2347 SMITH, DI REB 58
Idaho Power Company
.
.
.
1 building and thus defer a long-term decision on building
2 new facilities.
3 Why have you concluded that these costs are notQ.
4 capitalizable costs?
5 A. Capital expenditures according to GAAP are not
6 normal, recurring expenses and are costs that benefit the
7 operations of more than one operating period. Also,
8 costs that improve efficiency or extend the life of an
9 asset would also qualify under GAAP to be capitalized.
10 However, unlike architectural drawings which may meet the
11 aforementioned requirements, consulting costs of this
12 nature are normal, recurring, and according to GAAP
13 should be expensed.
14 Q . Given that Mr. Nobbs stated these should be
15 capi tali zed, did he add these costs to rate base and
16 include an appropriate amount in the cost of service for
17 depreciation?
18 No, he did not.A.
19 XiV. LEGA FEES ADJUSTMNT
20 On page 13 of his testimony, Staff WitnessQ.
21 Leckie recommends that the Commission deny recovery of
22 legal fees in the amount of $192,364 paid to the Dewey &
23 LeBoeuf law firm. Is Mr. Leckie's adjustment reasonable?
24
25
2348 SMITH, DI REB 59
Idaho Power Company
.
.
.
1 A.No. Mr. Leckie testifies that the billings
2 for these legal services were entitled "Stock Plans" and
3 separated from other Dewey & LeBoeuf billings. On this
4 basis, he mistakenly concludes that the legal services
5 covered by these billings only benefit shareholders and
6 therefore should be excluded from expenses to be included
7 in the Company's revenue requirement. I believe if Mr.
8 Leckie had examined the actual invoices fr~m Dewey &
9 LeBoeuf, he would have recognized that the legal services
10 described in the invoices labeled "Stock Plans" cover
11 legal compliance issues associated with multiple employee
12 benefit matters and are not for legal services directly
13 related to IDACORP stock. For example, the legal
14 services covered in the "Stock Plan" invoices include
15 work on legal compliance issues associated with the
16 Company's 401(k) and restricted stock plans for its
17 employees. Both restricted stock and 401 (k) plans are
18 common employee benefits that help the Company attract
19 and retain qualified employees.
20 Q.Should any of the legal services billed under
21 the "Stock Plans" label be allocated to IDACORP?
22 A.Yes, and they already have been. The actual
23 invoiced amounts are greater than the amounts shown in
24 Mr. Leckie's Exhibit No. 118. The Company has already
25 reduced the amount it is seeking to collect in its
revenue
2349 SMITH, DI REB 60
Idaho Power Company
.
.
.
1 requirement to reflect an allocated portion of these
2 billings going to IDACORP. The Company's General
3 Counsel's office reviewed the bills and concluded that a
4 portion of the total bill should be allocated to IDACORP.
5 The amounts shown in Mr. Leckie's Exhibit No. 118 reflect
6 that reduction.
7 Will the Company change the way it labels theseQ.
8 legal services invoices in the future?
9 Yes. Idaho Power has requested that Dewey &A.
10 LeBoeuf revise its invoice descriptions to avoid future
11 misunderstandings of this type.
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Q.Does this conclude your rebuttal testimony?
A.Yes, it does.
2350 SMITH, DI REB 61
Idaho Power Company
.
.
.
1 (The following proceedings were had in
2 open hear ing . )
3 MS. NORDSTROM: Thank you. I make this
4 witness available for cross-examination.
5 COMMISSIONER SMITH: Thank you. Mr. Ward,
6 do you have questions?
7 MR. WARD: Just one quick area.
8
9 CROSS-EXAMINATION
10
11 BY MR. WARD:
12 In your direct testimony, Ms. Smith, youQ
13 say at page 18, I'm not going to quote the whole sentence
14 from lines 19' through 23, but you basically say the
15 Commission must establish a test year that most closely
16 reflects investment and expense levels at the time the
17 rates are implemented. Do you recall that testimony?
18 A Yes.
19 And in fact, the Company is -- the commonQ
20 theme throughout this proceeding in terms of test year is
21 that we have to have rates that are set forward into 2008
22 to allow the Company a fair opportunity to earn its
23 return; correct?
24 A Yes.
25 If you'd turn to page 20 of your rebuttalQ
CSB REPORTING'
[phone]
2351 SMITH (X)
Idaho Power Company
.
.
.
1 testimony, let me know when you're there, if you would.
2 A I am.
3 Q Now, at the bottom of page 20 and 21,
4 you're criticizing Dr. Peseau's proposal to limit the
5 compound annual growth rate to a CPI level which I think
6 in his testimony he estimated it at approximately two
7 percent. Now, in making that criticism, what you say is
8 essentially that the 5.82 percent that the Company used
9 as an inflator -- and you can see that number on line 18
10 of page 21, do you see that?
11 A Yes.
12 Q That's correct, is it not?
13 A Yes, it is.
14 And what you say at the top of page 21 isQ
15 we can show this is reasonable for an inflator because
16 compared to the time period 2003 to 2007, the rate of
17 combined growth for inflation and customer growth has
18 been 6.3 percent. Now, what you're saying is my 5.82
19 percent is reasonable because in the last four years the
20 combination of system growth and inflation has been even
21 greater, 6.3 percent?
22 A Yes.
23 Now, as to the 5.82 that you estimatedQ
24 that you used to move forward your estimated expenses
25 into 2008, are you aware that Mr. Said estimated the
CSB REPORTING
[phone]
2352 SMITH (X)
Idaho Power Company
.
.
.
1 system growth for 2007 at 1.9 percent?
2 A Subj ect to check, I would say that Mr.
3 Said is probably correct.
4 Q It's on page 8, line 10 of Mr. Said's
5 testimony if anyone wants to check, and if that's
6 correct, do you know what the inflation adjustment, the
7 CPI inflation has been from November 2007 to November
8 2008?
9 A ' Well, a couple of things by what you said,
10 Mr. Ward. First off, the combination of system growth,
11 which I think you're referring to in Mr. Said's
12 testimony, is not what I'm referring here to in the
13 annual number of new customers that are added, so what
14 I'm referring to is the new customer growth, plus
15 inflation, that combination is driving the expenses of
16 the Company.
17 Q All right, I'll accept that, subject to
18 check, that there may be some difference between your
19 estimation of growth and his, but, nevertheless, his
20 estimate of system growth is 1.9 percent. Now, let me
21 repeat the question. Do you know what the inflation rate
22 was, the CPI inflator was, from November of 2007 through
23 2008?
24 A For that specific time period, no, I
25 don't. I know what it was at September 2008 and I know
CSB REPORTING
[phone]
2353 SMITH (X)
Idaho Power Company
.
.
.
1 what it is recently at the end of November.
2 Q Okay, at the end of November did it go
3 down dramatically?
4 A Yes, it has declined. September it was
5 3.8 percent, so it's been very volatile in '08.
6 Q Would you accept, subj ect to check, that
7 in November of 2008, the annualized adjustment had been,
8 the historical inflation was 1.1 percent for the year?
9 A Subj ect to check.
10 Q And you can check that by Googling CPI or
11 Bureau of Labor Statistics.
12 A Uh-huh.
13 Q Now, if we're going to use that as a
14 standard, if we're going to use growth plus inflation as
15 a standard, and the Company says that we have to have the
16 most forward-looking numbers we can possibly produce that
17 have any reliability, why should we accept your 5.82
18 percent when the combination, and I admit, you have a
19 quarrel about, what we're using for a growth rate, but the
20 combination of growth and CPI inflation has only been
21 three percent?
22 A Well, as we participated in the forecast
23 test year workshops on March 12th, what we agreed to do,
24 and many of the parties agreed to do, was to identify an
25 escalator that would be applied to the historical 2007
CSB REPORTING
[phone]
2354 SMITH (X)
Idaho Power Company
.
.
.
1 amounts, not the forecasted 2007 amounts as you
2 indicated, and the Company did willingly participate in
3 that workshop. What we did do is so this was in March
4 of 2008, of course -- we developed a methodology for 2008
5 for all of the cost of service components, including rate
6 base and operating expenses, and we populated that based
7 on some of the historical spending that the Company has
8 seen.
9 Now, if inflation has reduced in 2008,
10 that really doesn't matter in 2008 as I demonstrated and
11 can be seen very clearly on my Exhibit 83 which reflects
12 the actuals for Idaho Power Company through September and
13 we have achieved and provided the operating expenses to
14 maintain the system, to provide service for the
15 approximately 6,600 new customers that were on in 2008,
16 and so we have actually spent in 2008 the majority of the
17 forecast test year that we put forward in 2008.
18 Q But didn't you say in your rebuttal
19 testimony that Dr. Peseau' s proposal was not unreasonable
20 provided that you used both figures, that is, the CPI
21 inflator and a growth figure?
22 A No, I think the combination of those two
23 inflators is appropriate.
24 Q And isn't it true that right now the
25 traj ectory of, the CPI is toward deflation, not
CSB REPORTING
[phone]
2355 SMITH (X)
Idaho Power Company
.
.
.
1 inflation?
2 A I believe the inflation in 2008 will still
3 be positive, greater than zero.
4 Q And I realize you're not a financial
5 wi tness, but we all read the papers. Isn't it true that
6 the really alarming scenario that everyone from the
7 Treasury secretary and the Federal Reserve is concerned
8 about is the possibility of serious deflation in the
9 Uni ted States?
10 A I think everyone both nationally, locally,
11 internationally is very concerned about what's happening
12 in the volatility in all the markets that we have to deal
13 wi th. I agree that there is a lot of concern out there
14 and I understand that many companies are having to do a
15 lot of unprecedented things. How I think our Company is
16 different is we don't have as many levers as, say, for
17 example, someone that can shut down a manufacturing line,
18 someone that can close a branch store, someone that can
19 continue to reduce their expenses. As a regulated
20 utili ty, we have the obligation to serve and that's the
21 challenge that the Commission has in how to balance that.
22
23
Q Well, I --
A So I don't believe we have as many levers
24 as unregulated companies.
25 Q I will concede that that is probably true,
CSB REPORTING
[phone]
2356 SMITH (X)
Idaho Power Company
.
.
.
1 but you're not entirely without levers, are you, or why
2 would we have a management of the Company?
3 A Well, and we have taken levers. As
4 Mr. Keen indicated on the first day, we have included
5 cost containment in our original filing that we
6 identified early in the year. We have a soft freeze on
7 hiring employees which is also reflected in Mr. Gale's
8 acceptance of Mr. Leckie's payroll adj ustments, so we
9 have pulled as many levers as we think are prudent.
10 Q And if nothing else, I have to ask this
11 question to get it on record for the next rate case or
12 the future, if the shoe were on the other foot, if the
13 CPI inflator and system growth, which we don't know what
14 it actually was for 2007, but if the CPI inflator and
15 system growth actually exceeded your 5.82 percent
16 estimate by a significant margin, would Idaho Power then
17 want it updated to take account of that bigger number?
18 A I think Mr. Gale could certainly have a
19 Company position on that. The way I would answer it
20 would be that if we are overearning or underearning, I
21 think that it's the Company's responsibility to take
22 action on that.
23 Q I didn't ask about overearning or
24 underearning. I asked about what happens -- we're
25 dealing here with a future test year in which you have
CSB REPORTING
[phone]
2357 SMITH (X)
Idaho Power Company
.
.
.
1 proj ected increases in certain costs and the Company has
2 proj ected increases in a great number of costs and we
3 have used compound annual growth rates, correct, in the
4 instance we're talking about here, compound annual growth
5 rates?
6 A Yes, we've used 2007 actuals, we've used
7 known and measurables. We've used normalizing
8 adjustments like we typically do and we've used the
9 methodolgy to apply a constant average growth rate.
10 Q All right, and Dr. Peseau' s testimony
11 suggests that'this has to be limited somehow by some
12 obj ecti ve standard and we can -- you don't disagree with
13 me that that's essentially what he's arguing, do you?
14 A No.
15 Q Now, all I'm asking is without regard to
16 whether you're underearning or overearning, if you make
17 an estimate and the obj ecti ve standard then turns out
18 later to be significantly higher, are you going to want
19 the objective number rather than your historical-based
20 estimate?
21 A Well, I think you're asking me to opine on
22 something that hasn't happened, so I guess I'm not quite
23 sure how to answer that.
24 MR. WARD: Well, I think maybe you have.
25 That's all I have, Madam Chair.
CSB REPORTING
[phone]
2358 SMITH (X)
Idaho Power Company
.
.
.
20
1
2 Mr. Olsen.
COMMISSIONER SMITH: Thank you, Mr. Ward.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Purdy.
MR~ PURDY: None. Thank you.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Thank you, Madam Chair,
COMMISSIONER SMITH: Mr. Boehm.
MR. BOEHM: No questions.
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: No questions,
COMMISSIONER SMITH: Mr. Price.
MR. PRICE: Thank you, Chair.
CROSS-EXAINATION
Ms. Smith, I would refer you to your
21 rebuttal testimony on page 11. If you look at lines 11
3
4
5
6
7
8 no questions.
9
10
11
12
13 Madam Chairman.
14
15
16
17
18
19 BY MR. PRICE:
Q
22 and 12 --
23
24
25
COMMISSIONER REDFORD: Page II?
MR. PRICE: Rebuttal testimony of
Ms. Smith, page 11, lines 11 through 12.
CSB REPORTING
[phone]
2359 SMITH (X)
Idaho Power Company
.
.
.
1 Q BY MR. PRICE: In this passage here,
2 you're talking about the Company accepting a trending
3 approach that was agreed to in the forecast test year
4 workshop; correct?
5 A Yes.
6 Q And is it your testimony that Staff and
7 the Company reached an agreement as to use of the
8 forecast test year?
9 A No, I don't think we reached an agreement.
10 I think we discussed different methodologies and the
11 Company was asked to put forth a testimony and a
12 methodology and that's what we did.
13 I just wantQ So where was the agreement?
14 You said therean interpretation there of that passage.
15 was an agreement as to the trending approach.
16 A , Well, we agreed that we would put together
17 a forecast test year. That's what we did. We didn't
18 agree on the specific methodology, but we agreed to put
19 forth a forecasted test year.
20 Okay, and I'd also refer you to pages 21Q
21 through 22 of your rebuttal testimony. In this section
22 here, you're talking about O&M accounts during the time
23 period of 2003 through 2007 and you note there that
24 customers on Idaho Power's system increased approximately
25 3.21 percent and that the O&M budget increased 6.39
CSB REPORTING
[phone]
2360 SMITH (X)
Idaho Power Company
.
.
.
1 percent. That's on page 22, line 2, and this is during
2 the time period of 2003 through 2007; is that correct?
3 A Yes. This was data that we used to
4 compare to other utilities out of FERC Form 1 and the
5 point of this part of my rebuttal testimony was just
6 simply to say that the growth in customers for Idaho
7 Power Company as a ratio to the growth in O&M to this
8 peer group that is also on my Exhibit No. 85 or 86,
9 excuse me, our growth in customers relative was 1.6 times
10 versus our growth in O&M expenses being 1.1 times.
11 Q Idaho Power's base rates also went up
12 during that time period; correct?
13 A In February of 2008, March of 2008.
14 Q I'm speaking of the 2003 through 2007
15 period.
16 A Yes.
17 Q And would you agree, subj ect to check,
18 that revenue requirement increased by approximately $90
19 million during that time period?
