IPC5261.docx

1 BOISE, IDAHO, TUESDAY, MAY 26, 1998, 9:30 A. M.
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4 COMMISSIONER SMITH: Good morning, ladies
5 and gentlemen. This is the time and place set for
6 hearing in Idaho Public Utilities Commission Case
7 No. IPC-E-97-12. This is the matter of the application
8 of Idaho Power Company for authority to increase its
9 rates and charges to recover demand side management and
10 conservation expenditures.
11 We'll begin this morning by taking the
12 appearance of the parties. Mr. Ripley.
13 MR. RIPLEY: Larry D. Ripley appearing on
14 behalf of Idaho Power Company.
15 COMMISSIONER SMITH: Mr. Purdy.
16 MR. PURDY: Brad Purdy, Deputy Attorney
17 General, appearing on behalf of the Commission Staff.
18 COMMISSIONER SMITH: And Mr. Budge.
19 MR. BUDGE: Randy Budge on behalf of Idaho
20 Irrigation Pumpers Association.
21 MR. RICHEY: Alan Richey on behalf of
22 Micron Technology, Incorporated.
23 MR. JAUREGUI: Paul L. Jauregui on behalf
24 of the Rate Fairness Group.
25 COMMISSIONER SMITH: Mr. Richardson.
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CSB REPORTING COLLOQUY
Wilder, Idaho 83676
1 MR. RICHARDSON: Peter Richardson with the
2 firm Davis Wright Tremaine on behalf of the Industrial
3 Customers of Idaho Power and also Molly O'Leary of the
4 firm Davis Wright Tremaine who will be sitting in for me
5 tomorrow.
6 COMMISSIONER SMITH: All right, thank you.
7 Mr. Ward.
8 MR. WARD: Conley Ward of the firm Givens,
9 Pursley for FMC.
10 COMMISSIONER SMITH: You came in for this?
11 MR. WARD: Foolishly.
12 COMMISSIONER SMITH: Mr. Gollomp.
13 MR. GOLLOMP: Lawrence Gollomp of the
14 United States Department of Energy on behalf of the
15 Federal Executive Agencies.
16 MR. FOTHERGILL: Al Fothergill for the
17 Idaho Citizens Coalition.
18 COMMISSIONER SMITH: I think I've gotten
19 everyone. Let the record reflect that the Idaho Consumer
20 Affairs was granted intervention, but no one appears on
21 their behalf today and with that, it looks like we have
22 everybody else.
23 Are there any preliminary matters or
24 motions that need to be taken up before we begin the
25 presentation of the testimony?
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Wilder, Idaho 83676
1 MR. RIPLEY: Just one, Madam Chair.
2 COMMISSIONER SMITH: Mr. Ripley.
3 MR. RIPLEY: Perhaps it would be well if we
4 could have a line-up as to when the witnesses are to
5 appear and in what order. Idaho Power has already
6 received some inquiries. It makes no difference to us
7 what the order is.
8 COMMISSIONER SMITH: Well, it was my, I
9 guess, thought that the Company would start with its
10 direct case and I wasn't sure whether you intended to put
11 your rebuttal on when you put your direct case on or if
12 you're going to reserve it for the end.
13 MR. RIPLEY: We'll put our rebuttal on at
14 the end. I think procedurally it just makes more sense.
15 COMMISSIONER SMITH: And you have
16 Mr. Said?
17 MR. RIPLEY: We have Mr. Said and
18 Mr. Obenchain with direct and then we have Mr. Gale and
19 Mr. Said with rebuttal.
20 COMMISSIONER SMITH: And you'll save that
21 for the end?
22 MR. RIPLEY: Yes.
23 COMMISSIONER SMITH: All right, and then
24 the Staff had Ms. Carlock and Mr. Anderson.
25 MR. RIPLEY: Correct.
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Wilder, Idaho 83676
1 COMMISSIONER SMITH: And then I understood
2 that Mr. Power had requested to be on today and then Rate
3 Fairness has Mr. Arms.
4 MR. JAUREGUI: Mr. Arms will go on today or
5 tomorrow if we go into that.
6 COMMISSIONER SMITH: You think we'll be
7 done today? Mr. Peseau.
8 MR. RICHARDSON: Madam Chair, Dr. Peseau is
9 available all day today, but would need to leave early
10 afternoon tomorrow if that comports with the Commission's
11 ability.
12 COMMISSIONER SMITH: And Mr. Yankel.
13 MR. BUDGE: He'd be available any time.
14 He'll be here through tomorrow, so I suppose he can be
15 later, if necessary.
16 COMMISSIONER SMITH: And Mr. Richey has
17 Dr. Anderson.
18 MR. RICHARDSON: Dr. Anderson for Micron is
19 available today and tomorrow.
20 MR. WARD: And Mr. Bonn would be available
21 through about 2:00 o'clock tomorrow afternoon, so I guess
22 through tomorrow morning.
23 COMMISSIONER SMITH: All right. I'm
24 assuming the Staff is available any time.
25 MR. PURDY: All the time.
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Wilder, Idaho 83676
1 COMMISSIONER SMITH: Okay. Well, then I
2 propose that we start with the Company's witnesses
3 Mr. Said and Mr. Obenchain and then we could do Dr. Power
4 and Dr. Peseau and Mr. Bonn, and then we'll see where we
5 are. How is that?
6 We'll go to you, Mr. Ripley.
7 MR. RIPLEY: I'm sorry, I can't hear you.
8 COMMISSIONER SMITH: You can't hear me?
9 Can you hear me now?
10 MR. RIPLEY: Yes, I can. Do you want
11 Mr. Said to take the stand?
12 COMMISSIONER SMITH: Sure, we're ready.
13 With our new sound system, if your mike is on and you're
14 ruffling your papers, it picks it up very well, so if we
15 can remember we'll keep our mikes off unless we're
16 speaking and that would probably work better.
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Wilder, Idaho 83676
1 GREGORY W. SAID,
2 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:
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6 DIRECT EXAMINATION
7
8 BY MR. RIPLEY:
9 Q Would state your full name for the record,
10 please?
11 A Gregory W. Said.
12 Q Mr. Said, are you the same individual that
13 has prefiled 16 pages of prefiled testimony?
14 A Yes, I am.
15 Q And you also in that testimony, you
16 identify 10 exhibits that are prenumbered?
17 A That's correct.
18 Q If I asked you the questions that are set
19 forth in your testimony, would your answers be the same
20 today?
21 A Yes.
22 MR. RIPLEY: With that, we would ask that
23 Mr. Said's testimony be incorporated into the record and
24 his exhibits be identified as they are premarked and we
25 would tender him for cross-examination.
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CSB REPORTING SAID (Di)
Wilder, Idaho 83676 Idaho Power Company
1 COMMISSIONER SMITH: If there's no
2 objection, the prefiled testimony of Mr. Said will be
3 spread upon the record as if read and his exhibits will
4 be identified as they have been premarked.
5 (The following prefiled testimony of
6 Mr. Gregory Said is spread upon the record.)
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CSB REPORTING SAID (Di)
Wilder, Idaho 83676 Idaho Power Company
1 Q Please state your name and business
2 address.
3 A My name is Gregory W. Said and my business
4 address is 1221 West Idaho Street, Boise, Idaho.
5 Q By whom are you employed and in what
6 capacity?
7 A I am employed by Idaho Power Company as a
8 Supervisor in the Pricing & Regulatory Services
9 Department.
10 Q Please describe your educational
11 background.
12 A In May of 1975, I received a Bachelor of
13 Science Degree with honors in Mathematics from Boise
14 State University.
15 Q Please describe your work experience with
16 Idaho Power Company.
17 A I became employed by Idaho Power Company in
18 1980. My first responsibilities with the Company
19 involved developing power supply simulation models for
20 use in resource planning and revenue requirement
21 determinations.
22 I have testified before this Commission on
23 issues such as general revenue requirements, surcharges,
24 establishment and changes in the Power Cost Adjustment
25 (PCA), and line extension provisions.
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SAID, DI 2
IDAHO POWER COMPANY
1 In 1994, I was asked to become the Meridian
2 District Manager for a one year cross-training
3 opportunity. After that I was promoted to lead a team of
4 analysts in the Pricing & Regulatory Services Department,
5 formerly known as the Rate Department. In this role, I
6 prepare or direct the
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SAID, DI 2A
IDAHO POWER COMPANY
1 preparation of analyses of pricing methods, revenue
2 requirement determinations, line installation provisions,
3 as well as other utility issues. In August, I was asked
4 to be Project Manager for the recovery of Demand Side
5 Management/Conservation (DSM) expenditures.
6 Q What is the purpose of your testimony in
7 this proceeding?
8 A The purpose of my testimony is to obtain
9 approval of a new tariff schedule to allow for recovery
10 of outstanding DSM expenditures. In support of this, I
11 will first quantify the revenue requirement associated
12 with the outstanding DSM expenditures that the Company is
13 entitled to recover in the Idaho jurisdiction. Second, I
14 will discuss the allocation of the revenue requirement to
15 customer classes. Finally, I will discuss rate design
16 for collection of the revenue requirement.
17 Q Has the Commission encouraged the Company
18 to make such a filing?
19 A Yes. In Order No. 27045 issued in Case
20 No. IPC-E-96-26, the case in which Idaho Power Company
21 applied for authority to implement a public purposes
22 charge to fund the Company's participation in the
23 Northwest Energy Efficiency Alliance, the Commission
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25 "We encourage the Company to initiate a
proceeding that would permit a
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SAID, DI 3
IDAHO POWER COMPANY
1 comprehensive review of its existing DSM
2 investment and recovery."
3 Later in that same case, the Commission issued Order
4 No. 27200 and stated:
5 "In the meantime, the Company is free to
6 make a proposal regarding the recovery of
7 outstanding DSM investment."
8 Revenue Requirement
9 Q Have you quantified the Idaho
10 jurisdictional revenue requirement associated with the
11 outstanding DSM investment?
12 A Yes. I have quantified a five year Idaho
13 jurisdictional revenue requirement associated with the
14 outstanding DSM investment amounting to $42,348,700.
15 This amount is comprised of four major components; (1) an
16 amount associated with accelerating the amortization of
17 deferred program expenditures made prior to 1994,
18 (2) deferred program expenditures made after 1993,
19 (3) carrying charges on deferred DSM amounts and,
20 (4) income tax impacts on the carrying charge component.
21 I will discuss each of the components in detail.
22 Q Why have you quantified the Idaho
23 jurisdictional revenue requirement for a five year time
24 period rather than quantifying an annual revenue
25 requirement?