20 A Subj ect to check, sure.
21 Q Well, now, let's turn to the exciting
22 portion of your rebuttal testimony, the P-cards. Is it
23 accurate to say that Idaho Power's policy regarding
24 P-cards are that employees are only to use P-cards for
25 business purposes?
CSB REPORTING
[phone]
2361 SMITH (X)
Idaho Power Company
.
.
.
1 A Yes, we have a policy that outlines the
2 business purposes for our P-cards.
3 Q How many employees, approximately, have
4 these P-cards?
5 A I don't have that number with me, but not
6 every employee has one, but many employees have them and
7 the reason that they do is because they are for low
8 dollar, high volume transactions that actually save money
9 for Idaho Power and for the customers because we're not
10 wri ting as many checks, we don't have as much petty cash
11 available, so it's really for those types of
12 transactions.
13 Q Okay, and that's the whole point of the
14 P-card system, right, that you don't have to mess with
15 A Contracts.
16 Q -- purchase orders, invoices, stuff like
17 that?
18 A Right. We no longer have open vendor
19 accounts and an open vendor account is, you know, an
20 account that's at each different hardware store, for
21 example, across southern Idaho, so it's hard to keep
22 track of the spending when we do it that way, so this
23 allows us to get discounts or to apply pressure to
24 vendors to reduce those costs.
25 Q How does the Company determine who should
CSB REPORTING
[phone]
2362 SMITH (X)
Idaho Power Company
.
.
.
1 get a P-card? What type of employee is eligible to have
2 one of these P-cards?
3 Manager review gets the authorization forA
4 a P-card.
5 And you alluded earlier to the internalQ
6 controls in place to prevent employee misuse of P-cards.
7 A Yes.
8 Okay, and when you say misuse or when youQ
9 acknowledge that I said misuse, you mean in a manner
10 inconsistent with Company's policy?
11 Yes, and if someone, for example,A
12 unintentionally uses their card or even if they
13 intentionally did it, we have a review process that if
14 the manager determines that it is an inappropriate
15 charge, we would just simply charge that back through the
16 employee's payroll, among other things as far as misusing
17 a P-card.
18 There's this extensive process that goesQ
19 on after a P-card purchase is made. It's not
20 pre-purchase, it's post-purchase that this process takes
21 place; correct?
22 It is a post-review process.A
23 Does the Company have an outline ofQ
24 allowable P-card purchase, I don't know, items? You say
25 it's for small items, for small purchases. Does the
CSB REPORTING
[phone]
2363 SMITH (X)
Idaho Power Company
.
.
.
1 Company have a list of the types of items that are
2 acceptable?
3 A I'm not sure how specific the list is, but
4 we do have indicators, guidelines and things like that,
5 yes.
6 Q And you talked about a cost center and
7 that they review the P-card purchases; correct?
8 A Could you repeat your question?
9 Q You talked about a cost center, post
10 P-card purchase, that those employees that work at the
11 cost center review P-card purchases.
12 A Well, your manager reviews your P-card
13 purchase and also we have a monthly review that is done
14 by Steve's group, which is the AP team, so if they review
15 their detail and find something that they have questions
16 about, they direct those to their team leader or to
17 Steve, for example. On a monthly basis we have also
18 review by Mr., Keen, by Mr. Anderson who is the CFO and by
19 the team leader over the AP team.
20 Q And when this manager sits down to review
21 these P-card expenditures, is that the only thing that's
22 in front of the manager or does it come in this
23 generalized report with other expenses out there?
24 A No, it's specifically for the P-card.
25 Q Okay; so far we've got the manager review
CSB REPORTING'
[phone]
2364 SMITH (X)
Idaho Power Company
.
.
.
1 level and then after the manager review level, then it
2 goes to the cost center; is that correct? Maybe I'm not
3 remembering correctly, but there are several levels of
4 scrutiny; right?
5 A Yes.
6 Q And does that --
7 A But the manager does the most detailed
8 review of an employee's purchases.
9 But it doesn't stop there, it keeps goingQ
10 up and up and I think you talked about it even goes up to
11 a senior vice president level and then to the chief CFO;
12 correct?
13 A Right, and don't be -- the review of the
14 book is probably two inches wide, so it is a cursory
15 review. He's looking for things that look like
16 exceptions and things like that when I say at that level
17 of the Company that the review is taking place.
18 And if an employee is found to have abusedQ
19 this process, then the Company takes it out of their
20 paycheck; is that right?
21 A Yes.
22 And is that a separate review or does thatQ
23 just happen perfunctory if the manager reviews and says
24 this isn't allowable, he would just go ahead and have it
25 deducted or is there another review to see whether that
CSB REPORTING
[phone]
2365 SMITH (X)
Idaho Power Company
.
.
.
1 manager acted appropriately?
2 A Not ever having had that happen to me, I'm
3 assuming the manager would let the employee -- would
4 ei ther ask the employee about the expense that was
5 incurred and ask why and if it was not an accident, for
6 example, then I would assume that the manager would say
7 that we'd like to get that ran through payroll.
8 Q So we've got, by my count, at least four
9 levels of review; correct? Manager? Cost center?
10 A You can use cost center and manager as the
11 same, so three.
12 Q Okay, the accounts payable team leader?
13 A Uh-huh.
14 Q And then it goes up even further up
15 finally to the chief CFO?
16 A Vice president and treasurer.
17 Q The vice president and treasurer; so given
18 all these leve~s of analysis and review, it's the
19 Company's position that this P-card system actually saves
20 the Company money?
21
22
A Yes, it is.
Q And has anybody done a detailed study to
23 reveal how much money the Company has actually saved by
24 implementing this P-card system versus not implementing
25 it?
CSB REPORTING
[phone]
2366 SMITH (X)
Idaho Power Company
.
.
.24
25
1 A I know that they're always looking at the
2 policy and the provider of the vendor, so we're currently
3 going through a P-card review now from the standpoint of
4 who's providing the P-cards and what technology they
5 have, so as far as the cost of the program, it's
6 frequently reviewed.
7 Q I'm not saying the actual cost. I mean,
8 it may be cost effective as compared to other programs
9 that are out there. What I'm talking about is whether
10 implementing this P-card system while it may make life a
11 lot easier for Idaho Power employees may not in the end
12 be the right thing to do, if anybody has done a financial
13 analysis demonstrating that implementing this P-card
14 system has borne fruit for the Company in terms of
15 bettering their bottom line.
16 A Mr. Keen would probably be a better
17 wi tness to answer if that financial analysis has been
18 reviewed or conducted.
19 Q So fair to say that you're not aware of
20 any?
21 A I don't know.
22 Q Okay. I if I could refer you to page 33
23 of your rebuttal testimony, please.
A Okay.
Q Lines 12 through 14. In there, I think
CSB REPORTING
[phone]
2367 SMITH (X)
Idaho Power Company
.
.
.
18
1 this is one of your corrections earlier.
2 A Yes.
3 Q That 884,000, I think you corrected that
4 number--
5 A 788.
6 Q -- to 788, adjustment to P-card purchases
7 made for ratemaking purposes and, again, that adjustment
8 is out of the total of approximately $11 million worth of
9 P-card purchases?
10 A I believe that's correct.
11 Q And would you believe, subj ect to check,
12 that that accounts for approximately eight percent of
13 total P-card purchases?
14 A Yes.
15 Q So Staff approved 92 percent,
16 approximately, of these P-card purchases for ratemaking
17 purposes?
A If the Commission accepted the reduction
19 of 884,000.
20 Q Yeah, of course, if the Commission accepts
21 Staff's proposal as that adjustment. On page 35, lines 1
22 through 4, you talk about your, the qualms that you have
23 with the adjustment of, I believe it's lines 1 through 4,
24 about the adjustment made for restaurant purchases?
25 A Uh-huh.
CSB REPORTING
[phone]
2368 SMITH (X)
Idaho Power Company
.
.
.
1 Q And your response to it, you say, "The
2 Company has adequate oversight controls in place for
3 these types of purchases in order to ensure they have a
4 legi timate business purpose and are neither excessive nor
5 unreasonable. " What sort of criteria does the Company
6 have to determine whether buying an employee's lunch is a
7 legi timate business purpose?
8 A Well, if an employee is out of town, for
9 example, if the employee has business that can only be
10 conducted at lunchtime, which I know I experience that,
11 you know, quite a bit, if the employee is traveling, so
12 yes, we have guidelines for what the expenses are used
13 for.
14 Q And isn't it true that that adj ustment,
15 the 236,000, approximately, was for restaurant purchases
16 within the Company's service territory?
17 A Yes.
18 Q This wasn't, like, off in New York City
19 at, I don't know, a training or whatever?
20 A Well, it's Ms. Vaughn's analysis of the
21 extract that we provided to her.
22 Q On page 40, lines 11 through 12, in here
23 you're talking about the cell phones and the cell phone
24 plan that the Company has entered into. You testify on
25 lines 11 through 12 that the contracts with carriers are
CSB REPORTING
[phone]
2369 SMITH (X)
Idaho Power Company
.
.
.
20
1 continuously reviewed and renegotiated resulting in more
2 competi ti ve pricing. Then later on in lines 15 through
3 19 you say that the Company has negotiated an umbrella
4 contract
5 A Right.
6 Q -- correct? So it's fair to say that the
7 Company is no longer negotiating, that this umbrella
8 contract lasts for, I don't know, two years, three years?
9 Is there a service agreement involved there?
10 A Yes, there is.
11 Q And I take it, also, if this is an
12 umbrella contract, it covers all employees; correct?
13 A Yes.
14 Q So the general Idaho Power policy now is
15 that all Company employees merit a cell phone?
16 A No.
17 Q Page 41, in this section you take issue
18 wi th Staff's adj ustments regarding gifts and awards.
19 A Yes.
Q You say that these benefits offered to
21 employees are essential because they improve morale
22 wi thin the Company; correct?
23 A Improve morale, help to keep talented and
24 trained employees. I think Mr. Keen mentioned on Tuesday
25 the number of employees that have been cannibalized by
CSB REPORTING
[phone]
2370 SMITH (X)
Idaho Power Company
.
.
.
1 other utilities, for example, so service awards and
2 excellence awards and some of these smaller items are
3 being used by the Company to retain qualified employees
4 that are expensive to retrain.
5 Q And do retirement parties also improve
6 morale and a positive working environment?
7 A Yes, they do.
8 Q And they should be recovered through
9 rates, the expenses incurred there?
10 A Yes, I believe so.
11 Q Christmas parties for employees, should
12 those expenses also be recovered?
13 A Yes, I think there are very few of
14 those.
15 Q Page 54, this is Mr. Nobbs' adj ustments to
16 expenses for alarm clocks, candy, et cetera. You
17 disagreed with his adj ustment. Here on page 54, at lines
18 10 through 11, you say, "These expenses had a definite
19 business purpose and benefit," and I think you cite the
20 fact that the alarm clocks had the Idaho Power logo on
21 them.
22
23
A Yes.
Q Isn't that similar or could be construed
24 as advertising, image advertising, for the Company?
25 A Yes, and where these alarm clocks were
CSB REPORTING
[phone]
2371 SMITH (X)
Idaho Power Company
.
.
.
1 applied, it was at an EEI financial analyst conference
2 that has over 1,500 financial analysts that attend.
3 Those are both buy side and sell side analysts that are
4 either tracking the Company or writing research on the
5 Company, so for them to be able to recogni ze our label,
6 for example, is very important. We've had a lot of
7 discussion today about the volatility in the markets and
8 providing this small trinket to entice people, not
9 entice, but to have people come by and visit us is very
10 important to us.
11 Q So it's meant to bolster the Company's
12 image and keep their name out there; correct?
13 A And to help them remember who they talked
14 to.
15 Q And isn't it historical accounting
16 practice to move expenses associated with image
17 advertising below the line?
18 A Yes, it is.
19 Q On page 55, lines 2 through 5, this is the
20 butter toffee offered to credit rating agencies?
21 A No, it was actually provided to county
22 offices for help on locating easements, for example, GIS
23 data information, so it was simply a thank you for
24 helping us in working through some easements and we have
25 hundreds and hundreds of easements that we have to
CSB REPORTING
[phone]
2372 SMITH (X)
Idaho Power Company
.
.
.
1 track.
2 Q But the credit rating agencies were
3 actually present; correct?
4 A No, I'm not sure what you're reading that
5 would indicate that.
6 Q I'm reading page 55.
7 A The alarm clocks for
8 Q I'm sorry, you're right, it's the next
9 paragraph, I apologize. I got my cite mixed up here, it
10 all runs together.
11 A I can imagine.
12 Q May I refer you to page 56 and this talks
13 about the contributions that the Company made to the
14 Caldwell Economic Council as well as Eastern Oregon
15 Visi tors Association. You acknowledge that that money
16 should be removed?
17 A Yes.
18 Q And just a general question for you just
19 to wrap it up, earnings, can earnings be increased by
20 reducing expenses?
21 A Yes, earnings can increase by reducing
22 expenses.
23 Q And wouldn't this in turn have a tendency
24 to increase Idaho Power's returns?
25 A Yes. Mathematically, that is the way it
CSB REPORTING
[phone]
2373 SMITH (X)
Idaho Power Company
.
.
.
1 works.
2 MR. PRICE: Okay, thank you.
3 THE WITNESS: Or you increase revenue.
4 MR. PRICE: That's all I have.
5 COMMISSIONER SMITH: Are there questions
6 from the Commission?
7 COMMISSIONER KEMPTON: No questions.
8 COMMISSIONER REDFORD: I have a couple of
9 questions.
10
11 EXAMINATION
12
13 BY COMMISSIONER REDFORD:
14 Q In the industries that I've either worked
15 for or repres~nted over the years, vice president of
16 planning, corporate planning, is a fairly significant
17 posi tion. Do you interact with the board of directors?
18 A Yes, I do.
19 Q And so where I'm going with this is at
20 some point in time before the next fiscal year, you
21 present to the board of directors your forecast of
22 revenue and your forecast of or your budget?
23
24
25
A Yes, that's correct.
Q Okay, also in the companies that I've
represented that in the event that there's some startling
CSB REPORTING
[phone]
2374 SMITH (Com)
Idaho Power Company
.
.
.
1 event, whether it be a large loss or in Idaho Power's
2 case, you know, a dam fails or something like that, that
3 is what we used to refer to as a bust and it was -- we
4 were required by the board of directors to come in with
5 new figures, new planning figures, new budget to reflect
6 the catastrophic occurrence.
7 A Yes.
8 Q Have you been to the board of directors or
9 has anyone from your Company been to the board of
10 directors to adjust your planning and your budget to
11 reflect this recent downturn in events financially in the
12 country?
13 A Yes. What we typically do is we typically
14 have our business planning meeting in November and this
15 year that has been postponed until January, so we will be
16 taking those plans to the board in January.
17 Q So realistically, your plans based upon
18 this catastrophic situation will undoubtedly change as
19 well as your budget?
20 A We had put together a budget and we are
21 currently reviewing all the details of that, particularly
22 in the capital spending area. As we see the number of
23 new customers decline from where they have been, we will
24 be adjusting our capital related to that.
25 Q It's just a little curious to me that the
CSB REPORTING
[phone]
2375 SMITH (Com)
Idaho Power Company
.
.
.
1 Company's application for this rate increase was based
2 upon numbers and plans which at the time the financial
3 condi tion of the Company and the nation was in a little
4 bi t better shape; is that correct?
5 A I would say that is correct, but I would
6 also like to add that in 2008 we have spent
7 three-quarters of what we said that we were going to
8 spend, so we have already spent the money.