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SAID, DI 4
IDAHO POWER COMPANY
1 A In this filing, the quantification of the
2 revenue requirement is contingent upon acceptance of the
3 amortization period length that I will discuss later in
4 my testimony.
5 Q What is the five year revenue requirement
6 associated with accelerating the amortization of deferred
7 program expenditures made prior to 1994 which you have
8 called the first component?
9 A Based upon changing the amortization period
10 for deferred program expenditures made prior to 1994 from
11 24 years to five years, the Idaho jurisdictional revenue
12 requirement is $13,311,200 to be recovered in the five
13 year period.
14 Q Why has the Company selected a five year
15 recovery period?
16 A In recognition of the likelihood of changes
17 in the electric industry, a five year recovery period
18 seems like a reasonable time period for recovering
19 expenditures from the customers for whom the expenditures
20 were made. The current 24 year time period for recovery
21 of DSM expenditures is no longer reasonable.
22 Q Have you prepared an exhibit prepared to
23 illustrate the determination of $13,311,200 as the five
24 year Idaho jurisdictional revenue requirement associated
25 with accelerating the amortization of deferred DSM program
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SAID, DI 5
IDAHO POWER COMPANY
1 expenditures made prior to 1994?
2 A Yes. Exhibit 1 was prepared for that
3 purpose. As a result of Case No. IPC-E-94-5, the
4 Company's last general revenue requirement proceeding,
5 the Company began amortizing $19,863,300 of deferred DSM
6 program expenditures incurred prior to 1994 at a rate of
7 $68,970 per month after the first month. Exhibit 1
8 demonstrates that this balance will decline to
9 $17,449,400 on December 31, 1997. I propose amortizing
10 the $17,449,400 balance over the next five years. The
11 $17,449,400 can be recovered by 59 monthly payments of
12 $290,825 and a final monthly payment of $290,725. The
13 change in the monthly amortization amount is $221,855
14 ($290,825 - $68,970). The total change in revenues to be
15 collected over 60 months amounts to $13,311,200.
16 Q What is the Idaho jurisdictional revenue
17 requirement for the deferred program expenditures made
18 after 1993 which you have called the second component?
19 A The Idaho jurisdictional revenue
20 requirement for the deferred program expenditures made
21 after 1993 is $16,239,800.
22 Q Have you prepared exhibits to demonstrate
23 the determination of the Idaho jurisdictional revenue
24 requirement for deferred program expenditures made after
25 1993?
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SAID, DI 6
IDAHO POWER COMPANY
1 A Yes. Exhibit 2 shows the detail of
2 deferred DSM expenditures by program and by year. Total
3 deferred DSM expenditures for all programs during the
4 period January 1, 1994 through August 31, 1997 were
5 $16,999,200.
6 Exhibit 3 demonstrates the allocation of
7 total deferred DSM program expenditures to the retail
8 jurisdictions. Of the $16,999,200 total deferred DSM
9 program expenditures, $16,239,800 are the responsibility
10 of the Idaho jurisdiction.
11 Q What are the carrying charges associated
12 with the deferral of DSM expenditures?
13 A The third component of the five year Idaho
14 jurisdictional revenue requirement, carrying charges
15 associated with the deferral of DSM expenditures, is
16 $7,794,000.
17 Q Please detail the derivation of the
18 carrying charges associated with the deferral of DSM
19 expenditures component of the Idaho jurisdictional
20 revenue requirement.
21 A The carrying charges component can be
22 separated into two elements. The first element of the
23 carrying charge component is historical carrying charges
24 accrued on deferred DSM program expenditures during the
25 January 1, 1994 through December 31, 1995 time period
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SAID, DI 7
IDAHO POWER COMPANY
1 which amounts to $2,967,200 as shown on line 18 of
2 Exhibit 3. Carrying charges have accumulated at a rate
3 of 9.199 percent, the rate of return
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SAID, DI 7A
IDAHO POWER COMPANY
1 authorized in Case No. IPC-E-94-5, Idaho Power Company's
2 last general rate case.
3 Q Why have you excluded carrying charges
4 accrued in calendar years 1996 and 1997?
5 A Carrying charges on deferred DSM
6 expenditures accrued in 1996 amounting to $1,415,900 were
7 not included because of specific treatment of this amount
8 as a result of Order No. 26925 in Case No. IPC-E-97-5,
9 the "revenue sharing" compliance filing. Likewise,
10 carrying charges on deferred DSM expenditure accrued in
11 1997 amounting to $1,096,300 as of August 31, 1997 have
12 not been included. At this time it is anticipated that
13 revenue sharing for 1997 will exceed the carrying charges
14 that will accrue on deferred DSM expenditures in 1997.
15 Idaho Power Company intends to request similar treatment
16 for 1997 carrying charges on DSM as was ordered for 1996
17 carrying charges on DSM.
18 Q What is the second element of the carrying
19 charge component?
20 A The second element of the carrying charge
21 component is future carrying charges during the
22 amortization period. I recommend a simple mortgage
23 approach to a five year amortization period. Exhibit 4
24 has been created to illustrate this amortization. With a
25 beginning balance of $19,207,000 ($16,239,800 of program
costs and $2,967,200 of
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SAID, DI 8
IDAHO POWER COMPANY
1 carrying charges to date) and an rate of equaling 9.199
2 percent (the same rate at which carrying charges have
3 been accruing) monthly payments for a five-year
4 amortization would be $400,560 ($320,110 of levelized
5 principal and $80,450 of levelized carrying charges).
6 Fifty nine payments of $400,560 and a one month residual
7 payment of $400,760 total $24,033,800 which includes
8 $4,826,800 of future carrying charges.
9 Q What is the sum of the historical carrying
10 charges accrued on deferred DSM program expenditures
11 during the January 1, 1994 through December 31, 1995 time
12 period and the future carrying charges to be recovered
13 during the amortization period?
14 A The total carrying charge component is the
15 sum of these two elements, $2,967,000 and $4,826,000,
16 which total $7,794,000.
17 Q What is the income tax impact that you have
18 included as the fourth component of the five year Idaho
19 jurisdictional revenue requirement associated with the
20 deferral of DSM expenditures?
21 A The income tax impact component of the five
22 year Idaho jurisdictional revenue requirement associated
23 with the deferral of DSM expenditures is $5,003,700.
24 Q How was this amount determined?
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SAID, DI 9
IDAHO POWER COMPANY
1 A The income tax impact of $5,003,700 was the
2 rounded product computed by multiplying the carrying
3 charge component, $7,794,000 by the tax gross up
4 multiplier, 0.642. This tax gross up multiplier is the
5 same value as was used in Case No. IPC-E-94-5. Recovery
6 of carrying charges is not offset by an accompanying
7 expense and results in income that will be taxed. In
8 order to insure full recovery of carrying charges, a tax
9 gross up amount must be collected to offset the resulting
10 income tax expense.
11 Q Please summarize the four components of the
12 five year Idaho jurisdictional revenue requirement
13 associated with the outstanding DSM investment.
14 A The five year Idaho jurisdictional revenue
15 requirement associated with accelerating recovery of the
16 unamortized balance of deferred program expenditures made
17 prior to 1994 is $13,311,200. The Idaho jurisdictional
18 revenue requirement associated with deferred program
19 expenditures after 1993 is $16,239,800. The five year
20 Idaho jurisdictional revenue requirement associated with
21 carrying charges on deferred DSM amounts is $7,794,000
22 and the five year Idaho jurisdictional revenue
23 requirement associated with income taxes on carrying
24 charges is $5,003,700.
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SAID, DI 10
IDAHO POWER COMPANY
1 Class Allocation
2 Q What is your recommendation for allocating
3 the five year Idaho jurisdictional revenue requirement to
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SAID, DI 10A
IDAHO POWER COMPANY
1 customer classes?
2 A I recommend treatment of the five year
3 Idaho jurisdictional revenue requirement amounting to
4 $42,348,700 as two separate amounts allocated to customer
5 classes by separate methods. I recommend that the first
6 amount, $13,311,200, which is the revenue requirement
7 associated with accelerating amortization of deferred DSM
8 expenditures made prior to 1994, be allocated to customer
9 classes using the same allocations as were used in Case
10 No. IPC-E-94-5, Idaho Power Company's last general
11 revenue requirement case. This would allow for
12 acceleration of amounts already allocated to classes.
13 Exhibit 5 shows the previously approved allocation factor
14 and resulting allocation to customer classes of the
15 $13,311,200 portion of revenue requirement.
16 I recommend that the remainder of the
17 revenue requirement, $29,037,500, which includes
18 (1) deferred program expenditures after 1993,
19 (2) carrying charges and (3) income taxes, be allocated
20 based upon the ability of the customer class to
21 participate in programs. Exhibit 6 illustrates the
22 results of this allocation method.
23 Q Why do you recommend this hybrid approach
24 to allocation?
25 A My recommendation recognizes that in the
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SAID, DI 11
IDAHO POWER COMPANY
1 past DSM expenditures have been viewed as system
2 resources and as
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IDAHO POWER COMPANY
1 such, the costs have been allocated to classes based upon
2 class use (demand and energy) of resources. My
3 recommendation also recognizes that DSM is currently
4 viewed from the perspective of the direct benefits
5 (i.e., ability to participate in programs) that customers
6 receive from expenditures made on their behalf.
7 My hybrid approach to allocation blends
8 these two concepts.
9 Q Please describe Exhibit 6.
10 A Exhibit 6 details the allocation of
11 $29,037,500 portion of the revenue requirement to
12 customer classes. The Design Excellence Award Program
13 (line 1 DEAP) and the Commercial Lighting Program (line 6
14 CLP) were available to Small General Service (Schedule 7)
15 customers, Large General Service (Schedule 9) customers
16 and Large Power Service (Schedule 19) customers. The
17 Idaho jurisdictional revenue requirements of $793,900 for
18 DEAP and $901,000 for Commercial Lighting were allocated
19 to these three rate classes based upon their annual
20 energy usage. Some programs (Manufactured Home
21 Acquisition, Good Cents and Idaho Weatherization) were
22 available only to Residential Service (Schedule 1)
23 customers. Other programs (Agricultural Choices and Bell
24 Rapids) were available only to Irrigation Service
25 (Schedule 24) customers. The Partners in Industrial
Efficiency (PIE) program was available to Large Power
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SAID, DI 12
IDAHO POWER COMPANY
1 Service (Schedule 19) customers and Special Contract
2 customers.
3 Q How were the costs of the Low Income
4 Weatherization Assistance program allocated to customer
5 classes?
6 A Even though the Low Income Weatherization
7 Assistance program was not available to all customer
8 classes, it has never been viewed as purely a DSM program
9 and therefore should receive broadly based financial
10 support from all customer classes.
11 Q How were research expenditures allocated to
12 customer classes?
13 A The sums of the program costs allocated to
14 customer classes were used to allocate Research
15 Expenditures to customer classes. Likewise, carrying
16 charges and income taxes were also allocated based upon
17 the sums of allocated program costs. Line 16 of
18 Exhibit 6 shows the sum of allocations of the $29,037,500
19 to customer classes.
20 Q Have you prepared an exhibit to reflect the
21 combination of the allocation of $13,311,200 to customer
22 classes based on Case No. IPC-E-94-5 allocation factors
23 and the allocation of $29,037,500 to customer classes
24 based on the "ability to participate" allocation factors?
25 A Yes. Exhibit 7 shows the combination of
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IDAHO POWER COMPANY
1 the allocation of $13,311,200 to customer classes based
2 on Case
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IDAHO POWER COMPANY
1 No. IPC-E-94-5 allocation factors and the allocation of
2 $29,037,500 to customer classes based on ability to
3 participate allocation factors.
4 Rate Design
5 Q How do you propose recovering these revenue
6 requirements from the various customer classes?
7 A First, let me address the Special Contract
8 customers. I recommend a monthly charge for Special
9 Contract customers equal to one sixtieth (1/60) of their
10 five year revenue requirement rounded to the nearest 100
11 dollars. For Micron Technology, the monthly charge is
12 $9,800. For FMC the monthly charge is $55,600. For
13 Simplot Fertilizer in Pocatello, the monthly charge is
14 $8,800. For the DOE, the monthly charge is $6,000.
15 For all other customer classes, I recommend
16 a percentage adjustment to their monthly bills. The
17 percentage adjustment is determined by dividing the
18 customer class monthly DSM revenue requirement by the
19 1996 normalized monthly customer class revenue. The
20 calculation of this percentage is shown in Exhibit 8.
21 Q How long will these monthly charges remain
22 in effect?
23 A All of these monthly charges are intended
24 to remain in effect for five years.
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SAID, DI 14
IDAHO POWER COMPANY
1 Q Do you have an exhibit that reflects these
2 charges in a rate schedule format?
3 A Yes. Exhibit 9 is a proposed rate schedule
4 entitled "Schedule 96, ADJUSTMENT FOR DEMAND SIDE
5 MANAGEMENT COSTS."
6 Q You have stated that the monthly charges
7 are intended to remain in effect for five years. Do you
8 envision circumstances where this would not be the case?
9 A Yes. Customer growth from 1996 levels
10 would suggest that the Company may recover the revenue
11 requirement of specific customer classes prior to the end
12 of the five year period. I recommend that the company
13 track recovery of DSM related revenue requirement by
14 class and discontinue collection as individual classes
15 fully pay their revenue requirement. In addition, early
16 payoff of revenue requirement should allow for avoidance
17 of some future carrying charges and income tax.
18 Q How can early payoff of revenue
19 requirement be tracked?
20 A The best way to track early payoff of
21 revenue requirement will be to track recovery of future
22 carrying charges and income taxes separately from
23 recovery of program expenditures and historical carrying
24 charges (principal). Monthly revenues would first be
25 used to pay a fixed monthly amount toward future carrying
charges and income tax. The
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IDAHO POWER COMPANY
1 remainder of the monthly payment would go to reduction of
2 the principal amount by class. When the principal
3 balance reaches zero the adjustment for that class will
4 end.
5 Q Have you prepared an exhibit that shows the
6 separation of principal amounts from the future carrying
7 charges and income taxes by class?
8 A Yes. Exhibit 10 shows the separation of
9 principal from the future carrying charges and income
10 taxes by class.
11 Q Will the Commission have additional
12 opportunity to buy down the principal balance?
13 A Yes. The Commission could decide to use
14 additional "revenue sharing" dollars to reduce the DSM
15 principal and/or future carrying charges.
16 Q Would the reduction in future carrying
17 charges also reduce future income taxes?
18 A Yes.
19 Q Have you created a billing comparison
20 exhibit?
21 A No. The charges themselves reflect the
22 percentage change for all customer classes except the
23 special contracts.
24 Q Does this complete your prefiled testimony?
25 A Yes, it does.
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IDAHO POWER COMPANY
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER SMITH: Mr. Purdy, do you have
4 questions?
5 MR. PURDY: Madam Chair, most my questions
6 are pertinent to Mr. Said's rebuttal, the others can go
7 either way, so I will defer until his rebuttal testimony.
8 COMMISSIONER SMITH: Mr. Budge.
9 MR. BUDGE: No questions.
10 COMMISSIONER SMITH: Mr. Richey.
11 MR. RICHEY: No questions at this time.
12 COMMISSIONER SMITH: Mr. Richardson.
13 MR. RICHARDSON: I'll give it a shot,
14 Madam Chairman.
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16 CROSS-EXAMINATION
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18 BY MR. RICHARDSON:
19 Q Mr. Said, with reference to the
20 acceleration or the change in the amortization period for
21 deferred DSM costs, I guess it's fair to say the heart of
22 the Company's case is the move from 24 to five years; is
23 that correct?
24 A That is one aspect of our case, yes.
25 Q Can you enlighten us as to what studies or
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CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 what background the Company relied upon to recommend this
2 change?
3 A The Company essentially relied upon
4 previous Commission orders, the two that I've cited in my
5 testimony, encouraging us to come in for a review of
6 demand side management expenditures, consideration of
7 changes in the industry with regard to resource
8 planning. There are no specific studies that I referred
9 to.
10 Q The orders you refer to in your testimony
11 don't suggest that you shorten the amortization period
12 for recovery of DSM, do they?
13 A No. They just suggest there be a
14 comprehensive review of a recovery of demand side
15 management expenditures.
16 Q And when you say you factored into the
17 decision consideration of changes in the industry, what
18 changes were you referring to?
19 A Essentially, a change in perspective of how
20 the time frames for collection in this case of DSM
21 expenditures. In previous cases relating to line
22 extensions and the like, the Commission has looked at the
23 same sort of issues as to when recovery should occur and
24 who should be responsible for that payment.
25 Q So changes in the industry, you're
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1 referring to specifically this Commission's consideration
2 of line extension charges?
3 A Line extensions is a point. In addition,
4 I've mentioned resource planning and the way that that
5 has changed over time from individual company looks to
6 regional perspectives and market influence.
7 Q What specific changes in the Company's
8 resource planning prompted the recommendation that the
9 amortization period be shortened from 24 to five years?
10 A I wouldn't say that specifically the change
11 in resource. The planning horizon was the emphasis for
12 changing the amortization period. The Company's position
13 has always been that DSM was not the typical utility
14 asset, but rather was a regulatory asset that should be
15 recovered over a shorter period of time.
16 Q Right, but you said there were changes in
17 the industry that prompted your recommendation and you
18 specifically referenced resource planning.
19 A I think that change supports the position
20 that the Company has held all along.
21 Q The change to go to a regional planning
22 basis?
23 A The changes in the industry support what
24 the Company has contended.
25 Q And which changes are those? That's what
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1 I'm trying to get to.
2 A Resource planning.
3 Q And the change in resource planning was the
4 change from a utility specific to a regional resource
5 plan?
6 A And shortened planning horizons, yes.
7 Q And has Idaho Power gone to a regional
8 resource plan?
9 A Idaho Power has stated that they don't
10 intend to build any additional resources and rather will
11 rely on the market.
12 Q And that's what you mean by a regional
13 resource plan?
14 A Essentially, looking at market influences
15 in the region, yes.
16 Q And what are those market influences that
17 suggest that a shorter amortization period is more
18 appropriate?
19 A The reduced time frame for looking at
20 resources and avoided costs.
21 Q Do you know what the 24-year amortization
22 period was based on?
23 A Yes, I do.
24 Q And what was that?
25 A It was a review of the used and useful life
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1 of DSM programs.
2 Q And that was sort of an amalgamation of all
3 the different DSM programs to arrive at an average of 24
4 years?
5 A Yes.
6 Q So it was based upon an expected useful
7 life of each individual DSM measure; correct?
8 A That's correct.
9 Q And is it your understanding that those
10 expected useful lives has changed?
11 A No. Essentially, again, the Company's
12 contention has always been that those assets should be
13 viewed differently. In the last case when the 24-year
14 amortization was established, the Commission did decide
15 to create an amortization period that looked at those
16 costs as if they were utility assets and did not make a
17 distinction between them as a utility asset or a
18 regulatory asset.
19 Q But nothing has changed with regard to the
20 assets that the Commission found 24 years was appropriate
21 to amortize; correct?
22 A The assets are the same, yes.
23 Q And their amortization, their useful lives
24 are the same; correct?
25 A Yes.
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1 Q Now, are you aware of any other precedent
2 for the Company to depreciate Company-owned assets faster
3 than they become obsolete?
4 MR. RIPLEY: Objection. He's referring to
5 depreciation which is entirely different than
6 amortization.
7 COMMISSIONER SMITH: Mr. Richardson.
8 Q BY MR. RICHARDSON: Would you agree that
9 the amortization period of 24 years was a surrogate for
10 depreciation, the depreciable lives of the DSM measures
11 that have been installed?
12 MR. RIPLEY: Objection. The Order speaks
13 for itself. Is he asking Mr. Said what he thinks or what
14 the Commission said?
15 MR. RICHARDSON: Mr. Said is here on the
16 stand talking about the specific issue of the
17 amortization of the DSM measures installed and I'm asking
18 Mr. Said what his understanding of the basis for that
19 24-year period was.
20 MR. RIPLEY: If he's asking what Mr. Said's
21 understanding is, then we obviously have no objection.
22 MR. RICHARDSON: That's exactly what I'm
23 asking him.
24 COMMISSIONER SMITH: Thank you.
25 Mr. Said.
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1 THE WITNESS: Yes, as I mentioned, I
2 believe what the Commission did was look at those lives
3 of the DSM expenditures and treat those as if they were
4 like utility assets rather than making a distinction that
5 they were a regulatory asset with potentially a different
6 life.
7 Q BY MR. RICHARDSON: So the amortization
8 would be akin to a depreciation schedule on a
9 Company-owned asset, would it not?
10 A I think it would be similar, yes.
11 Q Are you aware of any precedent for the
12 Company to depreciate Company-owned assets at a faster
13 rate than they become obsolete?