9 Okay. Wouldn't that trigger a change inQ
10 some of your numbers in this rate application?
11 No, because 2008, as Mr. Keen indicatedA
12 earlier, it's, about spending the money and getting the
13 money recovered. This is very similar. We have spent
14 the money and we are here to get it recovered for taking
15 place in the beginning of 2009.
16 Okay, but the test year is a prospectiveQ
17 year?
18 Yes, and it's representative of what'sA
19 happened in 2008, so yes, I agree, it is a prospective
20 test year.
21 So the business conditions inasmuch as youQ
22 filed earlier this year and taking into consideration the
23 financial condition of the country and so on, you've not
24 seen the numbers change at all?
25 No, what we have seen, and Mr. Gale hasA
CSB REPORTING
[phone]
2376 SMITH (Com)
Idaho Power Company
.
.
.
1 agreed to, for example, Mr. Leckie's annualizing
2 adj ustment for payroll, Mr. Leckie recommends that we use
3 August and September for our annualizing adjustment for
4 payroll into 2009 versus the Company's December, when we
5 would normally use December, so you can see a reduction
6 there, but the capital, the càpital investments, the O&M,
7 the operating expenses, all of those have already taken
8 place.
9 COMMISSIONER REDFORD: Okay. Thank you
10 very much for your answers. I have no further questions.
11
12 EXAMINATION
13
14 BY COMMISSIONER SMITH:
15 Q I just had one I need clarified on page
16 40.
17 A Did you say 40?
18 Q I did, of your rebuttal. Beginning at
19 line 11, it's back on the telephone thing.
20 A The cell phones?
21 Q Yeah. The sentence that starts on line 15
22 about you have this umbrella contract that covers all
23 employees, does that mean that any Idaho Power employee
24 can be, get service under the umbrella contract?
25 A Yes, it means any Idaho Power employee
CSB REPORTING
[phone]
SMITH (Com)
Idaho Power Company
2377
.
.
.
20
21
22
23
24
25
1 that has a manager's approval to get a cell phone would
2 be part of that pool.
3 Q So it's just people who are authorized to
4 have a Company-provided cell phone?
5 A Yes.
6 COMMISSIONER SMITH: Okay. Thank you.
7 THE WITNESS: Thank you.
8 COMMISSIONER SMITH: Do you have any
9 redirect, Ms. Nordstrom?
10 MS. NORDSTROM: I do. Thank you.
11
12 REDIRECT EXAINATION
13
14 BY MS. NORDSTROM:
15 Q Mr. Ward was discussing growth earlier and
16 how it related to compound annual growth rates and it was
17 a little confusing, so I'm going to try and eliminate
18 some of that. He said that Mr. Said in his testimony
19 referred to a 1.9 percent growth rate.
A System growth,system load growth.
Q And is that in megawatts?
A Yes.
Q And your growth rate that you were talking
about in your testimony,is that in dollars?
A No, it's in number of new customers
CSB REPORTING
[phone]
2378 SMITH (Di)
Idaho Power Company
.
.
.
1 added.
2 Q So does growth in megawatts and growth in
3 customers added equate to the same dollar amount?
4 A When you say "dollar amount," what do you
5 mean?
6 Q Same percentage.
7 A No, because
8 Q It's apples and oranges?
9 A Yes, I would say it's apples and oranges,
10 because not only do new customers cause system load
11 growth, your existing customers cause system load growth
12 and what I'm referring to is the annual additions of new
13 customers.
14 Q All right. The purpose of any inflation
15 adj uster rate that the Company used was to accurately
16 estimate what 2008 expenses would be; correct?
17 A Yes, that's the purpose of it.
18 Q Now that eleven-and-a-half months of the
19 proposed test year have actually occurred, how accurate
20 is your projection turning out to be?
21 A Well, as I stated in my testimony, through
22 September we have spent the capital on the capital
23 projects that we indicated and our operating expenses are
24 three-quarters of the way through the test year. I have
25 not analyzed it through November, but I would expect that
CSB REPORTING
[phone]
2379 SMITH (Di)
Idaho Power Company
.
.
.
1 it's going to be very close.
2 Q Do you know if the Company has expressed a
3 posi tion regarding truing up the dollars in this rate
4 case to actual expenses?
5 A I f we've expres sed an opinion about it?
6 Q Yes.
7 A I'm not sure.
8 Q You haven't read Mr. Gale's rebuttal?
9 A Yes, I have.
10 Q All right; so there might be an opinion
11 expressed in Mr. Gale's rebuttal?
12 A Well, I was going to say Mr. Gale probably
13 has an opinion about that.
14 Q Okay, well, if anyone has any questions
15 about that, I'm sure they'll direct those questions to
16 him. There was some discussion about P-cards for
17 restaurant expenses and there was a distinction between
18 expenses incurred within our service territory and
19 expenses incurred outside the service terri tory. Why
20 would the majority of restaurant expenses be in our
21 service territory?
22 A Because our employees, the maj ori ty of our
23 employees, they work wi thin our service terri tory.
24
25
Q And under what sorts of circumstances
would employees be needing to have meals reimbursed
CSB REPORTING
[phone]
2380 SMITH (Di)
Idaho Power Company
.
.
1 wi thin the service terri tory?
2 A Well, we have offices, maj or offices, in
3 Pocatello, Twins Falls, Payette, McCall. We have
4 meetings occasionally in Boise. We have leaders that
5 travel to all of those locations for employee meetings,
6 for training, you know, so we've got people outside of
7 their normal areas. Within the area, for example, we
8 occasionally take people out for lunch for banking
9 relationships, all of those types of expenditures being
10 very normal business expenses for any kind of company,
11 regulated or nonregulated.
12 Q Mr. Price asked a question with regard to
13 the logo on the alarm clock and whether or not that was
14 an advertising expense. Was the purpose of that so that
15 the Company could sell more kilowatts?
16 A The purpose was for the recognition as the
17 visitors to that particular conference go home, they have
18 talked to hundreds of people, so it's a matter of
19 recognizing who they talked to, kind of putting a face
20 with a small
21 Q So it's not your typical advertising
22 expense, is it?
.
23 A No.
24 Q Why is it important to get ratings
25 coverage?
CSB REPORTING
[phone]
SMITH (Di)
Idaho Power Company
2381
.
.
.
1 A It's important to get ratings coverage to
2 get the story of the Company out, to create knowledge
3 about the Company that investors will want to invest in.
4 It's to, you know, get efficient access to capital
5 markets, so the more coverage you have, the more research
6 you have, the, more information is available for
7 investors, for example.
8 Q So how does that benefit customers as
9 opposed to shareholders?
10 A Well, your overall cost of capital is
11 going to be cheaper if you have a knowledgeable base of
12 analysts that cover you.
13 Q There was some discussion about, well,
14 from Mr. Price about how a decrease in expenses would
15 actually increase the Company's earnings. Isn't that
16 true only until rates are put into place?
17 A Yes.
18 Q So is there a difference between to some
19 degree how it works mathematically and how it works out
20 in the long run practically?
21 A Well, I think the Company looks for every
22 opportuni ty to keep its costs down and the reduction in
23 those costs is reflected in the revenue requirement in
24 the frequencies that you have rate cases.
25 Q And so by reducing those O&M expenses and
CSB REPORTING
[phone]
2382 SMITH (Di)
Idaho Power Company
.
.
.
1 once they are reflected in rates, does that benefit
2 customers?
3 A The reduction in expenses?
4 Q Yes.
5 A Yes, it would benefit customers because
6 they would have less revenue requirement to pay for.
7 MS. NORDSTROM: Thank you. No further
8 questions.
9 COMMISSIONER SMITH: Thank you, Ms. Smith.
10 THE WITNESS: Thank you.
11 (The witness left the stand.)
12 COMMISSIONER SMITH: I think we need to
13 take a break.' How about coming back at 25 after 3: 00.
14 (Recess. )
15 COMMISSIONER SMITH: All right, we'll go
16 back on the record. Ms. Nordstrom, did you have a
17 wi tness you wished to re-call?
18 MS. NORDSTROM: Yes, I would like to
19 re-call Steve Smith -- Steve Keen to the stand.
20
21
22
23
24
25
CSB REPORTING
[phone]
2383 SMITH (Di)
Idaho Power Company
.
.
.
1 STEVEN R. KEEN,
2 produced as a witness at the instance of the Idaho Power
3 Company, having been previously duly sworn, resumed the
4 stand and was further examined and testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MS. NORDSTROM:(Continued)
9 Q Mr. Keen, were you in the room when Lori
10 Smi th discussed purchasing cards?
11 A Yes, I was.
12 Q And did you hear the question about the
13 cost effectiveness of P-cards that she had difficulty
14 answering?
15 A / Yes, I did.
16 Q And can you answer that question?
17 A I can add some color to it. The P-card
18 process that we currently have, we're in the process of
19 looking at a new P-card process which will have a new
20 vendor and probably some new operating guidelines, but
21 the old process was done before I was the treasurer, but
22 the person, my direct report in that area was here when
23 that process was undertaken and I know there was a
24 combination of stemming some new hires that we would have
25 had to have made to continue processing checks at the
CSB REPORTING
[phone]
2384 KEEN (Di)
Idaho Power Company
.
.
.
1 volume we were previously and also some actual reductions
2 at the time we implemented that plan and there's a
3 feature in the P-card process where we get rebates for
4 our actual spend on the cards, so we participate in what
5 the banks earn on that spend and that's a maj or piece of
6 the new contract we're negotiating is we're going to get
7 a bigger piece of that spend back and it comes straight
8 in and goes as a reduction to O&M, so I can say there was
9 a process at least at the time it was viewed as favorable
10 and certainly now that we're redoing it, it's still
11 coming up that it's a favorable plan to have some type of
12 P-card.
13 Q So how often does the Company review the
14 cost effectiveness of the P-card program?
15 A We signed an initial contract and I can't
16 remember the length of term, but it was basically as we
17 were approaching an expiration of the term under the last
18 contract, we looked at it again and I think the first one
19 must have run for about four years.
20 Q And is it still cost effective?
21 A I believe it is, yes. It's certainly best
22 practiced in the industry and I know that the team that
23 has been tasked with that looked at various options of
24 putting back in check processing for some pieces and that
25 didn't pencil out well, so...
CSB REPORTING
[phone]
2385 KEEN (Di)
Idaho Power Company
.
.
.
1 Q And you talked about rebates and how that
2 reduced O&M, so does that mean that customers benefit
3 from the rebates?
4 A Yes.
5 MS. NORDSTROM: Thank you. No further
6 questions.
7 COMMISSIONER SMITH: Did that generate any
8 cross-examination on the part of any of the parties?
9 MR. PRICE: Yes.
10 COMMISSIONER SMITH: Mr. Price.
11 MR. PRICE: I have one question.
12
13 CROSS-EXAMINATION
14
15 BY MR. PRICE:
16 Q You say that in your opinion it's cost
17 effecti ve. Did the Company prepare any graphs, charts,
18 studies, analyses as to the cost savings to the Company
19 through the implementation of the P-card system?
20 A ' Yes, they did. I know there was -- I know
21 they exist. It was a few years ago. That's not a real
22 recent process that that was done on the plan that we're
23 operating in now. There's a whole new set of
24 documentation on the analysis that's underway to do a
25 vendor change.
CSB REPORTING
[phone]
2386 KEEN (X)
Idaho Power Company
.
.
.
1 Q Was that disclosed in this case?
Well, the new plan isn't in place yet.
3 We're going to pilot it in 2009 and then decide if we go
2 A
4 that way during 2009, so that's not part of this case.
5 The old plan, the documents would have been available,
6 but they would have been several years old, so I don't
7 know that they were put forward. They're certainly
8 available if somebody wants to see them.
9 Q That information was not provided in this
I honestly don't know.
As part of rebuttal testimony?
Not that I'm aware of.
And you would be the person that would be
15 directly responsible for providing that type of
20
21
22
23
10 case; correct?
11 A
12 Q
13 A
14 Q
16 information?
17 A
18
Probably one of my reports would be
responsible for providing that,yes.
MR.PRICE:Okay,thank you.
COMMISSIONER SMITH:Any other questions?
COMMISSIONER REDFORD:No.
COMMISSIONER KEMPTON:No.
COMMISSIONER SMITH:All right,thank you,
19
24 Ms. Nordstrom~
25 COMMISSIONER REDFORD:Thank you.
CSB REPORTING
[phone]
2387 KEEN (X)
Idaho Power Company
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1 THE WITNESS: Thank you.
2 (The witness left the stand.)
3 COMMISSIONER SMITH: Mr. Richardson.
4 MR. RICHARDSON: Thank you, Madam Chair.
5 The Industrial Customers of Idaho Power calls Dr. Reading
6 to the stand.
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8 DON READING,
9 produced as a' witness at the instance of the Industrial
10 Customers of Idaho Power, having been first duly sworn,
11 was examined and testified as follows:
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13 DIRECT EXAMINATION
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15 BY MR. RICHARDSON:
16 Q Are you the same Dr. Reading who caused
17 direct testimony with exhibits numbered 201 through 209
18 to be filed in this docket?
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A Yes.
Q And was that prefiled direct testimony
21 prepared by you or under your supervision?
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A Yes.
Q And were exhibits numbered 201 through 209
24 prepared by you or under your supervision?
25 A That is also true.
CSB REPORTING
[phone]
2388 READING (Di)
ICIP
1 Q And do you have any corrections or.2 additions to make to your prefiled testimony and/or
3 exhibits?
4 A None that I know of at this time.
5 MR. RICHARDSON: Thank you. With that,
6 Madam Chairman, I would move that the prefiled direct
7 testimony of Dr. Reading be spread upon the record in
8 this matter as if it were read in full and exhibits
9 numbered 20l through 209 be identified for the record.
10 COMMISSIONER SMITH: Without objection, it
11 is so ordered.
12 (The following prefiled direct and
13 rebuttal testimony of Dr. Don Reading is spread upon the.14 record. )
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CSB REPORTING
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2389 READING (Di)
ICIP
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1 INTRODUCTION
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3 Q.PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
4 A.My name is Don Reading and my business address is
5 Ben Johnson Associates, 6070 Hill Road, Boise, Idaho.
6 Q.HAVE YOU PREPARED AN EXHIBIT OUTLINING YOUR
7 QUALIFICATIONS AND BACKGROUND?
8 A.Yes. Exhibit 201 serves that purpose.
9 Q.WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS CASE?
10 A.I have been retained by the Industrial Customers of
11 Idaho Power (ICIP) to review Idaho Power's (IPC, Company)
12 application for authority to increase its rates and
13 charges for electric service. Specifically I examine the
14 Company's rate allocations that are derived from its
15 preferred cost of service (COS) study. I propose changes
16 to Idaho Power's COS that brings cost assignments closer
17 the Company's load profile as a capacity constrained
18 utili ty rather than as an energy constrained utility. I
19 also address the Company's use of a projected test year
20 and recommend an approach the Commission may take that
21 would satisfy some of the goals sought by the Company
22 while addressing some of the problems inherent with a
23 forecasted test year. I discuss the Company's
24 recommended inclusion of construction work in progress
25 (CWIP) in this case and recommend the Commission reject
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1 its inclusion in base rates. I also give a brief update
2 on the status of our virtual peaking discussions with
3 Idaho Power.
4 Cos t of Service
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2391 Reading, Di 2a
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1 Q.DR. READING, TURNING TO YOUR EXAMINATION OF IDAHO
2 POWER'S COST OF SERVICE STUDY -- COULD YOU PLEASE BRIEFLY
3 REVIEW THE COMPANY'S APPROACH?
4 A.Yes. Staff witness Tatum presents three separate
5 cost of service studies; Base Case, Modified Base Case,
6 and 3 CP /12 CP. The Company's preferred approach, as it
7 was in the last case (IPC-E-07-08), is the 3 CP/12 CP
8 study. This approach is being recommended because the
9 Company believes it is the most effective method of
10 allocating production plant costs consistent with the
11 costs imposed by each given customer class. CTatum, Di.