14 A No, I'm not.
15 Q So this would be a unique treatment, would
16 it not?
17 A No, because, again, I don't think this is a
18 utility asset.
19 Q If it were a utility asset, it would be a
20 unique treatment, would it not?
21 A If it were a utility asset, then it would
22 be a little bit different than the treatment of other
23 assets.
24 Q It would be unique, wouldn't it?
25 A I'm unaware of any other assets that might
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1 be treated that way, but I'm not sure that there aren't
2 any.
3 Q It would be a singular type of treatment;
4 correct?
5 A Sure.
6 Q As far as you know?
7 A Sure.
8 Q And when you picked five years, why did you
9 go with five instead of seven or 10 or 15 or 20?
10 A To an extent it was a rate shock-type
11 evaluation, judgment call as to what the various customer
12 classes could tolerate.
13 Q And the reason for that is the shorter the
14 amortization period the larger the rate increase?
15 A That's true.
16 Q And whose judgment was it that decided that
17 the ratepayers could stand a five-year rate shock or rate
18 increase versus any other time period?
19 A That would have been my judgment along with
20 input from Mr. Gale.
21 Q What's the rate increase with the five-year
22 amortization period that you've suggested on average?
23 A The rate increases by class are shown on
24 Exhibit 9.
25 Q And the overall increase is what?
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1 A I don't know that I computed that.
2 Q About two percent?
3 A That's probably close, yes.
4 Q So you didn't compute the overall increase,
5 you didn't even know what it was, but you think that that
6 is not going to cause rate shock?
7 A I looked at the individual classes to
8 establish what the percentage increase would be by class.
9 Q You didn't look at it on an overall
10 Company-wide basis?
11 A No, I concentrated on the more specific.
12 Q Does each class have a different tolerance
13 for rate shock?
14 A They probably do, yes.
15 Q And are you recommending that the different
16 classes have different rate increases?
17 A Yes.
18 Q Is that based upon the amortization period
19 or some other factor?
20 A That's based primarily on the allocations.
21 Q Which drove which? Did the allocations
22 drive the rate increase or did you select the allocation
23 to arrive at a predetermined rate increase?
24 A No, there wasn't a predetermined rate
25 increase that was a goal. In deciding on the five-year
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1 amortization, I probably concentrated mostly on the
2 residential class, but did take the allocations into
3 consideration.
4 Q Did you have a benchmark beyond which the
5 residential class would be experiencing rate shock and,
6 therefore, we won't have that large of an increase?
7 A No.
8 Q So how did you come up with the five
9 years? You said that you used rate shock as the criteria
10 for the size of the increase and you said that the length
11 of time you amortized drives the size of the increase, so
12 where was the benchmark or was there one?
13 A There wasn't a benchmark when I looked at
14 the various years and discovered that for the residential
15 class a five-year amortization would result in about two
16 percent.
17 Q And what other amortization periods did you
18 consider?
19 A We looked at the rate impact of a number of
20 years of amortization. I think we looked at three and
21 seven.
22 Q And what increases did those cause the
23 residential class?
24 A I don't recall. With a shorter
25 amortization, as you had mentioned, the increase was
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1 greater and with a longer it was less.
2 Q And you concluded that three years caused
3 rate shock?
4 A Decided that three years was rapid and
5 probably did push the limits a little.
6 Q Pushed the limits of rate shock?
7 A Yes.
8 MR. WARD: Madam Chair, I'm having trouble
9 hearing the witness. Can you get a little closer to the
10 mike?
11 COMMISSIONER SMITH: I've turned the
12 control up here, what I can do, so we'll see if it's any
13 better.
14 THE WITNESS: I'll try and talk louder as
15 well.
16 Q BY MR. RICHARDSON: You said that three
17 years was pushing the limits and I asked you if three
18 years was pushing the limits of rate shock for the
19 residential class?
20 A In my judgment, it was.
21 Q And what was the percentage increase caused
22 by three years?
23 A I don't recall.
24 Q You don't recall. Do you have any idea
25 what rate shock would be for the residential class? What
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1 percentage increase would be in your view rate shock?
2 A In terms of the residential class and what
3 they've experienced over the recent years, I think maybe
4 they could tolerate more than at other times. The last
5 couple of years all of the classes have benefited from
6 rate reductions related to the power cost adjustment and
7 they've really not seen any rate increases for a
8 considerable period of time, so I don't know that
9 entirely rate shock was the only consideration.
10 In addition, considering what the Company
11 had proposed previously as an amortization period, and
12 that was seven years, five years would be a quicker
13 acceleration and still not create rate shock, so it was a
14 little bit of a combination of rate shock and consistency
15 with what the Company had proposed in the past.
16 Q But what the Company proposed in the past
17 wasn't adopted by the Commission, was it?
18 A No, it wasn't.
19 Q So you wanted to be consistent in terms of
20 your treatment of the ratepayers based upon your prior
21 recommendations or based upon what this Commission has
22 ordered in the past?
23 A There are some of both. We certainly like
24 to maintain consistency in what we propose and in this
25 case we didn't abandon what we had proposed solely
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1 because the Commission had seen it in a different light.
2 Q Was there anything else that factored into
3 your decision other than rate shock and consistency with
4 prior Company proposals to recommend five years?
5 A A desire to see DSM expenditures be paid
6 for.
7 Q And were they not being paid for -- are
8 they not being paid for now?
9 A They are being paid for over a longer
10 period of time.
11 Q So that hasn't changed? They're still
12 being paid for; correct?
13 A The time frame is what's different.
14 Q Does the Company have a concern that with
15 the 24-year time frame that its DSM expenditures will not
16 be paid for?
17 A No, my attorneys tell me that the DSM
18 expenditures will be paid for.
19 Q Even if it's a 24-year amortization period?
20 A Yes. The question then arises as to who
21 pays.
22 Q Who would pay under a 24-year amortization
23 period?
24 A Whichever customers are around 24 years
25 from now.
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1 Q And who pays in a five-year amortization
2 period?
3 A The customers that are here today.
4 Q You said that different, stepping back just
5 for a moment, different classes have different tolerances
6 for rate shock; is that correct?
7 A I'm sure that's true, yes.
8 Q And you said that the rate shock tolerance
9 for the residential class was five years. It is
10 possible, isn't it, the rate shock tolerance for another
11 class might be 23 years?
12 A Probably not in this instance.
13 Q How do you know that?
14 A Based on the percentage increases in that
15 same exhibit.
16 Q Is it possible to have a customer class
17 that is experiencing economic difficulty and any rate
18 increase no matter how small would be a burden?
19 A Yes.
20 Q Is it typical utility ratemaking policy to
21 set rates based upon what the customers want to pay?
22 A There's a consideration of what customers
23 can afford to pay, yes.
24 Q You said that one of the reasons that five
25 years was more appropriate than 24 was because you were
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1 uncertain of the ratepayers who would be paying for the
2 amortization at 24 years; is that correct?
3 A Yes, the customer base could change.
4 Q The customer base could change, and which
5 customers are benefiting by the conservation?
6 A Today's customers.
7 Q And will tomorrow's customer also benefit
8 by the installed conservation measures to the extent they
9 still have a useful life?
10 MR. RIPLEY: What customer is counsel
11 referring to, the customer that owns the particular asset
12 that has been installed?
13 MR. RICHARDSON: I've been following your
14 witness' lead. The word is his word.
15 COMMISSIONER SMITH: Mr. Richardson, could
16 you be specific in your questions and maybe if you need
17 clarification, ask the witness.
18 Q BY MR. RICHARDSON: You stated, Mr. Said,
19 that it's unclear which customers would be around to pay
20 for the DSM beyond five years.
21 A Yes.
22 Q Which customers were you referring to,
23 Mr. Said?
24 A I was referring to today's customers of
25 Idaho Power.
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1 Q And beyond five years, you don't know whose
2 customers those will be; is that your concern?
3 A Or whether or not the customers will be
4 customers. Businesses close or change locations is
5 always a possibility.
6 Q And when you talk about businesses closing
7 and changing locations, I assume you're talking about the
8 businesses Idaho Power serves, not Idaho Power.
9 A That's correct.
10 Q Okay. What about the specter of
11 competition in the electric industry, what influence has
12 that had on your decision to move to five years?
13 A I don't know that competition necessarily
14 has a direct influence, although if competition were to
15 arise, that would potentially allow customers to leave
16 the system as well.
17 Q So that's one of the Company's concerns in
18 moving the five years from 24 is that its customers today
19 may not be its customers tomorrow because of competition?
20 A The concern is that the customers who have
21 had DSM expenditures made on their behalf may not be the
22 customers that pay for those DSM measures.
23 Q And which customers are those that have had
24 DSM measures expended on their behalf?
25 A The current customers of Idaho Power
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1 Company.
2 Q All of them?
3 A Under the treatment in terms of
4 allocations, yes.
5 Q Okay; so you're concerned that any one of
6 those customers leaves the system, if any one of your
7 customers leave the system, because of competition, that
8 is a reason for moving to a shorter time period; correct?
9 A In terms of trying to match who's receiving
10 benefits and who pays, that's the motivation of moving to
11 a five-year period of time.
12 MR. RIPLEY: Mr. Said, you're going to have
13 to speak up.
14 THE WITNESS: The air conditioning just
15 came on?
16 Q BY MR. RICHARDSON: Assuming that you have
17 a stable customer base, that is, your customers don't
18 leave you for competition or whatever, isn't the Company
19 indifferent as to five years' or 24 years' amortization
20 period?
21 A If the customer base were never to change,
22 then collection over five or 24 years would --
23 Q I'm sorry?
24 A -- then collection over five or 24 years
25 would no longer be an issue, I guess that's true.
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1 That's, however, not a realistic hypothetical.
2 Q But it is true, if you have a stable or
3 even a growing customer base, the Company is indifferent
4 with 24 or five years; correct?
5 A A stable or growing is different than
6 having the same customers in place.
7 Q The specific identified customers or the
8 same number and size of system?
9 A I think it's the same customers that is the
10 interest.
11 Q What difference does that make to you, to
12 the Company, whether it's Alan Richey or Peter Richardson
13 who is your customer as long as you have the same number
14 of customers? Why do you care if you're still recovering
15 over the 24 years your DSM costs?
16 A Well, if I've incurred a cost for
17 Mr. Richardson and then later Mr. Richey takes his place,
18 I'm aware that Mr. Richey will not want to pay for
19 Mr. Richardson's costs.
20 Q But didn't you say that the DSM measures
21 were to benefit all of the customers?