12 pages 51,52.)
13 Q.DO YOU HAVE ANY GENERAL OBSERVATIONS?
14 A.Yes. I have two general observations. First, Mr.
15 Tatum states that the Base Case is consistent with the
16 "Normalized" method filed in the last rate proceeding.
17 That rate proceeding, IPC-E-07-08, was settled and thus
18 the cost of service study was not litigated in that case.
19 Therefore, when comparing the Company's proposed COS with
20 past filings" the base of comparison should be the last
21 one filed by the Company and approved by the Commission
22 in case No. IPC-E-03-13.
23 Second, as indicated by Company Exhibit 69, a
24 disproportionate share of the overall 9.89% proposed
25 increase requested by Idaho Power falls on high load
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1 factor customers under all three COS cases presented by
2 the Company (irrigation service being the one exception
3 of a low load factor costumer having a significant
4 increase in revenue requirement). The indicated
5 increases for all three studies presented for residential
6 customers range from 2.01% (Base Case) to 3.71% (3 CP/12/
7 CP). On the other hand, the
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2393 Reading, Di 3a
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1 range of increases for Schedule 19 and the Special
2 Contract customers is 15.21% (Schedule 19, Modified Base
3 Case) to 32.61% (JR Simplot, Base Case) .
4 Q.WHY DO YOU POINT OUT THAT THE COST OF SERVICE STUDY
5 FILED BY THE COMPANY SHOULD LOOK TO CASE IPC-E-03-13 AS
6 THE BASE CASE FOR COMPARISON TO THE CURRENT CASE?
7 A.As I testified above, Idaho Power's last general
8 rate case was settled. In the Settlement Agreement the
9 parties agreed that the cost of service study filed in
10 that case would not be precedent setting. The Commission
11 recognized that fact in its order approving the
12 settlement:
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14 The parties also agreed that the underlying
15 cost-of-service model filed by the Company in this
16 proceeding will not constitute precedent in any
17 subsequent general rate case. The parties
18 specifically recognize that any party s failure to
19 specifically obj ect to the Company s cost-of-service
analysis' in this case will not constitute a waiver
in any future general rate case proceeding. C Idaho
Public Commission Order 30035, IPC-E-05-28, page 5.)
24 The COS filed' in the last case also allocated the major
25 share of the proposed rate increase to the high load
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1 factor customers. A hint of the reason for this
2 disproportionate share for high load factor customers is
3 found in Company witness Brilz IPC-E-05-28 Direct
4 Testimony filed in that case.
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2395 Reading, Di 4a
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1 Q.WHAT REASONS DID MS. BRILZ GIVE FOR THE
2 DISPROPORTIONATELY HIGHER ALLOCATIONS TO HIGH LOAD FACTOR
3 CUSTOMERS FOUND IN THE COMPANY'S COST OF SERVICE STUDIES?
4 A.In her filed testimony she stated,
5 Since the conclusion of the Company's last general
6 rate case it has been determined that the deficit
7 months of June, July, August, November, and December
8 used in the 2003 marginal cost analysis were
9 primarily determined by firm generation supply
10 acquisi tion need rater than determination of months
11 in which a peak-hour deficiency occurred. The
12 deficit months of January, May, June, July, August,
13 September, November, and December used in the
14 current marginal cost analysis are directly tied to
15 peak-hour deficiency months identified in the 2004
16 IRP.
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18 And,
19 The use of eight deficit months (January, May, June,
July, August, September, November, and December) in
the current marginal cost analysis results in
weighting factors that attribute more generation
capaci ty cost responsibility to customer classes
wi th usage throughout most of the year. C Direct
Testimony, Maggie Brilz, IPC-E-05-28, page 21,22.)
2396 Reading, Di 5
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1 The effect of extending the number of months used in the
2 marginal cost study from 5 to 8 months spreads the costs
3 of generation to customer classes with high use over a
4 greater number of months.
5 Q.THE COMPANY HAS INCREASED THE NUMBER OF MONTHS TO
6 WHICH IT IS APPLYING CAPACITY COSTS. WHAT HAVE BEEN THE
7 TRENDS IN THE MARGINAL COST OF CAPACITY AND ENERGY FOR
8 IDAHO POWER SINCE THE IPC-E-03-13 GENERAL RATE CASE?
9 A.There have been dramatic shifts in the costs of
10 capacity and energy for the Company in the 5 years since
11 case IPC-E-03-13 was filed. Marginal generation capacity
12 costs have dropped by 45% from $90.71 per KW to $50.00
13 per KW. The monthly amounts are shown on my Exhibit No.
14 202. While capacity costs have dropped, marginal power
15 supply costs over the same 5 year period increased
16 dramatically by 114%, from $33.38 to $71.46 per MWh. The
17 increase has been especially large in July and August
18 with currently estimated marginal costs of $99.66 and
19 $81.85 per MWh respectively.My Exhibit 203 displays
20 monthly marginal power supply costs over the last 4 filed
21 general rate cases.
22 Q.HOW DO YOU EXPLAIN THE SIGNIFICANT DROP IN MARGINAL
23 CAPACITY COSTS COUPLED WITH THE DRAMATIC INCREASE IN
24 MARGINAL ENERGY COSTS?
25 A.It appears to be the function of two interrelated
2397 Reading, Di 6
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1 factors. Natural gas prices have increased since the
2 filing of the general rate case in 2003, and the Company
3 has added gas peaking
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2398 Reading, Di 6a
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1 resources. The capacity costs of a gas peaking unit on a
2 per KW basis are relatively lower than other generating
3 resources. The trade off for these lower capacity costs
4 is higher fuel costs and hence higher energy costs. The
5 higher gas prices have also driven the cost of purchasing
6 off system power to higher levels.
7 Q.IDAHO POWER HAS A RESOURCE STACK WITH MIX OF
8 DIFFERENT TYPES OF RESOURCES. WHAT HAVE BEEN THE CHANGES
9 IN THE COST OF ENERGY ON A NORMALIZED BASIS OVER THE PAST
10 5 YEARS?
11 As shown on my Exhibit 204, energy costs haveA.
12 increase from a variety of resources. Both Bridger and
13 Valmy , with essentially the same output since 2005, have
14 experienced increased energy production costs by $35
15 million. The two gas fired units in the Company's
16 resource stack have power supply costs of $81.96 per MWh
17 for Bennett Mountain and $195.53 per MWh for Danskin.
18 The cost of off system purchases have increased from
19 $39.9 per MWh in case IPC-E-03-13 to $58.8 per MWh in
20 the current case. The value of off system sales has also
21 increased, but by a lesser amount, from $20.9 per MWh in
22 2003 to $45.6 per MWh. It should be emphasized the
23 current case values are based on projections by the
24 Company.
25 Q.YOU HAVE DEMONSTRATED THE INCREASES IN ENERGY COSTS
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lOVER THE PAST 5 YEARS FOR IDAHO POWER. IS THIS A CAUSE
2 OF HIGH LOAD FACTOR CUSTOMERS BEING ASSIGNED THE MAJOR
3 SHARE OF THE PROPOSED RATE INCREASE?
4 A.Yes. The paradoxical aspect of this increase in
5 energy costs relative to capacity costs is
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2400 Reading, Di 7 a
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1 the fact that Idaho Power has changed from a energy
2 constrained utility to a capacity constrained utility
3 over the past 15 years. This shift has been driven
4 primarily by the growth in the residential and small
5 commercial classes over the past dozen years. This is
6 the reason the Company has constructed 260 MWs of gas
7 peaking units as its latest resources. These higher
8 energy costs are reflected in the Company's cost of
9 service studies which pass on higher energy costs to high
10 load factor customers. However for a utility that is
11 capacity constrained, higher price signals should be sent
12 to those customer classes that have the lowest load
13 factors. The results of Idaho Power's cost of service
14 studies does just the opposite by charging a
15 disproportional share to customers that have high load
16 factors.
Q.AS YOU POINTED OUT ABOVE, THE RESIDENTIAL CLASS,
18 (AND TO A LESSER EXTENT THE SMALL COMMERCIAL CUSTOMER
19 CLASS) IS RECEIVING THE LOWEST PERCENTAGE INCREASE, WHILE
20 THE HIGH LOAD FACTOR CUSTOMERS ARE RECEIVING THE HIGHEST.
21 WHAT DOES THIS SAY ABOUT PRICE SIGNALS TO CUSTOMERS?
22 A.It sends the wrong price signals, because the result
23 of the Company's COS allocates more costs to energy than
24 to capacity, which is reflected in the Company's proposed
25 rates. The recommended rate increase for Schedule 19 and
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1 Special Contract customers is 2.4 times higher than for
2 the residential class. Yet the Company has been adding
3 peaking resources to meet the increasing demand during
4 peak periods that is being driven largely by residential
5 customer growth.
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1 Q.HAVE YOU FOUND ANOTHER CAUSE WITHIN THE COMPANY'S
2 COST OF SERVICE STUDIES THAT HAVE SHIFTED COSTS FROM
3 RESIDENTIAL AND SMALL COMMERCIAL CUSTOMERS TO HIGH LOAD
4 FACTOR CUSTOMERS?
5 A.Yes. As outlined in Company witness Tatum's
6 testimony one of the changes to come out of the three
7 cost-of-service workshops was a method of "normalizing"
8 class coincident peak demands.
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10 The surrogate demand normalization methodology uses
11 ithe fi ve~year median demand ratios from the load
12 research sample applied to the normalized monthly
13 energy values for each customer class to determine
14 the coincident peak demands by class. This
15 methodology reduces the effect of any atypical
16 demand ratios that might exist in a given test year
due to unusual weather conditions. CTatum, p. 11.)
19 The Company calculates system coincident demand factors
20 for each customer class for each month. These coincident
21 demand factors are derived by finding the kW demand at
22 the system peak hour divided by the average kW demand for
23 the month. These are calculated for each of the years
24 2003 through 2007, then the median value over the 5 year
25 period is selected for each month for each customer
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1 class. One would expect the pattern of median values for
2 the customer classes to be somewhat similar given typical
3 or atypical years.
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1 Q.DID YOU FIND SIMILAR PATTERNS AMONG CUSTOMER CLASSES
2 WHEN YOU EXAMINED THE PATTERN OF THE SYSTEM COINCIDENT
3 DEMAND FACTORS?
4 A.No. For the residential class six of the median
5 values for these factors occur in 2003 with another four
6 being found in 2004. On the other hand, for Schedule 19,
7 eight of the median system coincident factors occur in
8 2006 with another two in 2007. Other customer classes
9 show varying patterns over the five year period of median
10 system coincident demand factors. This anomaly produces
11 the effect that for some classes the cost of service
12 values are being determined weighted for load patterns
13 that occurred four or five years ago while for other
14 classes this weighting effect occurs in more recent
15 years.
16 Q.DID YOU EXAMINE HOW THE PATTERN YOU JUST DESCRIBED
17 ABOVE COULD IMPACT COST OF SERVICE VALUES AMONG CUSTOMER
18 CLASSES?
19 Yes. Rather than using the median values for the system
20 coincident demand factors I substituted in the 2007
21 values and ran the 3 CP/12 CP model with no other
22 changes. Use of 2007 system coincident demand factors,
23 rather than the five year median values, produced some
24 significant shifts among some customer classes. In
25 general there, was a shift of costs away from the higher
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1 load factor customer classes to the lower load factor
2 classes. The residential class revenue deficiency
3 increased nearly $5 million meaning the percent increase
4 in rates went from 3.71% to 6.26%. Csee Exhibit 205)
5 While the Large General Service class percent increase in
6 rates dropped to 2.12% from 9.16%, and Schedule 19's
7 increase was reduced from 15.87% to 14.97%. These
8 results appear to
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2406 Reading, Di lOa
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1 assign cost responsibility more in line with what one
2 would expect given the growth in Idaho Power's system
3 over the last 15 years. These results should be viewed as
4 preliminary. The Company's Cost of Service method
5 requires several steps of transferring large amounts of
6 data to make this change. We are working with the Company
7 to verify these steps have been made correctly. To the
8 extent the results presented here vary from the
9 Company's, we will adopt ,the Company's verification of
10 these results and file revised exhibits.
11 Q.BY RECOMMENDING THE USE OF THE 2007 VALUES FOR
12 SYSTEM COINCIDENT DEMAND FACTORS RATHER THAN THE MEDIAN
13 ARE YOU SAYING COINCIDENT KW SHOULD NOT BE NORMALIZED IN
14 SOME MANNER TO ACCOUNT FOR ATYPICAL YEARS?
15 A.No. I think the Company and the cost of service
16 workshop participants were addressing this as a potential
17 problem. However the experience of using the median
18 method as described above has lead to anomalous results.
19 For this case, the use of 2007 yields results that are
20 more consistent with what one would expect given the
21 Company's load patterns. I would recommend the Company
22 and the parties work together to find a method of
23 normalizing kW coincident demand factors.
24 Q.DO YOU HAVE OTHER RECOMMENDATIONS THAT WOULD HELP
25 REMEDY THE PARADOXICAL RESULTS OF THE COMPANY'S COST OF
SERVICE STUDIES?
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1 I have two additional recommended changes to the cost of
2 service method used by the Company. The cost of service
3 resul ts described below are based on changes from the
4 Company's recommended 3 CP /12 CP Case.The other two
5 changes are:
6 1) I recommend that the weightings for customer
7 classes be set at full marginal cost rather than the
8 average of marginal and imbedded weightings used by
9 the Company. This will more accurately reflect the
10 costs that are being incurred by the Company because
11 marginal costs best represent the costs of
12 additional capacity and energy from needed
13 additional resources. See my Exhibit 206.
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15 2) I also recommend that the Company's hydro
16 resources be allocated between demand/energy to 75%
17 capaci ty' and 25% energy rather than the system
average split that is currently used by Idaho Power.
19 This is more in line with standard cost allocations
and are the same values used by Rocky Mountain Power
in both its current and last rate case before the
Commission. See my Exhibit 207.
The results of these three modifications to the
Company's approach are detailed in Exhibits 205, 206 and
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1 207. I will outline each change separately below, and
2 then summarize them in combination with one another.
3 Q.DR. READING PLEASE TURN TO YOUR FIRST MODIFICATION
4 OF THE COST OF SERVICE STUDY PRESENTED BY THE COMPANY.
5 WHY DO YOU BELIEVE FULL MARGINAL COST WEIGHTING REFLECTS
6 THE COMPANY'S, COSTS BETTER THAN ACTUAL VALUES?
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1 A. As explained above, one of the problems with the
2 class cost allocations that result from the Company's
3 cost of service studies is that cost allocations are not
4 reflected in the rates for those customer classes that
5 drive costs on Idaho Power's system. Exhibits 202 and
6 203 depict the marginal costs of capacity and energy
7 indicate the dramatic differences in cost over the
8 different months of the year. Full marginal cost
9 weightings then will reflect more fully these difference
10 among customer classes and thus better reflect the costs
11 each custom class is placing on the system.
12 Q.WHAT ARE THE RESULTS OF THIS MODIFICATION TO THE
13 COMPANY'S 3 CP/12 CP MODEL?
14 A. It should be noted before I discuss the results of
15 these cost of service modifications, that all the values
16 are based on the Company receiving its full proposed
17 increase of 9.89%. A different overall rate increase
18 will change the percentage change for each customer class
19 in ratio with that overall rate change.
20 As shown in Exhibit 206, weighting customer
21 classes at full marginal cost, in general, lowers the
22 percent increase on high load factor customers (Large
23 General Service, Schedule 19, special contracts). Cost
24 allocations to the residential and irrigation classes are
25 increased slightly. The other classes remain about the
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1 same. This result tends to move the cost of service away
2 from high load factor customers but it does not send a
3 price signal to the residential class which is a maj or
4 cause of the Company's increasing need for capacity.
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1 Q.COULD YOU PLEASE EXPLAIN THE THIRD MODIFICATION YOU
2 ARE RECOMMENDING BE MADE TO THE COST OF SERVICE STUDY
3 PRESENTED BY THE COMPANY?
4 A.On page 5 of his direct testimony Company witness
5 Tatum states,
6 Demand related costs are investments in generation,
7 transmission, and a portion of the distribution
8 plant and the associated operation and maintenance
9 expenses necessary to accommodate the maximum demand
10 imposed on the Company's system. Energy related
11 costs are generally the variable costs associated
12 wi th the operation of the generating plants, such as
13 fuel. However, due to the hydro production
14 capabili ty of the Company, a portion of the hydro
15 and thermal generating plant investment has
16 historically been classified as energy-related.
17 (Tatum, Di. p. 5)
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Q. What did you use as your primary guide in
classifying costs as either customer-, demand-, or
energy related?
A. I used the Electric Utility Cost Allocation
Manual published by the National Association of
Regulatory Utility Commissioners as my primary guide
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1 to the classification of customer-, demand-, and
2 energy-related costs. Cpage 6.)
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4 According to the NARUC Cost Allocation Manual, hydro
5 facili ties are usually treated as capacity. Mr. Tatum is
6 correct that 'traditionally' the Company has treated, and
7 the Commission has accepted, the allocation of the
8 Company's hydro resources to energy. When the Company
9 was energy constrained, rather than capacity constrained,
10 this made sense. However now that Idaho Power is
11 capacity constrained rather than energy
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1 constrained, and it is adding additional resources which
2 reduces its reliance on hydro resources, it now makes
3 sense to allocate its hydro resources more to capacity
4 rather than energy.
5 Q.WHAT is YOUR RECOMMENDATION FOR THE ASSIGNMENT OF
6 HYDRO RESOURCES BETWEEN ENERGY AND CAPACITY?
7 A.A reasonable method of allocating Idaho Power's
8 hydro resources between capacity and energy is to assign
9 75% capacity and 25% energy. This is the allocation used
10 by PacifiCorp in its cost of service study in its last
11 and current rate cases, "Production and transmission
12 plant and non-fuel related expenses are classified as 75
13 percent demand related and 25 percent energy related"
14 CPAC-E-07-05, Rocky Mountain Power, Mark E. Tucker,
15 Di -4). It is my understanding this capacity/energy split
16 was established by the various states served by
17 PacifiCorp.
18 There are a variety of ways hydro facilities can be
19 allocated. These would range from 100% demand related to
some mixture between demand and energy.I believe the
21 allocation of 75% to capacity and 25% to energy is
22 reasonable for hydro plants. The NARUC Cost Allocation
23 Manual states, "Most hydro capacity today is being used
24 for peaking purposes, and its costs therefore are.25 properly classified as demand-related." (Electric Utility
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1 Cost Allocation Manual, NARUC, 1967, footnote page 33.)
2 While the Company has numerous run-of-ri ver facilities
3 the maj or hydro complex is Hells Canyon that Idaho Power
4 uses for peaking.
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1 Q.WHAT is THE RESULT OF YOUR RECOMMENDATION FOR THE
2 ASSIGNMENT OF HYDRO RESOURCES BEING 75% CAPACITY AND 25%
3 ENERGY?
4 A.Exhibit 207 displays the results of allocating the
5 Company's hydro resources 75% to capacity and 25% to
6 energy. This modification produces approximately the
7 same result as reclassifying PURPA proj ects at the system
8 average between capacity and energy. With this change,
9 the revenue requirement for high load factor customers is
10 lowered with the residential class being assigned a
11 slightly higher increase. In addition, as was true with
12 the other two recommended changes, irrigation customers
13 recei ve a higher percent increase.
14 Q. YOU HAVE INDICATED WHAT THE RESULTS ARE FOR EACH OF
15 YOUR THREE RECOMMENDED CHANGES INDEPENDENTLY. WHAT is
16 THE IMPACT I F ALL THREE ARE IMPLEMENTED?
17 A.These results are shown in Exhibit 208. When the
18 three modifications are made simultaneously the high load
19 factor customers revenue deficiency are lowered
20 significantly and the percentage increase for irrigation
21 customers increases slightly from 28.54% to 29.09%. The
22 residential class's revenue deficiency increases by $ 9.3
23 million for a rate increase of 8.52%.
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Q.YOU HAVE DESCRIBED THREE CHANGES TO THE COMPANY'S
COST OF SERVICE METHOD. ARE YOU ADVOCATING THESE CHANGES
BE IMPLEMENTED BY THE COMMISSION?
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1 A. Yes. The modifications I have recommended align
2 cost responsibility more in line with the Company's
3 changing load growth patterns. These changes will also
4 better provide price signals to the customer classes that
5 are creating costs through system load growth. The
6 resul ts of these changes also increase the revenue
7 requirement for the irrigation class only slightly. The
8 irrigation class has the misfortune of having the need
9 for power during summer on peak that is when the
10 Company's system needs are growing the fastest.
11 Irrigation load is not growing. Yet due to increasing
12 residential and commercial demand, their cost allocations
13 are increasing due to their relatively high summer use.
14
15 Reading Test Year Testimony
16
17 Q.Dr. Reading, have you read the testimony and
18 reviewed the exhibits of Company witness Lori Smith?
19 A.Yes. Ms. Smith used the Company's actual financial
20 results for calendar 2007 as a foundation to project the
21 calendar 2008 test year used by Idaho Power for its
22 proposed rates in this case. She develops the 2008
23 forecasted test year by adjusting 2007 values for
24 operating expenses and rate base. Three and five year
25 compound growth rates are used to forecast investments of
2417 Reading, Di 1 7
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1 the Company that are less than $2 million. In addition
2 certain items are annualized as if they were in existence
3 the full test year.
4 Q.Why is the Company using a fully forecasted test
5 year in this case?
6 A.According to Ms. Smith,
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2418 Reading, Di 17 a
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1 In order to meet the legal requirement that rates be
2 fair, just, reasonable, and sufficient, the
3 Commission must establish a test year that most
4 closely reflects the investment and expense levels
5 that will exist at the time new rates are
6 implemented. At this time, the Company believes that
7 a 2008 test year best satisfies that requirement.
8 CSmith Direct, pgs 18,19.)
9 It is understandable why the Company wants rates that
10 most closely match their costs and revenues during the
11 period in which those rates will be in effect.
12 Q.Are you saying you support the utility basing rates
13 on a forecasted test year?
14 A. No. As I stated in my filed testimony in the
15 Company's last rate case CIPC-E-07-08) that I was, and
16 remain, opposed to the forecasted test year for both
17 theoretical and practical reasons:
18 One of the pillars of ratemaking is that ratepayers
19 should only shoulder the burden of 'known and
measurable' costs. Proj ections, by definition, are
a presumption about future events. The standard
approach for a forecasted test year, and the one
used by the Company, is to make proj ections base on
historical data and the adjusted for expected
changes. CReading Direct Testimony, IPC-E-07-07, p.
2419 Reading, Di 18
ICP-E-08-10
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1 5. )
2 In reality the assumptions and projections made by the
3 Company mayor may not in fact come true, yet ratepayers
4 will be paying as if the proj ections were true.
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2420 Reading, Di 18 a
ICP-E-08-10
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1 Q. You said you also have practical reasons for
2 opposing a forecasted test year, could you briefly
3 outline those concerns?
4 A.Yes, in my direct testimony in case IPC-E-07-08 I
5 quoted the well-known regulatory expert James Bonbright:
6 In the first place, the commission's staff must
7 audit the utility's books. For ratemaking purposes,
8 only just and reasonable expenses are allowed; only
9 used and useful property is permitted in the rate
10 base. In the second place, the commission must have
11 a basis for estimating future revenue requirements.
12 This estimate is one of the most difficult problems
13
14
15
16
in a rate case. A commission is setting rates for
the future but it has only past experience
(expenses, revenues, demand conditions) to use as a
guide. C James Bonbright, with Albert Danielsen and
17 David Kamerschen, Principles of Public Utility
18 Rates, 2nd Ed., March, 1988.)
19 I want to complement the Company for its efforts and
20 communication with the Staff and Interveners in the
21 development of the forecasted test year in this case.
22 The Company met with Staff and Interveners in a workshop
23 and outlined their approach. The Company has worked hard
24 to simplify the projection process and explain the
25 foundation and methodologies used to determine the values
2421 Reading, Di 19
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1 in the 2008 test year.
2 Q.Are you saying you support the Company's proj ected
3 2008 test year as filed?
4 A.No, but due the timing of this case I am
5 recommending a procedure that can accomplish some of the
6 goals of the Company and alleviate some of the problems
7 wi th a forecasted
8
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2422 Reading, Di 19a
ICP-E-08-10
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1 test year outlined above.
2 Q.Could you please discuss how you formed your
3 recommendation for dealing with the forecasted test year
4 in this docket?
5 A.This case was filed on June 27, 2008 with the
6 technical hearing set for the end of December 2008. The
7 proposed rate suspension period will end January 27, 2009
8 wi th the Commission able to suspend for an additional 60
9 days for good cause. I, of course, do not know what the
10 Commission will do. However given the timing of the
11 technical hearing the Commission will need some time to
12 decide the case. Therefore it is reasonable to assume
13 the final order would be issued sometime in mid-January.
14 We ask for, and received, in discovery from the Company
15 C Idaho Power Company's Supplemental Response to the First
16 Production Request of the Industrial Customers of Idaho
17 Power, Supplemental Response for Production No.7.) on
18 August 15, 2008 actual financial data for the Company
19 through June 2008 for items they projected using the 3
20 and 5 year compound growth rates.
21 Q.Did you compare the actual first six months data for
22 2008 with the Company's forecast?
23 A.Yes. I used the simplifying assumption of
24 multiplying the six month year-to-date actual values by
25 two and then compared that value to the Company's full
2423 Reading, Di 20
ICP-E-08-10
1 proj ected test year.Exhibi t 209 shows the results of.2 that comparison.As can be seen,some of the estimates
3 appear to be very close while others vary significantly.
4 There can be all kinds of reasons
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2424 Reading,Di 20a
ICP-E-08-10
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1 why the first six months' expenditures and revenues would
2 not exactly match the last half of the year. However,
3 the Exhibit does demonstrate how dramatically projections
4 and actual values can vary.
5 Q.You testified earlier that you have a recommendation
6 that can resolve some of the concerns of the Company as
7 well as the problems you identified with using a
8 proj ected test year. What is your recommendation?
9 A.The Company should file with its rebuttal testimony,
10 which is due on December 3rd, actual results for the
11 first three quarters of 2008. These updated actual
12 resul ts should be used to compare to the proj ected test
13 year calendar 2008. This would give a better indication
14 of how the Company's proj ections are squaring with
15 reality. For those items for which there is a
16 significant difference, the Company could either make
17 adj ustments and/or explain why those discrepancies
18 occurred. Depending on when the Commission issues its
19 final Order, another update could be made with actual
20 data from those additional month (s) that become
21 available. This approach would mean rates would be set
22 using financial data that is closer to actual rather than
23 a full 12 month proj ection.
24 Q.DR. READING HAVE YOU REVIEWED THE TESTIMONY OF MS.
25 MILLER REGARD!NG INCLUDING THE ALLOWANCE FOR FUNDS USED
2425 Reading, Di 21
ICP-E-08-10
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. 25
1 DURING CONSTRUCTION ("AFUDC") COMPONENT OF CONSTRUCTION
2 WORK IN PROGRESS ("CWIP") FOR THE HELLS CANYON
3 RELICENSING PROJECT TO BE INCLUDED IN BASE RATES?
4 A.Yes, I have. I do not believe it is appropriate to
5 include such costs in rates in this
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2426 Reading, Di 21a
ICP-E-08-10
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12
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1 case.
2 Q.WHAT ARE THE PROBLEMS WITH INCLUDING THE AFUDC
3 COMPONENT OF CWIP ASSOCIATED WITH THE HELLS CANYON
4 RELICENSING PROJECT IN BASE RATES?
5 A.This Commission has a long standing precedent to
6 disallow CWIP from rates. Here the Company is asking
7 that the AFUDC component of CWIP be included in base
8 rates. That is short of asking for all of the CWIP
9 associated with this proj ect to be included in base
10 rates, but it is still asking for CWIP to be included in
11 base rates.
Q.WHAT ARE THE PROBLEMS WITH INCLUDING CWIP IN BASE
RATES?
A. Actually the Commission's own orders outline the
15 reasons for disallowing CWIP from rates. In order No.
16 14348 issued in Case No. 1009-96 the Commission made the
17 following declaration:
18 allowing a company to earn a return on construction
19 work in progress destroys the incentive to finish
20 that speedily, puts on the ratepayers a risk which
21 is properly borne by stockholders, and creates a
22 mismatch between those who presently pay and those
23 who, in the future, will benefit from the electric
24
25
plant when it becomes used and useful.The
Commission has made clear its position on this issue
2427 Reading, Di 22
ICP-E-08-10
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in recent orders (citations omitted). We are
steadfastly opposed to the inclusion of CWIP in rate
base. We find that the al ternati ve method of
providing an allowance for funds used during
construction (AFUDC) is just and reasonable and does
not deprive the Company of anything to which it is
entitled. Nothing would be served by further
discussion of this matter. Cat page 6)
2428 Reading, Di 22a
ICP-E-08-10
.
.
.
1 The Commission's rational is as valid today as it was
2 back in 1978.
3 Q.THE COMPANY'S REQUEST is RELATIVELY MODEST IN LIGHT
4 OF THE ENTIRETY OF THE HELLS CANYON RELICENSING COSTS.
5 WHY THE STRONG OPPOSITION?
6 A. Because this is just the tip of the iceberg, if you
7 will. Company policy witness Gale testified that the
8 Company is embarking on a plan of construction proj ects
9 that is only comparable to the time it built the Hells .
10 Canyon Complex. He noted that the Company is planning on
11 spending almost one billion dollars in the near term on
12 construction projects without including the Gateway West
13 Transmission Proj ect or the Hemingway-Boardman line.
14 (Gale Di at page 19.)