22 A All of today's customers and in your
23 hypothetical --
24 Q And they're not benefiting any customer
25 beyond today?
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Wilder, Idaho 83676 Idaho Power Company
1 A Potentially not.
2 Q None of your -- how could they not be
3 benefiting customers beyond today? Explain that to me.
4 A If I install equipment for you today --
5 Q Now, you said earlier that the DSM measures
6 that have been installed have been to benefit all of the
7 customers; is that true or not?
8 A They have been viewed from the standpoint
9 of being allocated to customer classes in the past based
10 on resource planning criteria and the ability to defer
11 resources. In today's planning horizon where there are
12 no future resources to be deferred, the calculation of
13 avoided costs has changed from a resource deferral method
14 to more of a market price approach.
15 From that standpoint, Mr. Richey as a new
16 customer does not see a benefit from deferring resources
17 and he also does not have need of the demand side
18 management programs at his facility, so I would say no,
19 he's not benefited.
20 Q So it's your view that if a new customer
21 comes on to Idaho Power's system today, it should not
22 share in any of the DSM deferral costs?
23 A No, I'm not saying that.
24 Q Wouldn't that be logical, though, if you
25 assumed that a new customer today is not relying on any
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Wilder, Idaho 83676 Idaho Power Company
1 of these deferred demand side management costs, then that
2 new customer should not be responsible for paying for any
3 of those; correct?
4 A No, that's not my proposal.
5 Q I didn't say it was your proposal, but it's
6 logical based upon what you just said, isn't it?
7 A If you were to decide to isolate customers
8 and decide that only people in existence today should
9 have to pay for demand side management, then that would
10 be a possible result, but that's not my recommendation.
11 Q Your recommendation is that as of five
12 years from today future customers will not be required to
13 pay for any DSM measures; correct?
14 A Any of today's expenditures, yes.
15 Q Five years from today if your proposal is
16 adopted, after five years everyone beyond that time
17 period will reap no benefits whatsoever from any of your
18 DSM programs; correct?
19 A It would be hard to say that they do
20 receive benefits.
21 Q So when this Commission three years ago
22 said that these deferred demand side management
23 expenditures have useful lives of 30, 20 years because
24 they would be producing conservation savings for that
25 long, they were wrong?
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1 A I think the Company's opinion at that time
2 was that a shorter period would be more correct and the
3 Commission utilized its judgment which was different from
4 that of the Company.
5 Q But you don't agree that many of these
6 conservation measures have useful lives way beyond five
7 years?
8 A They do, but not to the Company,
9 necessarily.
10 Q Even though they're saving the Company the
11 need to go out and acquire resources to meet load?
12 A The Company has no plans to build
13 additional resources.
14 Q Would you agree that the shorter time
15 period for amortization of these DSM costs makes the
16 Company financially healthier?
17 A It creates both a revenue and an expense
18 stream that are approximately offsetting, so it won't
19 have a large impact.
20 Q Is it a cash expense stream?
21 A No, it's not.
22 Q So it's a non-cash expense that you now
23 have a cash revenue to cover?
24 A Yes.
25 Q And doesn't that make the Company
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CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 healthier?
2 A In terms of cash flow.
3 Q And what else does cash flow inure to the
4 benefit of? Doesn't it assist you in terms of you need
5 to go to the market to borrow money, it reduces that
6 need, doesn't it?
7 A It could, yes.
8 Q And doesn't it increase retained earnings,
9 possibly?
10 MR. RIPLEY: If you know, Mr. Said.
11 THE WITNESS: I don't believe so.
12 Q BY MR. RICHARDSON: Well, if you've got
13 more money in your pocket today than you did yesterday,
14 you're better off today than you were yesterday, aren't
15 you?
16 A Again, in terms of cash, but there's also
17 an expenditure, a paper expenditure, that would impact
18 earnings.
19 Q Doesn't your proposal also reduce the
20 Company's risk in terms of the financial markets?
21 A Looking ahead and knowing that Mr. Gale has
22 rebuttal testimony in that area and having read that, I
23 would say that it has the benefit of reduced risk if the
24 amounts that we're talking about were to be securitized.
25 Q So are you deferring to Mr. Gale or are you
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Wilder, Idaho 83676 Idaho Power Company
1 capable to answer that question?
2 A Mr. Gale would probably be the better
3 witness.
4 Q All right. Let's assume, just getting back
5 to that one point just for a quick moment, let's assume
6 that five years from now you've recovered all of your DSM
7 deferrals and the Company's prediction was wrong and you
8 have to go to the market to build a new generating
9 resource and that new generating resource costs more than
10 your embedded cost of power, do you have that assumption
11 in mind?
12 A Yes.
13 Q And that's not a wildly unreasonable
14 assumption, is it?
15 A It's not consistent with the current plan.
16 Q It's not consistent with your current plan?
17 A That's correct.
18 Q Okay. With that assumption in mind,
19 wouldn't the future ratepayers be getting benefits
20 without having to pay for those benefits of the DSM
21 measures that were paid for over the five-year period
22 between now and then?
23 A Your assumption was that the DSM
24 expenditures helped defer the need for a resource that
25 now you're saying is needed, so I don't -- I have trouble
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Wilder, Idaho 83676 Idaho Power Company
1 figuring out what the benefit is.
2 Q The assumption was that you are now five
3 years down the road and your projection that you would
4 never need to acquire another resource was wrong in order
5 to serve your customers and so Idaho Power is faced with
6 the decision of going out to acquire a new resource, the
7 cost of which is higher than your embedded cost, and you
8 have DSM in place, that we have in place today that is
9 presumably effecting some savings of energy and putting
10 off into the future the need for new resources, meaning
11 that you would have had to acquire new resources sooner
12 were it not for the DSM measures, now, the question is
13 with that premise in mind, wouldn't those ratepayers
14 after five years be reaping the benefits of the costs
15 that were amortized over five years rather than 24?
16 A It would require a change in the resource
17 planning methodology that the Company currently has in
18 place which would be to go out and purchase the power on
19 the market rather than to acquire its own physical
20 resources.
21 Q And the assumption was that the Company's
22 resource plan, that is, that you're never going to build
23 anything ever again, was wrong and that you had to build
24 something to meet load?
25 A I don't know that you could say that the
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Wilder, Idaho 83676 Idaho Power Company
1 resource plan was wrong. Again, the approach would then
2 be that the region has the need for a resource rather
3 than necessarily Idaho Power specific, in which case
4 Idaho Power could still purchase the output of a new
5 facility from another entity.
6 Q Let me ask it again.
7 MR. RIPLEY: Objection. He's arguing with
8 the witness. First, he's assuming facts that are not in
9 the record, postulating a hypothetical. Mr. Said has
10 done his best to answer it and now he wants to argue with
11 him.
12 MR. RICHARDSON: Madam Chairman, I'd ask
13 that you instruct the witness to answer the question
14 which he has been artfully dodging now for two times.
15 COMMISSIONER SMITH: Okay, Mr. Richardson,
16 try one more time and let's see if we get an answer.
17 Please don't be argumentative.
18 MR. RICHARDSON: Thank you,
19 Madam Chairman.
20 Q BY MR. RICHARDSON: Mr. Said, I'd like you
21 to assume with me for one moment that your application in
22 this case is approved and your DSM expenditures have been
23 amortized and completely paid for within five years. I'd
24 like you to also assume that the Company five years hence
25 is faced with a situation in which it is required to
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Wilder, Idaho 83676 Idaho Power Company
1 build a new resource, to acquire a new resource, to serve
2 its native load customers. Do you have that?
3 A Yes.
4 Q And that the cost of that new resource is
5 higher than your embedded cost. Do you have that?
6 A Uh-huh.
7 Q Wouldn't it be true in that situation that
8 the customers five years hence would be reaping some
9 reward, some benefit, however measured, from the DSM
10 measures that had been installed and that are under
11 discussion today?
12 A It would depend on the size of the resource
13 that under your hypothetical was required to be
14 constructed and whether or not it was reduced in size to
15 any extent by DSM measures that created less of a need
16 for additional load than the load that drove the need for
17 the new resource.
18 Q You trailed off.
19 A That was less than the load needed for, by
20 the new resource.
21 Q And if that were true, then, the answer to
22 my question would be that those ratepayers are benefiting
23 from the DSM measures installed today; correct?
24 A There might be some benefit.
25 Q Is that a yes or a no?
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1 COMMISSIONER SMITH: Mr. Richardson, I
2 think he answered your question.
3 MR. RICHARDSON: All right, thank you,
4 Madam Chairman, I'll move on.
5 Madam Chairman, I think that's all I have.
6 Thank you, Mr. Said.
7 COMMISSIONER SMITH: Thank you.
8 Mr. Jauregui.
9 MR. JAUREGUI: Yes, I have a few.
10
11 CROSS-EXAMINATION
12
13 BY MR. JAUREGUI:
14 Q In your direct testimony, you indicated, I
15 believe, that you were asked to be the project manager to
16 recover the demand side management expenditures?
17 A That is correct.
18 Q As a part of that program, were you given
19 numbers or how did you start that? You talked about the
20 numbers that you were going to recover. Was there an
21 examination made by you of those or were you given that
22 number of the DSM expenditures?
23 A There was a team created to assist me in
24 this project and the team provided the numbers that we as
25 a team reviewed before making this filing.
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1 Q With respect to those numbers, was there an
2 examination by that team of the prudency of those
3 expenditures?
4 A There was a look to see whether or not the
5 expenditures had been appropriately booked to a deferred
6 account or an expense account and the ongoing prudency of
7 the programs had been reviewed elsewhere.
8 Q I believe that you indicated that customer
9 consideration was one of the considerations in developing
10 the cost, the price customers would be willing to pay,
11 rate shock, in response to Mr. Richardson's question; is
12 that correct?
13 A That was a consideration in our final
14 recommendation, yes.
15 Q Was any consideration given in your group's
16 development of the numbers of any credits or adjustments
17 to customers or customer classes for reduced carrying
18 costs that were occurring during the interim period of
19 time or effects of termination of programs?
20 A With regard to the carrying costs, those
21 were being booked according to prior Commission orders.
22 In terms of the reduction of programs, the discontinuance
23 of programs, the deferred expenditures naturally dropped
24 off as the programs were discontinued.
25 Q If you know, isn't it a fact that the
143
CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 carrying costs of the programs were reducing due to
2 refinancings, efforts of the Company during the period
3 from '95 through '97; is that correct?