15 Q.WOULD NOT SUCH A LARGE CONSTRUCTION PLAN SUGGEST
16 THAT THE COMPANY WILL NEED TO PUT CWI P IN RATES?
17 A.Yes and no.Certainly the Company will raise the
18 argument that putting CWIP in rates reduces future rate
19 increases, generates internal cash flow and reduces the
20 cost of electric plant when it does become used and
21 useful. However, the Company's planned future
22 developments are not certain to come on line and are also
23 not certain to come on line when planned. The risk of
24 failure to develop and the risk of delay is placed
25 entirely on the ratepayer side of the ledger when a
2429 Reading, Di 23
ICP-E-08-10
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15
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1 utili ty is allowed to place CWIP in rates. Idaho has had
2 ambi tious construction plans in the past that have not
3 come on line and the ratepayers were protected from
4 paying the costs of those dry hole prospects.
5 Q.DO YOU HAVE ANY SPECIFIC PROJECTS IN MIND THAT WERE
6 PLANNED BUT NOT CONSTRUCTED?
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13
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19
2430 Reading, Di 23a
ICP-E-08-10
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25
1 A. Certainly. In the early 1990s Idaho Power was
2 actively pursing a maj or transmission proj ect to
3 construct a large transmission line from Southern Idaho
4 to Las Vegas, Nevada. It spent millions of dollars on
5 planning, permitting and engineering that proj ect. It
6 subsequently abandoned the proj ect and only recently sold
7 its rights to build it to a third party. Had it put
8 those costs in rates back in the 1990s those ratepayers
9 would have paid for a proj ect that not only did not
10 benefit them at the time of payment, but did not benefit
11 Idaho Power's, ratepayers at all.That illustrates my
12 concern here.Placing CWIP in rates is simply too
13 speculati ve of a risk to put on the ratepayers.
14 Q. IDAHO POWER'S FUTURE CONSTRUCTION PLANS CALL FOR
15 INCREASING ITS RATEBASE BY A SUBSTANTIAL AMOUNT, WOULD
16 NOT ALLOWING CWI P IN RATES ALLOW IT TO PROCEED WITH LESS
17 COST?
18 A.The unprecedented level of construction spending
19 Idaho Power is planning may call for an unprecedented
20 response. However, simply slipping the precedent of
21 allowing CWIP in rates in this case is not the way to go
22 about fashioning that response.
23 Q.PLEASE EXPLAIN.
A.If all of Idaho Power's planned proj ects come to
fruition, we could easily see a doubling of its rate base
2431 Reading, Di 24
ICP-E-08-10
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1 and unprecedented rate increases for the ratepayers. I
2 understand that Idaho Power may need some assistance from
3 the Commission and the ratepayers in terms of assurance
4 of recovery of its prudently incurred costs and we would
5 be willing to sit down with them to fashion a response
6 short of a blanket granting of CWIP. I don't have any
7 specific suggestions at this time, but would be open to a
8 compromise down the road as these possible construction
9 proj ects become more real.
10 Q.WHAT DO YOU MEAN 'MORE REAL'?
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/
2432 Reading, Di 24 a
ICP-E-08-10
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15
1 A.As the U. S. and, indeed, the global economies
2 currently appear to be hurtling toward a maj or recession,
3 ambi tious construction proj ects that require large
4 quanti ties of debt may be mothballed for reasons other
5 than lack of CWIP in rates. There is a possibility of
6 major loss of load due to the weak economy that would
7 make proceeding with some proj ects less than prudent. As
8 of the time that I am writing this testimony the economy
9 is in one of the most uncertain states I have ever seen
10 it. I don't think now is the time to hard wire CWIP to
11 rates until we have more clarity on each specific project
12 and the costs associated with each specific proj ect.
13 Q. WHAT is THE STATUS OF THE VIRTUAL PEAKING RESOURCE
14 YOU ADDRESSED IN IDAHO POWER'S LAST RATE CASE?
A.I understand that Idaho Power has contacted some
16 entities with emergency back up generators to determine
17 interest in their running in parallel with the Company's
18 system. The Company has also done some very preliminary
19 studies of the costs associated with such a program. I
20 believe they have taken these steps in response to this
21 Commission's urging - although in discussions with
22 Company officials they report that Idaho Power has looked
23 at this sort of a peak shaving program at least ten years
24 ago.
25 Q.WHAT HAS, THE COMPANY LEARNED FROM ITS STUDIES AND
2433 Reading, Di 25
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1 DISCUSSIONS?
2 A.I believe the Company learned what it set out to
3 learn.
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2434 Reading, Di 25a
ICP-E-08- 10
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1 Q.PLEASE EXPLAIN.
2 A.The Company has been, to say the least, less than
3 enthusiastic about implementing a shared interest in
4 customer owned generation for purposes of meeting peak or
5 providing stand-by reserves. Why, I do not know. We can
6 speculate as to the reason for its lukewarm response to
7 the possibility of creating a virtual peaking unit at its
8 load center, but that would not be productive at this
9 juncture. I believe the Company's lack of enthusiasm for
10 the program was a large driver in its conclusions that
11 energy from such a program would be much more expensive
12 than building new gas fired peaking units. It did
13 conclude, however, that capacity would be much less
14 expensive.
15 Q.is THE FACT THAT ENERGY FROM A VIRTUAL PEAKING
16 PROGRA is MORE EXPENSIVE THAN FROM A TRADITIONAL GAS
1 7 PEAKER A FATAL FLAW?
18 A.Apparently from the Company's viewpoint it is.
19 Although, with its casual approach to this program, we
20 can conclude that creativity was not encouraged within
21 the Company's team that was looking into the possibility
22 of a virtual peaking program.
23 Q.PLEASE EXPLAIN.
24
25
2435 Reading, Di 26
ICP-E-08-10
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1 A. The reason energy from customer owned back up
2 generation is so much more expensive than energy from the
3 company's own gas fire peakers, is because the Company
4 assumed diesel fuel would be used in the customer owned
5 uni ts. The Company failed to explore ways to work with
6 new customers prior to installation of back up generation
7 to have those generators connect to the gas line rather
8 than building diesel generators. If that were done, the
9 cost of energy for the back up generators would equal the
10 cost of energy for the Company owned generators, while
11 the cost of capacity would be a fraction of the cost of
12 capaci ty from the Company's plants. Also using gas
13 eliminates most environmental concerns and dramatically
14 reduces the additional expense of the interconnection.
15 Q.SO ARE YOU SUGGESTING THE COMPANY BE DIRECTED TO
16 IMPLEMENT A VIRTUAL PEAKING PLANT PROGRAM FOR NEW
17 INSTALLATIONS?
18 A.Yes. On a going forward basis the Company should be
19 directed to exercise its best efforts to work with its
20 customers who are installing new customer-owned back up
21 generation to enlist them in the virtual peaking program.
22 If the Company, which had looked at this type of a
23 program at least ten years ago, had implemented it then,
24 I am sure it would now have a valuable addition to its
25 arsenal for meeting that very expensive summer peak.
2436 Reading, Di 27
ICP-E-08-10
1 Q.ARE THERE OTHER UTILITIES THAT HAVE IMPLEMENTED.2 PROGRAS THAT GRADUALLY REDUCE THEIR SYSTEM PEAK?
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2437 Reading,Di 27a
ICP-E-08-10
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1 A.Interestingly, and unexpectedly, one only need to
2 look at United Water to find an example of a reluctant
3 utili ty that was required to implement a successful peak
4 shaving program. This Commission initiated the concept
5 of requiring United Water (then Boise Water) to encourage
6 the installation of dual irrigation systems in those new
7 subdivisions where irrigation surface water was
8 available. The tool the Commission used was a puni ti ve
9 hook-up fee for customers who did not comply. Al though
10 the regulatory tool ran afoul of the prohibition against
11 discriminatory rates - Boise City picked up the ball and
12 made such a program mandatory through its zoning
13 regulations. As a result of this Commission's
14 ini tiati ve, Uhi ted Water's summer peak is much less now
15 than it would have been without dual irrigation systems
16 being installed as a matter of course.
17 Q.WHAT is THE LESSON TO BE LEARNED FROM THE BOISE
18 WATER EXPERIENCE?
19 A.Utilities have an incentive to build and own their
20 own resources. Programs that reduce their ability to
21 build new plant (gas fired peakers or surface water
22 treatment plants) reduce their ability to add to
23 stockholder value. However, that also creates a tension
24 between the customer's goal of having rates as low as
25 possible. Here i believe Idaho Power has been caught up
2438 Reading, Di 28
ICP-E-08-10
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1 at the intersection of those two competing interests.
2 The lesson to be learned is that the virtual peaking
3 program can clearly be part of the solution, but only if
4 this Commission wants it to be, because Idaho Power is
5 obviously not going to take the ini tiati ve.
6
7 /
8
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2439 Reading, Di 28a
ICP-E-08-10
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1 Q.DOES
2 A.Yes.
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THIS END YOUR TESTIMONY AS OF OCTOBER 24, 2008?
2440 Reading, Di 29
ICP-E-08-10
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18
1 INTRODUCTION
2 Q.Are you the same Don Reading who filed Direct
3 Testimony in Case IPC-E-08-10?
4 A.Yes.
5 Q.What is the purpose of your rebuttal testimony in
6 this Docket?
7 A.I discuss statements made by Staff witness Hessing
8 dealing with changes in the cost-of-service (COS)
9 methodology that have occurred since the Company's
10 IPC-E-03-13 general rate case and the current Docket. I
11 also discuss the cost-of-service studies that were filed
12 in Direct Testimony and my understanding of the Staff's
13 Rebuttal filing.
14 Keith Hessing
15 Q.You state that you have comments over a point put
16 forward by Staff witness Hessing in his Direct Testimony.
17 What is the issue you address?
A.As I discussed in my Direct Testimony, there have
19 been dramatic shifts in the costs of capacity and energy
20 for the Company in the 5 years since general rate case
21 IPC-E-03-13 was filed by the Company. The growth in
22 system load over this time period has come primarily from
23 the residential class while the high load factor classes
24 and the irrigation class have experienced little or no
25 growth. The growth in the residential class load has
2441 Reading, Reb 2
ICP-E-08-10
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20
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25
1 caused the Company to experience pressure on capacity
2 resources. In response, the Company has built 250 MW in
3 gas peaking units in the past few years. In spite of the
4 increased costs to serve the growing residential load,
5 the Company's cost-of-service studies have displayed
6 paradoxical and counterintuitive results.
7 Q.What paradoxical and counterintui ti ve results are
8 the Company's cost-of-service studies showing?
9 They assign disproportional rate increases to
10 high load factor customers, and significantly lower
11 percentage increases to the residential class.
12 Q.What did Mr. Hessing have to say about these
13 counterintui ti ve results from the
14
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2442 Reading, Reb 2a
ICP-E-08-10
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1 Company's COS filings since IPE-E-03-13?
2 A.Mr. Hessing frames the issue by saying:
3 There are a number of circumstances that have
caused changes in cost of service results. Load
growth, substantially in the residential class,
has occurred in record amounts. The cost of
power supply to meet the growing load, at
approximately 6ç/kWh, has been much higher
than it used to be. Under cost of service
methodology a disproportionately larger share
of all costs, old and new, are allocated to the
residential class because the residential
classes percentage share of energy, peak demand
and customers has increased. A mix of old and
new costs is also allocated to all other
classes even if they experienced no load
growth. No customer class is entitled
to rates based on a grandfathered share of old
costs. In the cost of service model the
residential class received credit for all of
the revenue from its load growth at near
6ç /kWh and a portion of the production cost
increases at about the same rate. In the cost
of service study the increased revenues offset
the increased costs and the Residential Class
is shown to deserve an increase below the
Idaho Jurisdictional average, or even a
decrease as demonstrated in Staff's results.
High load factor customer groups are situated
differently. They are allocated a reduced
portion of all costs, old and new, and have
li ttle or no new revenue to offset the new
costs. The new costs more than offset the
cost reduction due to the decrease in the
allocation percentages and without additional
revenue rates go up. Therefore, cost of serviceresul ts indicate increases higher than the
average. CHessing Direct Testimony, pgs. 9-11.)
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22 Mr. Hessing goes on to say that because high load factor
23 customers pay about 3ç/kWh and residential customers pay
24 approximately 6ç/kWh, residential customers' contribution
25 to revenue, on a per kWh basis, is double that of high
2443 Reading, Reb 3
ICP-E-08-10
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1 load factor customers. This leads him to the conclusion
2 that higher percent increases for high load factor
3 customers follows naturally because they cover such a
4 smaller share of the marginal cost of power on a kWh
5 basis.
6 Q.Do you agree with Mr. Hessing's analysis?
7
8 A.Only half way. While Mr. Hessing is correct that
9 residential customers do contribute, on
10
11 /
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2444 Reading, Reb 3a
ICP-E-08-10
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1 a kWh basis, about double the revenue of high load factor
2 customers, his analysis looks at only the revenue side of
3 the cost-of-service equation. There is a reason that
4 residential customers pay about double the amount that
5 high load factor customers pay. The reason is that the
6 residential class imposes -- again on a per kWh basis --
7 about double the costs on the system than do high load
8 factor customers. The reason for these higher costs on a
9 per kWh basis are many, and include such factors as the
10 relatively poor load factor of the class, higher
11 distribution costs, and much higher administrative costs.
12 Q.Is it appropriate to only look at revenue in a cost
13 of service analysis?
14 No. Cost of service calculations include both
15 customer class costs and revenues.Considering only
16 revenue and ignoring costs is like trying to cut paper
17 wi th a one blàded scissor. You need to consider both the
18 cost and revenue blades in order to assign proper rate
19 responsibili ty for customer classes and in order to get
20 the rate assignment job done accurately. Therefore, Mr.
21 Hessing's example only provides part of the explanation
22 for the paradoxical results of the Company's recent COS.
23 For the reasons stated above, however, it does not
24 provide a complete explanation.
25 Cost-of-Service
2445 Reading, Reb 4
ICP-E-08-10
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15
1 Q.You recommend some changes to the cost-of-service
2 testimony filed by the Company in your Direct Testimony.
3 Didn't you state a cause of the shift of cost
4 responsibili ty from residential and small commercial
5 customer to high load factor customers was a
6 methodological change in the calculation of coincident
7 peak recommend by attendees in the COS workshops?
8 A.Yes, in my Direct Testimony I state:
9
10
Rather than using the median values for the
system coincident demand factors I
substituted in the 2007 values and ran the
3CP /12 CP model with no other changes. Use of
2007 system coincident demand factors, rather
tha~ the five year median values, produced some
significant shifts among some customer classes.
In general there was a shift of costs away from
the higher load factor customer classes to the
lower load factor classes. C Direct Testimony,
Don Reading, Cp. 10.)
11
12
13
14
16 I present cost-of-service results with this change and
17 state:
18 The Company's Cost of Service method requires
several steps of transferring
19
20
21 /
22
23 /
24
25 /
2446 Reading, Reb 4 a
ICP-E-08- 10
.
.
.
1
2
large amounts of data to make this change. We
are working with the Company to verify these
steps have been made correctly. To the extent
the results presented here vary from the
Company's, we will adopt the Company's
verification of these results and file revised
exhibits. Cp. 11.)
3
4
5
6 It is my understanding that the Company and Commission
7 Staff have worked together to verify the results I
8 testified to in my direct testimony. I also understand
9 that, as a result, Mr. Hessing has accepted the change in
10 the cost-of-service methodology that substitutes the 2007
11 values for the system coincident demand factors for the
12 median values of the past 5 years. I agree with this
13 change and anticipate that Mr. Hessing's rebuttal
14 testimony will confirm it as well. The rationale for
15 this change is detailed in my Direct Testimony, and need
16 not be repeated here. I also stated in my Direct
17 Testimony that it would be worthwhile for the Company,
18 Staff, and interveners to work together to arrive at an
19 acceptable methodology to 'normalize' peak demand in the
20 cost-of-service studies.
21 Q.Does this conclude your Rebuttal Testimony on
22 December 3, 2008?
23
24
25
A.Yes, it does.
2447 Reading, Reb 5
ICP-E-08-10
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 MR. RICHARDSON: Madam Chairman, with your
4 indulgence, may I inquire of a couple of issues with Dr.
5 Reading before we submit him to cross-examination?
6 COMMISSIONER SMITH: Yes.
7
8 DIRECT EXAMINATION
9
10 BY MR. RICHARDSON:
11 Q Dr. Reading, were you in the room
12 yesterday when Dr. Goins recommended a uniform percent
13 increase across the board in this matter?
14 A Yes, I was.
15 Q And do you have any response to that
16 suggestion by'Dr. Goins?
17 A Yes, I'm supportive of that. I'm
18 struggling with how much to explain my answer and how
19 much the Commission has heard all the answers, so yes, I
20 support it for a variety of reasons, many of which have
21 been expressed and some which haven't and would be glad
22 to enumerate if someone would like to ask me why I
23 support it.
24
25
Q What about his recommendation to have an
independent third party assist the Commission and the
CSB REPORTING
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2448 READING (Di)
ICIP
.
.
.
17
18
19
20
1 other parties in devising or examining cost of service
2 issues?
3 A I also agree with that and both Dr. Goins
4 and Dr. Peseau explained their reasons. Again, the
5 maj ori ty, I mean, I agree with all those reasons they
6 gave and, again, I would be happy to elaborate.
7 MR. RICHARDSON: Thank you, Dr. Reading.
8 Madam Chair, Dr. Reading is now available for
9 cross-examination.
10 COMMISSIONER SMITH: Thank you very much.
11 Mr. Boehm, do you have questions?
12 MR. BOEHM: No questions, Your Honor.
13 COMMISSIONER SMITH: Mr. Bruder.
14 MR. BRUDER: No questions, Your Honor.
15 COMMISSIONER SMITH: Mr. Purdy.
16 MR. PURDY: No questions.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Ward.
MR. WARD: Well, your counsel asked the
21 two I was goihg to as k, so I've got no questions.
22
23
24
25
COMMISSIONER SMITH: Okay, Mr. Price.
MR. PRICE: No questions.
COMMISSIONER SMITH: Mr. Walker.
MR. WALKER: Only about five pages. I
CSB REPORTING
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2449 READING (Di)
ICIP
.
.
.
20
1 only have a few areas.
2
3 CROSS-EXAMINATION
4
5 BY MR. WALKER:
6 Q Mr. Reading, in your direct testimony on
7 page 22 is generally where you start your discussion
8 about CWIP and it kind of starts off by saying, and I
9 think this is consistent with the presentation by your
10 counsel throughout the hearing, that the Commission has
11 this longstanding precedent to disallow CWIP from rates.
12 Could you teii us what you define as "precedent"?
13 A Oh, precedent would be what the Commission
14 in the past has opined on what they feel their opinion of
15 what CWIP is and how it relates to the public interest
16 and so the best way I thought to do that was to go
17 through past Orders and quote from those past Orders what
18 the Commission expressed about its attitudes toward
19 CWIP.
Q And are you familiar with the term stare
21 decisis?
22
23
24
25
MR. RICHARDSON: Objection.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Stare decisis is a legal
concept and Dr. Reading is here as an economist, not a
CSB REPORTING
[phone]
2450 READING (X)
ICIP
.
.
.
18
1 lawyer.
2 COMMISSIONER SMITH: Mr. Walker.
3 MR. WALKER: Certainly, I think he can
4 testify to his own knowledge and understanding of what
5 that term means.
6 MR. RICHARDSON: That term doesn't even
7 appear in his testimony.
8 COMMISSIONER SMITH: It is a legal term.
9 Do you have a different way you could ask him?
10 MR. WALKER: I'll try.
11 COMMISSIONER SMITH: Thank you.
12 Q BY MR. WALKER: Do you have an
13 understanding as to whether precedent as you have just
14 defined it is binding upon this Commission?
15 MR. RICHARDSON: Objection for the same
16 reason.
17 COMMISSIONER SMITH: Mr. Walker.
MR. WALKER: I think given Mr. Reading's
19 Exhibit No., as shown in his Exhibit No., 201, his very
20 impressive resume of experience in this industry,
21 including a time from '81 to '86, which was a very
22 relevant time period that we're discussing about CWIP
23 COMMISSIONER SMITH: Why don't you just
24 ask him if the Commission can change its mind.
25 Q BY MR. WALKER: Dr. Reading, could the
CSB REPORTING
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2451 READING (X)
ICIP
.
.
.
1 Commission change its mind from that precedent?
2 A To cut to the chase, certainly.
3 Q Thank you. Now, also on page 22, starting
4 on line 15, you have a quote from one of those previous
5 Orders that lays out three basic premises that the
6 Commission stated at least in that Order about CWIP. Do
7 you see that from line 15 through line 18?
8 A On which page?
9 Q On page 22.
10 A Yes.
11 Q Where allowing a company to earn a return
12 on construction work in progress destroys the incentive
13 to finish that speedily, puts the ratepayers at risk
14 which is properly borne by stockholders, and creates a
15 mismatch between those who presently pay and those who,
16 in the future, will benefit from the electric plant when
17 it becomes used and useful. Do you think those three
18 cri teria are equally applicable to the Company's present
19 request as they are to, say, construction of a nuclear
20 plant?
21 A Yes, and I would like to explain my answer
22 and that is one of the things that I see with CWIP in
23 this case, and I'll put a footnote and Mr. Gale can
24 respond when he's on the stand where he says Dr. Peseau
25 and I just slammed the door and say, you know, hell no,
CSB REPORTING
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2452 READING (X)
ICIP
.
.
.
1 we won't go, no CWIP, zero, which is not a proper
2 interpretation of what I believe was in my testimony and
3 not what I heard Dr. Peseau say on the stand. Where I
4 see the disconnect in CWIP in this case and the reason
5 that I quoted Commission Orders of the past is Staff has
6 a position that well, Hells Canyon is different. Hells
7 Canyon is a resource that is up and used and useful and
8 still functioning and it's got all of these really
9 special conditions around it, so okay.
10 On the other hand, when I read the
11 Company's testimony, Mr. Gale's primarily, and I'd like
12 to compliment him for being candid in it, it's obvious
13 that they see CWIP, and to paraphrase it, as a tool and
14 if I misrepresent Mr. Gale, he's coming on the stand
15 after and can correct it, they're saying we've got these
16 big multi-year expensive projects coming down the road
17 and so we're taking a little bite out of the apple.
18 We're only asking for a little. We're only asking in a
19 special situation, but it's obvious, at least to me, that
20 they're saying we would like to open the door on CWIP, so
21 on the one hand, I look at Commission precedent as I
22 define it and they are saying on its face, CWIP is not in
23 the public interest.
24 I see the Company, on the other hand,
25 looking at CWIP and saying on its face, CWIP is in the
CSB REPORTING
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2453 READING (X)
ICIP
.
.
.
1 public interest and when I my non-lawyer economist eyes
2 read the recently passed legislation, it struck extreme
3 emergency and inserted explicit, so now rather than
4 saying the Commission can only give CWIP in an extreme
5 emergency and find it in the public interest, now the
6 Commission sh9Uld find it explicitly in the public
7 interest, so to me, because I agree with the Commission's
8 past Orders that CWIP on its face is not in the public
9 interest, and that's why I quoted those past Orders and I
10 see that stacked up against what I see in the Company
11 that CWIP is in the public interest, then that's why I
12 look at this particular case and say I don't think what
13 they're asking for in CWIP in this particular case is in
14 the public interest and I don't think that -- I could not
15 make a finding that it is explicitly in the public
16 interest.
17 Q Certainly, you would have no quarrel with
18 the statement given the change in the legislation that
19 it's within the discretion of the Commission to look at
20 an individual situation and make the determination of
21 whether CWIP would be appropriate in that individual
22 case; isn't that correct?
23
24
25
A Absolutely correct, yes.
Q So your testimony should not be
interpreted to mean that CWIP should never be included in
CSB REPORTING
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2454 READING (X)
ICIP
.
.
.
1 rates?
2 A Yes, and that I agree. Never -- I sound
3 like a politician. Never say never. It's how high you
4 want to put the bar, okay, and I obviously along with
5 Dr. Peseau put the bar significantly higher than the
6 Staff puts it here or the Company puts it down here. One
7 of my fears is if the Commission finds for CWIP in this
8 case without using a lot of, you know, tried things, you
9 know, the camel's nose is under the tent, et cetera, that
10 once that door is open and you say okay for this one,
11 then that makes future arguments easier to use by taking
12 whatever the Commission would say in allowing CWIP in
13 this particular case and saying well, how is this
14 different, and let me use one example. You asked the
15 question.
16 Let's say okay, used and useful, this is
17 one of the pins, we're going to get some kind of a carbon
18 tax, some kind of a carbon restriction, whatever is
19 coming down the road, that's obvious, so let's say that
20 happens to be a very, very high number, so the Company
21 has one of its coal resources and it says gosh, I'm going
22 to have to pay "Z" millions of dollars in carbon tax or I
23 could spend "Y" millions of dollars which is less than
24 "Z" to put scrubbers or put things in, et cetera, okay?
25 Come back to the Commission and say we want CWIP for
CSB REPORTING
[phone]
2455 READING (X)
ICIP
.
.
.
1 this. Well, why do you think you should have CWIP for
2 this one? Well, you gave it to us before because it was
3 used and useful. I could go on and on and on, but that's
4 one of my fears and I don't see that level of explicit
5 need or reason to overcome what I believe is CWIP being
6 used for the public interest and what I see in past
7 Orders.
8 Q But certainly, some fear of setting a
9 precedent shouldn't preclude a case like this where the
10 Company would bring a specific proposal before the
11 Commission to enable it to exercise that discretion given
12 to it by the legislature and make a determination about
13 whether it's appropriate in that case?
14 A Not to presuppose -- I'm trying to do this
15 tactfully. I am not a commissioner. I certainly assume
16 I never will be a commissioner, but if I were a
17 commissioner, that would be part of my decision matrix.
18 I would worry about what decisions I make today and what
19 potential precedent that may set for future decisions.
20 I'm on several boards and when consumer complaints or
21 complaints come before them, that's one thing we always
22 look at.
23
24
25
MR. WALKER: No further questions.
COMMISSIONER SMITH: Do we have any
questions from the Commission? Commissioner Kempton.
CSB REPORTING
[phone]
2456 READING (X)
ICIP
.
.
.
1
2
EXAMINATION
3 BY COMMISSIONER KEMPTON:
4 Q Madam Chair, did you participate in the
5 hearings on the Bill when this was before the Idaho
6 legislature?
7 A No, I didn't. To be perfectly honest, I
8 didn't know it had even passed until I read this case.
9 Q But I would expect that you would agree
10 that there was probably significant discussion on just
11 the very aspects of issues that you are describing now,
12 wouldn't you?
13 A I would hope that would have been the
16 his nose under the tent would have been heard because
And I'm sure that term of the camel poking
14 case.
17 that may be a trite term, but it's used consistently in
15 Q
18 the legislature --
19
20
21
22
A
Q
A
Q
Yes.
-- I assure you, having been there.
Yes.
So what the legislature has done is to
23 give the PUC, they've expressed a confidence that the PUC
24 will look at the same things that may be expressed in the
25 legislati ve intent in that Bill and I haven't checked
CSB REPORTING
[phone]
2457 READING (Com)
ICIP
.
.
.
1 that, but I'll tell you right now that I will, if there
2 are guidelines there, they would expect us to follow
3 those and if there aren't guidelines there, they would
4 expect the Commission to not engage in falling in making
5 their first selections. Would you agree that there is a
6 process that can be followed with the Commission
7 recognizing the inherent dangers that you've expressed
8 and that the Commission can move forward slowly,
9 cautiously and recognizing that the nose of the camel is
10 still present make decisions that can work in this rate
11 case as a test and actually would be subj ect to
12 legislati ve review before the next rate case comes?
13 A Yes, Commissioner Kempton, I would have to
14 agree with you, that certainly is wi thin the purview of
15 the Commission and I'm sure that's why the legislature
16 said explicit. Even though it didn't define that, it
17 gave those parameters. I can't restrain myself here, I
18 guess. My response to one of the questions that I
19 believe Mr. Kline asked about CWIP and that was something
20 about well, you mean you're saying the legislature
21 hasn't -- you know, sort of like you're opposing the
22 legislature, my immediate reaction was which legislature
23 are you talking about, because I was around when the
24 legislature in 1984, in 1984 passed the restriction on
25 CWIP, and so I'd like to take just a minute on that
CSB REPORTING
[phone]
2458 READING (Com)
ICIP
.
.
.
1 history so you'll understand a little better where I'm
2 coming from and that is, I believe it was Utah Power &
3 Light and they had a 52 percent rate increase they put on
4 the table of which I don't think it was quite half, but
5 about half of it was CWIP and the Commission didn't give
6 it to them.
7 It got hauled to the Supreme Court. The
8 Supreme Court said no, you've got to give it to them and
9 the legislature looked at that and said that is a very
10 bad thing and we need to do something about it and so
11 they passed the law in '84 that this law amends, so where
12 I'm coming from and what I tried to do in my testimony
13 and what I'm saying is when I see where Dr. Peseau and I
14 both put the bars very high, we're saying that's what
15 we're concerned with and what we're trying to inform the
16 Commission about and I would agree with you and Mr.
17 Walker that you have the discretion to do with it
18 whatever you will do with it, that's up to you and the
19 legislature. The PUC being a creature of the
20 legislature, they gave you the authority to be the watch
21 dogs or regulators in this case.
22 Q Thank you, Mr. Reading, and I would only
23 add to your comments that time marches on and that's the
24 reason stare decisis exists and I know that you
25 understand that.
CSB REPORTING
[phone]
2459 READING (Com)
ICIP
.
.
.
19
1 A Yes.
2 COMMISSIONER KEMPTON: Thank you.
3 COMMISSIONER SMITH: Do you have
4 questions?
5 COMMISSIONER REDFORD: Yes, I do.
6
7 EXAMINATION
8
9 BY COMMISSIONER REDFORD:
10 Q It seems to me, Doctor, that you and
11 Dr. Peseau are being very conservative in your
12 discussions of CWIP. Also in the 1984 year that the
13 legislature imposed that, I think we had just gone
14 through WPPSS and other things and I believe that there
15 were some things in Idaho that were at first required, as
16 they were the owners were required, to come up with their
17 share of the losses which were enormous.
18 A That is true, yes.
Q So I think during that period of time
20 everyone was pretty gun shy. I must tell you that I do
21 see an economic benefit to ratepayers from the standpoint
22 that sometimes when you're negotiating your construction
23 loan or so on, if you can demonstrate that you have the
24 method, means and ability to repay the loans, sometimes
25 you can negotiate a cheaper rate and I hate to keep going
CSB REPORTING
[phone]
2460 READING (Com)
ICIP
.
.
.
1 on like this, but I think I need to for my questions. Is
2 it your understanding that Idaho Power does speculative
3 construction for transmission, power, whatever?
4 A I need you define before I can answer what
5 you mean by "speculative" and that is they spend the
6 money for a particular proj ect under the assumption they
7 will eventually get it in rate base?