4 A I'm not aware.
5 Q In your direct testimony, you indicated
6 that it was not changes in the electric industry but the
7 likelihood of changes. Those were in the future, was it
8 not? Isn't likelihood of changes speaking to the
9 future? What changes had occurred in the past at the
10 time that you submitted your prepared testimony that you
11 were looking at?
12 A Essentially, the changes that I've
13 discussed with Mr. Richardson.
14 Q Those were the likelihood of changes or the
15 changes?
16 A Both.
17 Q With respect to customers and the customer
18 allocation that you proposed in your direct testimony and
19 the rate shock issue, you indicated that two percent was
20 the rate shock threshold; is that correct?
21 A I didn't establish a threshold, but I did
22 say the two percent for the residential class would not
23 constitute rate shock.
24 Q Isn't it true that your filing in Oregon
25 has a 2.62 percent uniform percentage increase across
144
CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 classes?
2 A That is probably true. In Oregon we had an
3 existing surcharge in place that was for 2.62 percent
4 which we proposed cease and the DSM recovery begin at the
5 same expense and, therefore, there was no effective
6 change in rates and, obviously, no rate shock.
7 Q But your proposal here is different than
8 your proposal in Oregon and you're the witness in both
9 cases?
10 A Yes, and in this jurisdiction we are
11 actually proposing a rate increase; whereas, in Oregon,
12 we can recover the expenditures with no impact on rates.
13 Q With respect to the DSM measures, if at the
14 time that the DSM programs were instituted there was a
15 five-year amortization of the costs of those, would any
16 of those have been cost effective at that time?
17 A The cost effectiveness of the program I
18 don't know is necessarily tied to the revenue collection
19 for those expenditures on the part of the Company.
20 Q If I understand you, then, the time frame
21 for recovery has nothing to do with the value of the DSM
22 program?
23 A As we've mentioned, the DSM lives for the
24 customers actually having those measures in place have
25 effective lives that don't necessarily have to tie to the
145
CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 amortization period that is established for recovery.
2 Q But if you do not match the life of the
3 program with the life -- with the payment of the DSM
4 program, aren't you then shifting costs from one customer
5 to another customer; isn't that true?
6 A I believe there's definitely cost shifting
7 that goes on regardless of the recovery that you set up
8 since not all customers within a class reap the same
9 level of benefits from the programs and yet all are
10 expected to pay.
11 Q Isn't it true that at the time that the
12 programs were instituted the programs were looked at as a
13 deferral of the construction of other Company resources?
14 A That's true.
15 Q And isn't what you're proposing, then --
16 and that they would be paid for over a longer period of
17 time like Company resources?
18 A That's what the Commission ruled, yes.
19 Q I beg your pardon?
20 A That's what the Commission found.
21 MR. JAUREGUI: I have no further questions
22 at this time.
23 COMMISSIONER SMITH: Thank you,
24 Mr. Jauregui.
25 Mr. Ward.
146
CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 MR. WARD: My questions will be directed to
2 rebuttal. I have no questions.
3 COMMISSIONER SMITH: Mr. Gollomp.
4 MR. GOLLOMP: No questions.
5 COMMISSIONER SMITH: Mr. Fothergill.
6 MR. FOTHERGILL: Yes, I have a couple of
7 questions.
8
9 CROSS-EXAMINATION
10
11 BY MR. FOTHERGILL:
12 Q On page 12, lines 2 to 6 of your testimony,
13 Mr. Said, you've said that the DSM is currently viewed
14 from the perspective of the "ability to participate in
15 programs" and that's in opposition to what we've usually
16 thought that's a system resource and I was wondering, who
17 is viewing it that way?
18 A Well, obviously, the Company is in its
19 proposal. As I've mentioned in my testimony, I believe
20 that the Commission has recognized changes in planning
21 criteria, the regional approach as opposed to a system
22 look necessarily and as a result, it's my belief that
23 perhaps the Commission views it in this light as well.
24 Q I didn't catch that exactly. Is it your
25 belief that the Commission now views it that way?
147
CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 A I guess we'll find out when they rule, but,
2 yes, I envision that it might be.
3 Q In the testimony of David Bonn for FMC, he
4 indicates that with this kind of a classification, the
5 ability to participate in programs being the way to go,
6 these have now become social programs. Is that also your
7 opinion, that DSM now are social programs?
8 A I think they're certainly no longer viewed
9 purely as resource planning offsets.
10 Q Is your answer yes?
11 A I guess I don't know that they're solely --
12 I forget your term or Mr. Bonn's term -- social
13 programs. I don't know as I'd say that they're purely
14 social programs either. I've not contended that.
15 Q If they are social programs, don't we
16 usually finance such programs with the broadest possible
17 spectrum of the community participating in that, such as
18 Medicaid, AFUDC, unemployment insurance and such things?
19 A That's what we've proposed with the low
20 income weatherization assistance.
21 Q That's five percent of what we're talking
22 about. How about the generality of it?
23 MR. RIPLEY: Well --
24 COMMISSIONER SMITH: Mr. Ripley.
25 MR. RIPLEY: -- I'm going to have to
148
CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 interpose an objection simply because, again, I think
2 Mr. Fothergill is assuming facts that are not in the
3 record and I don't mean that simply as a technicality.
4 The programs that the Company is here requesting recovery
5 on have all been discontinued but ag choices, so if he's
6 asking what the Company views as far as the future is
7 concerned and yet is tying them to the DSM programs that
8 the Company has discontinued, I think he's confusing the
9 witness, so I think we need some predicates so that
10 Mr. Said can answer the questions. They're so vague and
11 general that it's difficult, I think, for the witness to
12 respond.
13 MR. FOTHERGILL: Let me put it a different
14 way.
15 Q BY MR. FOTHERGILL: What I'm talking about
16 here and what I'm asking you about is the decision to
17 allocate the expenses to customer classes on the basis of
18 their ability to participate and ability to participate
19 means that some people in that class will not
20 participate; would you agree with that?
21 A That's true.
22 Q So as Mr. Arms has pointed out in his
23 testimony for the Rate Fairness Group, some of these such
24 as if you had a DSM program for mobile homes, you would
25 expense these to all customers, all the customers, in the
149
CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 residential class; is that accurate?
2 A Under our proposal, yes.
3 Q Or, alternatively, to people who bought new
4 houses under your program; correct?
5 A We don't have that alternative.
6 Q Well, should it be as Mr. Arms says, should
7 it be such a thing as just people who bought new houses?
8 A I don't think from our records we would
9 have the ability to single those individuals out.
10 Q So what you propose is to charge,
11 regardless of whether people really have the ability to
12 participate, to charge the entire class for these
13 expenditures; true?
14 A We do view the individual classes as being
15 treated as a homogeneous group, yes.
16 Q Okay. Well, let's go to another subject
17 here. In your application, in the Company's application,
18 and in your testimony you've said that the principal
19 reason for your application and your testimony is to
20 accelerate the recovery expenditures for DSM. That's
21 accurate, is it not?
22 A For demand side management, yes.
23 Q Then in this case what objection would you
24 have to recovering these expenditures with a uniform
25 percentage rate as the Staff has indicated in its
150
CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 testimony?
2 A The principal reason for our proposal of a
3 new allocation method was based on knowledge of different
4 customer classes wondering about their cost
5 responsibility when they may not have had the ability to
6 participate in programs or having demand side management
7 programs that were all targeted towards one class or
8 another that was not theirs and rather than suggest that
9 we go in one fell swoop to allocating all of the demand
10 side management expenditures based on an ability to
11 participate, we proposed what we thought was more of a
12 middle-of-the-road approach where we would continue to
13 allocate those expenditures that had already been
14 approved in the past under the same allocation method
15 that had been used in the past and any expenditures that
16 had not already been approved and included in rates could
17 be allocated under the new proposed allocation method, so
18 it was kind of a blend of accepting the past for the past
19 and proposing something new for the new expenditures that
20 would be reviewed in the future.
21 Q It is a complicated way to get to two
22 percent, is it not?
23 A The two percent wasn't what drove the
24 allocation method if that's what you're implying.
25 MR. FOTHERGILL: Thank you.
151
CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company
1 That's all I have, Madam Chair.
2 COMMISSIONER SMITH: Thank you,
3 Mr. Fothergill.
4 Do we have questions from the
5 Commissioners?
6 COMMISSIONER NELSON: I will pass. Thank
7 you.
8 COMMISSIONER HANSEN: I have none.
9 COMMISSIONER SMITH: I just have one,
10 Mr. Said.
11
12 EXAMINATION
13
14 BY COMMISSIONER SMITH:
15 Q Did you look at other proposals, I mean
16 other time lengths, between 24 and five?
17 A Yes, we actually looked at just about every
18 possibility, probably more on the one- to ten-year frame
19 than the above ten, but we did look at those years.
20 Q So if I asked you what your rate proposal
21 would look like for a ten-year amortization, you could
22 give me that?
23 A We could certainly generate that
24 information. I don't know as we've retained what we had
25 as we were going along. We looked at the one- through
152
CSB REPORTING SAID (Com)
Wilder, Idaho 83676 Idaho Power Company
1 ten-year time frame before we had finalized all of our
2 numbers and I don't know that we recalculated the
3 individual years, but it's not a very complex process.
4 Q It wouldn't take long to do a number of
5 scenarios?
6 A No, we could do that.
7 COMMISSIONER SMITH: All right, thank you.
8 Mr. Ripley, do you have any redirect?
9 MR. RIPLEY: Yes, just a few.
10
11 REDIRECT EXAMINATION
12
13 BY MR. RIPLEY:
14 Q Counsel for the Industrial Customers asked
15 you a number of questions as to the life of the facility,
16 referring to the demand side management expenditure, for
17 a particular asset. Do you recall that?
18 A Yes.
19 Q Now, who owns that asset after it has been
20 installed and paid for by the Company?
21 A The individual who owns the facility that
22 the DSM equipment has been installed in.
23 Q So that it is the customer of Idaho Power
24 Company that owns that facility?
25 A That's correct.
153
CSB REPORTING SAID (Di)
Wilder, Idaho 83676 Idaho Power Company
1 Q Does that customer dictate how long that
2 facility will remain in existence?
3 A Yes.
4 Q Now, when you were looking at rate shock
5 and you were asked questions from the Industrial
6 Customers with reference to percentage increases, which
7 is more important, Mr. Said, the actual mill increase or
8 the percentage increase that you were looking at when you
9 were going to increase a customer's charges?