8 Q Yes.
9 A Okay, yes, they do.
10 Q Okay, and when Idaho Power is proposing to
11 undertake a new plant or transmission line, they
12 generally come to us for a certificate of public
13 convenience and necessity.
14 A Yes.
15 Q i need to explore a little more my
16 statements. I have often heard it said that well,
17 really, that just because Idaho Power is regulated,
18 owners of proj ects, you know, they have to borrow the
19 money and once they've borrowed the money, they have to
20 wai t until the facility, I would say abuilding, is
21 occupied before they can start recovering their
22 revenue
23
24
25
A Correct.
Q -- or payment. That doesn't compute with
me very much because, first of all, many types of
CSB REPORTING
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2461 READING (Com)
ICIP
.
.
.
17
18
19
1 contracts provide for advance payments and also provide
2 for advanced funding from the owner. In those cases, I
3 can see that there is a direct benefit to the customers
4 because it kind of starts to smooth out the load. Gi ven
5 what I've said, I would appreciate your response. If I
6 haven't made myself clear, I would like you to correct
7 me. Just having the rule that we just never allow CWIP
8 seems to me to be extremely conservative and not very
9 practical. I~m sure you've heard those arguments before.
10 A Yes.
11 Q Would you like to respond to what I've
12 said, especially in the area that it smooths out the load
13 or the rates?,
14 A Certainly, and not to be argumentative to
15 a Commissioner
16 Q Please be.
A Okay.
Q I'm into it.
A I guess I have two responses to that. The
20 first is I would agree -- maybe three responses, I
21 think that I would certainly agree with you that it's
22 very conservative and I think as you read my testimony
23 and look at the past Commission, you know, they viewed it
24 as very conservative. I agree with you with the analogy
25 that the Company needs to go out and borrow funds to
CSB REPORTING
[phone]
2462 READING (Com)
ICIP
.
.
.
1 complete proj ects of long duration. My biggest problem
2 wi th that is as a ratepayer, I don't want to be their
3 bank. I don't want them to borrow it from me and that's
4 kind of the view I have on it and that is is they're
5 using my money.
6 Now, it means that when the proj ect comes
7 on line, the payment stream is smoothed and I think
8 that's an important pin that the Commission has to look
9 at and I haven't heard it in this particular case, but
10 rate shock. Rate shock is always a thing, an item that
11 the Commission needs to look at and I know that over
12 time, a lot of years in here the Company is concerned
13 wi th rate shock. They don't like rate shock either, so I
14 guess the quickest answer I can have and I'll use an
15 analogy is I don't feel like I'm in a position to be
16 loaning them the money.
1 7 They can borrow money cheaper than I can
18 most of the time and it's like if I'm having a house
19 built for me ~nd the bank is distributing the funds, I
20 could certainly go to that bank and say, hey, I want to
21 pay some of the AFUDC equivalent. I want to pay the
22 interest, you know, that's in that interim and then gosh,
23 I've a really good deal at the end of the road, my house
24 costs less.
25 Well, it really doesn't cost less to me
CSB REPORTING
[phone]
2463 READING (Com)
ICIP
.
.
.
1 because I paid for part of it during the construction and
2 then I paid a lesser amount, that's true, but I still
3 paid the full boat, so that, Commissioner, is sort of
4 where my mind set is.
5 Q I understand it and I guess I partially
6 agree to that, but, you know, if you take a typical
7 construction proj ect and if you're building a generation
8 facili ty, there are a lot of long lead items. You have
9 to buy a lot of things, generators, boilers, all the
10 various things that go with it and you must put that
11 money out right away to its vendors and so having said
12 that, it just seems to me like other than the argument
13 why should I pay for the Company's construction up front,
14 it just seems to me if you're talking about risk, that's
15 not much of a risk to the ratepayer so long as the
16 project is completed.
17 I think that it has customer benefit
18 because I think, one, you avoid the rate shock, two,
19 you're incentivizing the Company to construct the
20 facility and also construct it on time and within the
21 budget and it, just seems to me that given the knowledge
22 of the Commission and the Commission Staff, a lot of the
23 concerns are resolved up front when they ask for a
24 certificate of public convenience and necessity and I
25 think it shortchanges the Commission a little bit from
CSB REPORTING
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2464 READING (Com)
ICIP
.
.
.
1 determining one, that there's a need, demand and that
2 they, the facility is going to be constructed and it's
3 used and useful. I do agree with you that probably in
4 the situation where a coal-fired plant was being
5 envisioned that we would probably say no, given the
6 technology or the lack of technology in the coal-fired
7 plants, that probably that's not a good investment.
8 If you're talking about large construction
9 loss, those things are all generally insured, so I don't
10 see much of a risk to the ratepayer other than you're
11 concerned that I am paying up front for something -- I'm
12 financing the project. You're really not financing the
13 proj ect because the Company is still going to have to get
14 its construction loans and it's going to have to then
15 convert it to long-term financing and so on, so does
16 anything I've said encourage you to think that maybe used
17 in the proper and considered method that the Commission
18 would employ that would stop us from saying sure, let us
19 help, let the ratepayers help you?
20 A Again, with all due respect, Commissioner
21 Redford, it's a -- and that's true, you know, with the
22 Commission and all the experts, we're in a balancing act
23 here where you have to weigh many factors and in my
24 opinion, as I said, I haven't drawn a line in the sand in
25 saying CWIP should never be used. I'm taking from what I
CSB REPORTING
[phone]
2465 READING (Com)
ICIP
.
.
.
1 hear you saying a more conservative approach and the more
2 conservati ve approach, and no sense going through them,
3 they're articulated in those past Orders. Gi ven that
4 balancing act, I do not see CWIP in this case, is in this
5 instance for a piece of interest for the Hells Canyon
6 relicensing. It doesn't meet my bar and, therefore, I
7 would still gi ven your articulate comments, you have
8 not changed my mind.
9 COMMISSIONER REDFORD: Okay. Well, from
10 my standpoint, it would appear that the Hells Canyon
11 proj ect would probably be at the low end of the risk, so
12 I guess we agree to disagree. Thank you, sir.
13 THE WITNESS: Okay, thank you.
14
15 EXAMINATION
16
17 BY COMMISSIONER SMITH:
18 Q Well, Dr. Reading, the CWIP horse has been
19 pretty much beaten to death, but I'll just ask one final
20 question after hearing you passionately state your
21 opinion and that is has the Commission disagreed with
22 your opinion in the past?
23 A Gosh, Commissioner Smith, let's see, I
24 have to throw in they've even disagreed in the past when
25 you and I were on the same case and you were an attorney
CSB REPORTING
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2466 READING (Com)
ICIP
.
.
.
1 and we were taking the same position.
2 Q Sad but true, so let's turn to, I guess,
3 what I think is the real serious issue and that is cost
4 of service.
5 A Yes.
6 Q What are we going to do with that? We
7 weren't happy in '03, nobody was happy, but, of course,
8 probably from the beginning of time nobody has been happy
9 with cost of service, but where do we go now? It occurs
10 to me that given the report on the workshops and the
11 meetings that were held that this could have evolved to
12 the state where I concluded about a dozen years ago the
13 telecommunication industry was. You know, you get them
14 together, the same parties, and in most cases the same
15 people, have been fighting for so long that if one said
16 black, the other said white and no progress whatsoever
17 could ever be made, so I don't know if we're here with
18 this issue and if so, I just don't know where to go from
19 here and if you think there is such a person as a
20 disinterested third party who could do it without a bias,
21 then I'd be interested to know about that because I don't
22 think there probably is one.
23 A Commissioner Smith, I don't know where
24 else to go and at the wrath of the audience here because
25 I'm the last witness and not taking too long, I think
CSB REPORTING
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2467 READING (Com)
ICIP
.
.
.
1 what's happened with the cost of service, the last one
2 that was approved in -- well, let me really do history.
3 The methodology that was developed for the cost of
4 interest -- cost of service, rendering Mr. Kline brain
5 dead period here the cost of service was my old boss
6 here in '82, '83 Dr. Willmorth and he put it together
7 when the Company was energy constrained and not capacity
8 constrained and it was very unique among utili ties around
9 the country in that it had a significant portion of
10 hydro, you know, much higher, and it also had a
11 significant P9rtion of irrigation load and what's
12 happened -- and it had no peaking units, it didn't need
13 peaking units because it could -- well, it had the Sun
14 Valley diesel or something to close a loop, but it had no
15 meaningful peaking unit, and as I have gone around the
16 country in other jurisdictions, that was almost unheard
17 of, a utility that was in that situation.
18 Well, what's happened is over time this
19 engine or this Model T Ford or whatever it is, the cost
20 of service study put together worked very well for that.
21 Well, lots of things have changed. The system has grown.
22 It's gone from energy to capacity constrained. It has a
23 significant irrigation load and it's really too bad Idaho
24 Power isn't a' winter peaker and a big part of our
25 problems would go away, and I don't know of a utility in
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1 the country that has the uniquenesses of its generation
2 facili ties and its load with such a big piece of
3 irrigation.
4 There's lots of smaller utilities that are
5 kind of irrigation utili ties, but a general service
6 utili ty, I don't know of any other in the country that
7 has that big a piece of irrigation load, and what we've
8 tried to do over time by patch and scratch and fix and
9 fix and fix and fix and I think we've gotten to the point
10 where it's time to trade that old truck in because it
11 just isn't doing its job even though we poured a ton of
12 money into it and we need to start over with a new model.
13 The thought occurred to me when I was
14 listening to Dr. Goins and he was saying I've never seen
15 this and I've never seen this, well, if you looked at
16 1982 when the model was put together and approved by the
17 Commission and went through all that and you hauled that
18 to other jurisdictions, no other jurisdictions saw
19 anything like that, so I think due to what's happened to
20 the service territory, the way it's grown, the
21 uniquenesses öf the load, the change in the resource
22 stack of the Company, it's time for somebody with a new
23 set of eyes to come in and say, okay, let's throw it in
24 the trash can and let's start from the beginning. Maybe
25 not in the trash can, you've got to use the old one and
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1 maybe a new set of eyes can better put a system together
2 that makes more sense for where we are rather than where
3 it started in 1982, '83, '81. I can't remember when
4 Dr. Willmorth put it together.
5 COMMISSIONER SMITH: Okay. Thank you very
6 much.
7 COMMISSIONER REDFORD: I have one more
8 question.
9 COMMISSIONER SMITH: Oh, Commissioner
10 Redford.
11
12 EXAMINATION
13
14 BY COMMISSIONER REDFORD:
15 Q Would you say that meetings of the parties
16 that they're so polarized that on their own they probably
17 could not come up with a different solution, are you
18 saying that?
19 A Yeah, and I have some empirical historical
20 data I could cite and, you know, in all candor, I was
21 part of that process, so...
22 Q It seems to me that a third party who
23 would look at it probably has some bias himself.
24
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A Very well could.
Q And so it would probably be very difficult
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1 to come up with that party among the participants to
2 finally select one. What I'm saying is we might never
3 ever be able to pick one.
4 A I don't disagree with that on its face,
5 but I think given the obvious frustration that
6 Commissioner Smith has expressed, we should at least
7 try.
8 Q Have you ever thought of gathering the
9 parties together before a mediator?
10 A A new thought, Commissioner Redford. Let
11 me process for a second here. That mediator, no, I have
12 not thought of that, but that mediator would need to be
13 somebody who really understood what cost of service was
14 about. I mean, it's such a technical kind of an area
15 that you would need someone with significant knowledge
16 about the process to be the mediator and that's, you
17 know, I guess I'll speak for my client without my
18 attorney whispering in my ear, but I think that is
19 certainly an avenue that may bear fruit and would be very
20 interesting to look at.
21 Q In my past I've dealt with mediators on
22 several occasions when it looked like there was an
23 impasse and we had to go to court. I would just like all
24 the parties to think about the possibility of mediating
25 this because it is a dispute and I agree with you that we
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1 would need someone who has significant understanding of
2 the process, but I throw that out. I mean, we need to
3 exhaust all things we can do to save from having
4 commissions finally impose some solution that may not
5 satisfy everyone or anyone.
6 A I would agree and probably the best
7 decision is one that would satisfy none of the parties.
8 COMMISSIONER REDFORD: You're probably
9 right. Thank you. I have no further questions and I
10 appreciate your testimony.
11 THE WITNESS: Thank you.
12 COMMISSIONER SMITH: Mr. Richardson, do
13 you have any redirect?
14 MR. RICHARDSON: I do, Madam Chairman.
15 Thank you.
16
17 REDIRECT EXAMINATION
19 BY MR. RICHARDSON:
20 Q Dr. Reading, you were asked by
21 Commissioner Redford about the riskiness of Idaho Power's
22 construction proj ects and the risk of a proj ect not
23 coming on line as being fairly low, but isn't there a
24 flip side to that risk and that is the customer going
25 away and having paid for a project in CWIP that it never
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1 enj oys the benefits of?
2 A Yes, that's one of the issues and it's
3 articulated in one of the Orders either I quoted or you
4 had folks read from the stand.
5 Q And it's a real world issue, isn't it?
6 Haven't members of the industrial customers of Idaho
7 Power closed factories on Idaho Power's system?
8 A Several.
9 Q And Commissioner Redford suggested that
10 perhaps it might be less expensive for Idaho Power to use
11 CWIP to help it finance its construction proj ects. Would
12 that have any impact on the riskiness of Idaho Power in
13 their rate of return on equity?
14 A In general, a utility that would receive
15 CWIP on kind of an ongoing basis would be viewed as less
16 risky.
17 Q And less risky utili ties typically have
18 lower--
A Lower equity rates of return and overall
20 rates of return. It would justify setting an equity rate
21 that would be lower.
22 Q And finally, just so we have a sense of
23 what we're talking about in this docket, what's the
24 magnitude of this CWIP adjustment on revenue requirement
25 in this docket?
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1 A Let's see, 7.6 million and then Dr. Peseau
2 pointed out in his testimony, when you gross it up, it's
3 about 12 million, so you do the arithmetic off the
4 original asset, so it would be 76 into 12 whatever, so it
5 would be a significant part of this case.
6 MR. RICHARDSON: That's all I have,
7 Madam Chairman. Thank you.
8 COMMISSIONER SMITH: Thank you,
9 Dr. Reading, appreciate your help as always.
10 THE WITNESS: Thank you.
11 COMMISSIONER REDFORD: Thanks very much.
12 (The witness left the stand.)
13 COMMISSIONER SMITH: Okay, we'll go off
14 the record for a moment.
15 (Off the record discussion.)
16 COMMISSIONER SMITH: All right, we'll be
17 done for the day. We'll start in the morning at 9: 30.
18 MR. KLINE: Madam Chair, one last thing,
19 can we excuse Ms. Smith and Mr. Keen?
COMMISSIONER SMITH: If there is no
21 objection, they are excused.
22 MR. OLSEN: Madam Chair, also one
23 housekeeping matter.
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COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: I was wondering if I could beg
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1 your indulgence if I could participate by phone tomorrow,
2 travel back to Pocatello and hear the last li ttle bit.
3 COMMISSIONER SMITH: You want to drive in
4 the snow?
5 MR. OLSEN: Well, I would rather --
6 COMMISSIONER SMITH: Mr. Olsen, that will
7 be perfectly fine and get the phone number. I'm assuming
8 the bridge will be open tomorrow.
9 MR. OLSEN: Okay, thank you very much.
10 (The Hearing recessed at 4: 15 p.m.)
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