10 A I would say that the mill increase is
11 probably the more significant just from the standpoint
12 that if you start with a very low base rate and see an
13 absolute mill increase, you will come up with a larger
14 percentage than if you had that same absolute mill
15 increase for a higher beginning charge.
16 Q Now, in reference to the installation of
17 demand side management expenditures by the Company that
18 in essence is then given to the customer, do customers of
19 Idaho Power Company change from a physical standpoint?
20 They move away? They die? They go out of business?
21 A Yes, they do.
22 Q Now, if a particular customer has received
23 a DSM, has received the benefit of a DSM, expenditure
24 and, say, it's an industrial customer and after three
25 years that industrial customer goes out of business, who
154
CSB REPORTING SAID (Di)
Wilder, Idaho 83676 Idaho Power Company
1 has received the basic benefit of that expenditure during
2 the three-year period of time that the industrial
3 customer was in existence?
4 A The industrial customer that was in
5 existence for the three years.
6 Q Now, the longer the period of time that you
7 recover that DSM expenditure, does that place at risk the
8 fact that the customer that received the particular
9 benefit will not be the customer that pays for it?
10 A Yes, that's true.
11 Q Is that what you're referring to when you
12 say you have to look at the customer make-up and how it
13 changes?
14 A Yes. The Company proposal is essentially
15 trying to match the receiver of the benefit with, at
16 least in terms of the time frame with, the costs.
17 Q Now, does that become more important if the
18 Company has discontinued the DSM programs that it is now
19 attempting to recover the expenditures on?
20 A I'm sorry, would you repeat it, Larry?
21 Q Yes. If a customer of tomorrow, let's say,
22 comes on the system, he's new, and that customer is not
23 entitled to participate in a DSM program because it has
24 been discontinued, does that dictate to you the fact that
25 the period of time for the recovery of the expenditure
155
CSB REPORTING SAID (Di)
Wilder, Idaho 83676 Idaho Power Company
1 should be shortened?
2 A It does suggest that tomorrow's customers
3 may not have the ability to participate in programs that
4 existing customers have already had the opportunity to
5 participate in and yet will be saddled with some of the
6 cost burden.
7 MR. JAUREGUI: Madam Chairman, I can't hear
8 Mr. Said's answers.
9 COMMISSIONER SMITH: Well, Mr. Said, just
10 speak into that as best you can.
11 MR. RIPLEY: That's all the redirect we
12 have.
13 COMMISSIONER SMITH: All right.
14 (The witness left the stand.)
15 COMMISSIONER SMITH: Let's take a
16 ten-minute break right now and we'll go off the record.
17 (Recess.)
18 COMMISSIONER SMITH: All right, now we'll
19 try again. Okay, Mr. Ripley.
20 MR. RIPLEY: We call Mr. Obenchain.
21
22
23
24
25
156
CSB REPORTING SAID (Di)
Wilder, Idaho 83676 Idaho Power Company
1 PHIL A. OBENCHAIN,
2 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 DIRECT EXAMINATION
7
8 BY MR. RIPLEY:
9 Q Mr. Obenchain, would you please state your
10 name for the record?
11 A Phil A. Obenchain.
12 Q And did you have cause to be prepared for
13 this proceeding four pages of direct testimony?
14 A I did.
15 Q And also did you identify a multi-page
16 exhibit as RS1?
17 A I did.
18 MR. RIPLEY: Could we have that remarked as
19 Exhibit No. 11 for this proceeding?
20 COMMISSIONER SMITH: That would be very
21 good. We'll call that Exhibit 11.
22 Q BY MR. RIPLEY: And with the change in his
23 testimony to Exhibit No. 11, I would ask Mr. Obenchain,
24 you don't have any changes in the exhibit either?
25 A I do not.
157
CSB REPORTING OBENCHAIN (Di)
Wilder, Idaho 83676 Idaho Power Company
1 MR. RIPLEY: We would tender Mr. Obenchain
2 for cross-examination and request that his testimony be
3 spread upon the record as if read.
4 COMMISSIONER SMITH: Without objection, it
5 is so ordered. I would tell you, Mr. Ripley, I spent
6 some time trying to figure out what "RS" stood for since
7 I knew it wasn't Phil Obenchain.
8 MR. RIPLEY: Revenue sharing.
9 (The following prefiled testimony of
10 Mr. Phil Obenchain is spread upon the record.)
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
158
CSB REPORTING OBENCHAIN (Di)
Wilder, Idaho 83676 Idaho Power Company
1 Q. Please state your name and business
2 address.
3 A. My name is Phil A. Obenchain and my
4 business address is 1221 West Idaho Street, Boise, Idaho.
5 Q. By whom are you employed and in what
6 capacity?
7 A. I am employed by the Idaho Power Company as
8 an Senior Analyst in the Pricing and Regulatory Services
9 Department.
10 Q. Please describe your educational
11 background.
12 A. In May of 1979, I received a Bachelor of
13 Arts Degree in Economics from Boise State University in
14 Boise, Idaho.
15 In August of 1981, I attended the University of
16 Idaho at Moscow, Idaho to pursue a Masters of Science
17 Degree in Economics, with emphasis in Regulatory
18 Economics. I completed the necessary course work in the
19 spring of 1982.
20 Q. Please describe your professional
21 experience.
22 A. In January of 1983, I accepted a position
23 of Rate Analyst with Idaho Power Company. My duties as
24 Rate Analyst included the preparation of cost-of-service
25 information for use in the development of jurisdictional
159
OBENCHAIN, DI 1
IDAHO POWER COMPANY
1 separation studies and class cost-of-service studies.
2 More specifically, I am responsible for gathering and
3 analyzing data from various sources to carry out
4 cost-of-service analyses to determine the jurisdictional
5 revenue requirement in each of the four jurisdictions
6 regulating Idaho Power Company.
7 In 1994 I performed the jurisdictional separation
8 study which produced the Idaho jurisdictional revenue
9 requirement in Case No. IPC-E-94-5.
10 Q. What is the scope of your testimony in this
11 proceeding?
12 A. My testimony will identify the Idaho
13 jurisdictional revenue sharing amount for 1997.
14
15 /
16
17 /
18
19 /
20
21
22
23
24
25
160
OBENCHAIN, DI 1A
IDAHO POWER COMPANY
1 Q. Have you prepared or supervised the
2 preparation of an exhibit for this proceeding?
3 A. Yes, I have prepared or supervised the
4 preparation of Revenue Sharing Exhibit RS1. Exhibit RS1
5 is the Earnings Test Jurisdictional Separation Study for
6 the twelve months ending December 31, 1997.
7 Q. Is the methodology used to determine the
8 1997 Idaho jurisdictional earnings the same as that
9 utilized in previous compliance filings?
10 A. Yes. The 1997 Idaho jurisdictional
11 earnings test calculation follows the same methodology
12 established in prior earnings test compliance filings.
13 Q. Does the earnings test result in an Idaho
14 jurisdictional amount to be shared for 1997?
15 A. Yes. The total amount to be shared is
16 $15,143,891 which can be found on page 2 of 34, line 91,
17 of Exhibit RS1. As ordered by the Commission in Order
18 No. 26216 in Case No. IPC-E-95-11, Idaho jurisdictional
19 earnings above 11.75 percent of common equity are to be
20 shared equally between the shareholders of Idaho Power
21 Company and the Company's Idaho retail customers. The
22 customer revenue sharing amount of $7,571,946 is found on
23 page 2 of 34, line 92, of Exhibit RS1.
24 Q. Is this customer revenue sharing amount
25 less than earlier estimates indicated?
161
OBENCHAIN, DI 2
IDAHO POWER COMPANY
1 A. Yes it is. The final customer revenue
2 sharing amount is lower than the preliminary estimate.
3 The preliminary estimate was determined by allocating
4 total system year-end financial information to the Idaho
5 jurisdiction based on the 1996 test year's aggregated
6 jurisdictional allocation factors. The final revenue
7 sharing value, as determined by the 1997 Earnings Test
8 Jurisdictional
9
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
162
OBENCHAIN, DI 2A
IDAHO POWER COMPANY
1 Separation Study, allocates total system costs by each
2 FERC account utilizing current jurisdictional allocation
3 factors.
4 Q. Do you propose an adjustment to the
5 customer revenue sharing amount related to 1997 carrying
6 charges on deferred demand-side management ("DSM")
7 expenses.
8 A. Yes. I propose that the customer revenue
9 sharing amount be offset by $2,623,188 which is the
10 grossed-up amount of 1997 carrying charges on the DSM
11 deferred expenses for 1994 through 1997.
12 Q. Why is the 1997 carrying charge expense on
13 deferred DSM expenses grossed-up?
14 A. Last year, the Idaho Commission authorized
15 the use of customer revenue sharing dollars to pay the
16 Company's 1996 carrying charge on the deferred DSM
17 expenses. The Company is required to pay taxes on this
18 recovery amount and thus needs to collect from customers
19 an amount sufficient to cover the Company's tax liability
20 as well as the carrying charge amount. The Company
21 erroneously failed to include taxes in last years
22 computation. The carrying charge expense of $1,597,556
23 when grossed-up by the net-to-gross multiplier of 1.642
24 results in a $2,623,188 reduction to the customer revenue
25 sharing amount.
163
OBENCHAIN, DI 3
IDAHO POWER COMPANY
1 Q. Are there any additional adjustments to the
2 total customer revenue sharing amount?
3 A. Yes there are. The Rate Fairness Group was
4 awarded $5,400 of intervenor funding, plus interest, in
5 Order No. 27267, Case No. IPC-E-96-26. The total award
6 plus carrying charges that have been grossed-up by the
7 net-to-gross multiplier of 1,642, results in a $5,647
8 reduction to the customer sharing amount.
9
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
164
OBENCHAIN, DI 3A
IDAHO POWER COMPANY
1 Q. What is the net customer revenue sharing
2 amount after 1997 grossed-up DSM carrying charges and
3 intervenor funding are removed?
4 A. The total customer revenue sharing amount
5 is $4,943,111.
6 Q. What does the Company propose with regard
7 to this $4,943111 amount?
8 A. The Company has proposed that the
9 $4,943,111 be used as a reduction in the DSM revenue
10 requirement.
11 Q. Does this conclude your testimony?
12 A. Yes, it does.
13
14
15
16
17
18
19
20
21
22
23
24
25
165
OBENCHAIN, DI 4
IDAHO POWER COMPANY
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER SMITH: All right, I assume
4 he's ready for cross-examination.
5 MR. RIPLEY: Yes.
6 COMMISSIONER SMITH: Mr. Purdy, do you have
7 any questions?
8 MR. PURDY: No questions, Madam Chair.
9 COMMISSIONER SMITH: Mr. Budge.
10 MR. BUDGE: No questions.
11 COMMISSIONER SMITH: Mr. Richey.
12 MR. RICHEY: No questions at this time.
13 COMMISSIONER SMITH: Mr. Richardson.
14 MR. RICHARDSON: No questions,
15 Madam Chairman.
16 COMMISSIONER SMITH: Mr. Jauregui.
17 MR. JAUREGUI: No questions.
18 COMMISSIONER SMITH: Mr. Ward.
19 MR. WARD: No questions.
20 COMMISSIONER SMITH: Mr. Gollomp.
21 MR. GOLLOMP: No questions.
22 COMMISSIONER SMITH: Mr. Fothergill.
23 MR. FOTHERGILL: No questions.
24 COMMISSIONER SMITH: My goodness, we could
25 have done him before the break.
166
CSB REPORTING OBENCHAIN
Wilder, Idaho 83676 Idaho Power Company
1 Do we have questions from the Commission?
2 COMMISSIONER NELSON: I do not have any.
3 Thank you.
4 COMMISSIONER SMITH: There being no
5 questions, there can be no redirect.
6 Thank you for your help, Mr. Obenchain.
7 (The witness left the stand.)
8 COMMISSIONER SMITH: It looks like next
9 we'll have Dr. Power.
10
11 THOMAS MICHAEL POWER,
12 produced as a witness at the instance of the Idaho
13 Citizens Coalition, having been first duly sworn, was
14 examined and testified as follows:
15
16 DIRECT EXAMINATION
17
18 BY MR. FOTHERGILL:
19 Q For the record, would you please state your
20 name and your occupation?
21 A Yes, my name is Thomas Michael Power. I'm
22 a professor of economics and chairman of the economics
23 department at the University of Montana, but I'm
24 appearing here as an independent consultant on behalf of
25 the Idaho Citizens Coalition.
167
CSB REPORTING POWER (Di)
Wilder, Idaho 83676 Idaho Citizens Coalition
1 Q Are you the same Thomas Michael Power who
2 prepared 18 pages of testimony for filing in this
3 proceeding?
4 A Yes, I am.
5 Q Are there any changes you would want to
6 make in the written testimony that's been submitted?
7 A Yes, there's one that may affect the
8 meaning of the testimony. On page 3, line 13, I'm
9 referring to the utility, but I simply say "Idaho," so
10 line 13 should read, "Yes. In April of this year, Idaho
11 Power submitted its Conservation Plan...."
12 Q Do you have any other changes?
13 A Not that affect the meaning of the
14 testimony.
15 Q With this change, would your answers to the
16 questions be the same as they are in your written
17 testimony?
18 A Yes.
19 MR. FOTHERGILL: With this, we would ask
20 that his testimony be spread upon the record.
21 COMMISSIONER SMITH: Without objection, it
22 is so ordered.
23 MR. FOTHERGILL: And we would submit him
24 for cross-examination.
25 COMMISSIONER SMITH: I was just looking,
168
CSB REPORTING POWER (Di)
Wilder, Idaho 83676 Idaho Citizens Coalition
1 Mr. Fothergill, I believe what we ought to do with his
2 attachment is give that an exhibit number. I think for
3 the purpose of the transcript that would be clearer, so
4 can we call that Exhibit 701?
5 MR. FOTHERGILL: The qualifications?
6 COMMISSIONER SMITH: Yes, he called it
7 Appendix A.
8 MR. FOTHERGILL: All right. Well, let's
9 see if I can find it and you'd rather that be
10 Exhibit 701?
11 COMMISSIONER SMITH: If you don't mind.
12 MR. FOTHERGILL: No, we don't mind and so
13 with the 15 pages of testimony and Exhibit 701, we would
14 ask that that be spread upon the record.
15 COMMISSIONER SMITH: So ordered.
16 (The following prefiled testimony of
17 Mr. Thomas Michael Power is spread upon the record.)
18
19
20
21
22
23
24
25
169
CSB REPORTING POWER (Di)
Wilder, Idaho 83676 Idaho Citizens Coalition
1 DIRECT TESTIMONY OF THOMAS MICHAEL POWER
2
3 1. Introduction, Qualifications and Outline
4 Q Please state your name and occupation.
5 A My name is Thomas Michael Power. I am
6 Professor of Economics and Chairman of the Economics
7 Department at the University of Montana, Missoula,
8 Montana, 59812. I am appearing in these proceedings,
9 however, as an independent consulting economist on behalf
10 of the Idaho Citizens Coalition.
11 Q Have you previously testified before this
12 and other regulatory commissions as an expert witness?
13 A Yes. I have testified before this
14 Commission on numerous occasions in the past. I have
15 also testified before federal and state regulatory
16 commissions throughout the country on more than
17 seventy-five occasions. A brief summary of my
18 professional experience and training is attached as an
19 Appendix A to this testimony.
20 Q What issues will you address in your
21 testimony?
22 A My testimony will deal with the following
23 topics:
24 a. The appropriateness of reducing the
25 amortization period for DSM to five years.
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1 b. The appropriate adjustment of DSM financing in
2 the light of increasing competition in the electric
3 utility industry.
4 c. The appropriateness of collecting DSM costs
5 from specific customer "beneficiaries."
6 Q Can you summarize your conclusions and
7 recommendations?
8 A Yes. Let me simply list the conclusions
9 that follow from the analysis that is provided in my
10 testimony below.
11 i. The Commission should not approve the
12 reduction of the DSM amortization period from 24 years to
13 5 years. The 24 year amortization
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1 period almost perfectly matches the expected life of the
2 DSM investments that Idaho Power reported to the
3 Commission in April of this year.
4 ii. To the extent that the combination of
5 deferrals and amortization does not exceed the expected
6 lives of the DSM investments, a reduction in the
7 amortization period to match those expected lives would
8 be appropriate.
9 iii. Given the changed size and nature of Idaho
10 Power's ongoing DSM expenditures, it may be appropriate
11 to begin expensing current and future DSM expenditures.
12 iv. Increased electric supply competition does
13 not threaten the value or recovery of Idaho Power's DSM
14 regulatory assets. There are regulatory arrangements
15 that are consistent with electric supply competition that
16 can assure the recovery of the DSM investments if that is
17 the appropriate regulatory outcome.
18 v. The potential for electric supply competition
19 should not be used to raise customers' rates before those
20 customers are given access to any of the benefits of that
21 competition. In particular, the collection of positive
22 stranded costs that burden customers should not be
23 approved before the offsetting negative stranded costs
24 that would benefit customers are taken into account.
25 vi. The allocation of DSM costs among customers
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1 should not be changed from the demand and energy
2 allocator to a DSM-beneficiary basis. To do so changes
3 the rules of the game retroactively and leads to absurd
4 and unfair results.
5
6 2. The Appropriate Amortization Period for DSM Investments
7
8 Q What justification does Idaho Power present
9 for shortening the amortization of DSM investments from
10 24 years to five years?
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1 A Almost none. Idaho Power says that changes
2 in the electric utility industry make a shortening of the
3 amortization period necessary and says that Mr. Said came
4 up with the proposed five year period by using his
5 judgment. Idaho Power does not specify what changes in
6 the electric utility industry make this change necessary
7 nor how an analysis of those changes supports a five year
8 amortization of DSM investments. In that sense, Idaho
9 Power has provided absolutely no evidence in support of
10 its proposal. It simply asserts what it wants and goes
11 no further than stating that wish.
12 Q Has Idaho Power recently provided evidence
13 to the Commission that directly indicates the appropriate
14 amortization period for DSM investments?
15 A Yes. In April of this year, Idaho Power
16 submitted its Conservation Plan to the Commission. That
17 Conservation Plan indicates the expected lives of the
18 various DSM measures in which IPC has invested since
19 1989. Those expected lives and the Idaho DSM
20 expenditures are found in Appendix C, Data Tables,
21 pp. 7-9 of the 1998 Conservation Plan. The table below
22 reproduces that data in summary form.
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9 (Chart can be found in the Transcript.)
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1 Q In the 1998 Conservation Plan, what did
2 Idaho Power recently report to the Commission as the
3 expected life of its DSM investments?
4 A The expected lives associated with the
5 various Idaho DSM programs varied from 10 years to 30
6 years. If one weights the expected life by the number of
7 dollars spent on each program, the weighted average life
8 of an Idaho Power DSM investment in Idaho is about 23
9 years as shown in the table above. That average life is
10 very close to the 24 year amortization period now being
11 used for DSM investments in Idaho.
12 Q Does Idaho Power argue that the expected
13 life of its DSM investments is only five years?
14 A No. When asked by the Industrial Customers
15 of Idaho Power Company (ICIPC) if Idaho Power had any
16 studies indicating that the DSM investments would "become
17 physically obsolete and useless" or "technologically
18 obsolete and useless" or "economically obsolete and
19 useless" in less than 24 years, Idaho Power responded
20 that it was not claiming any of those things about the
21 lives of its DSM investments. (ICIPC Data Requests 2, 3,
22 and 4)
23 Q If the DSM investments did have only five
24 year useful lives, would this have implications for
25 whether Idaho Power should be allowed to recover the DSM
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1 costs?
2 A Absolutely. If Idaho Power invested in
3 these measures expecting a ten to thirty year useful life
4 but was only able to achieve a five year useful life, the
5 Idaho Power DSM programs must have been badly designed
6 and implemented. The measured cost effectiveness of
7 programs that turned out to only have a five year useful
8 life would be very, very low. Such gross failure of a
9 company investment program would justify serious
10 financial penalties being imposed on Idaho Power.
11 Q What is the standard utility practice when
12 it comes to recovering utility investments in rates?
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1 A The standard practice is to recover those
2 capitalized investment costs over the expected useful
3 life of the equipment or facility. This allows the
4 collection of the costs to be timed to match the
5 realization of the benefits. If the recovery of the
6 costs is not timed in this way, there is a timing
7 mismatch.
8 Q But Idaho Power has claimed that when
9 lengthy amortization periods are used the cost of the
10 equipment or facility to customers is significantly
11 raised. Is this true?
12 A No, except in some financially and
13 economically naive sense. This is like saying that
14 because the investment cost of the Valmy facility is
15 being collected over the life of the facility, customers
16 are being forced to pay more for the electricity than if
17 the plant had been expensed as it was built. If
18 capitalizing and amortizing investments raises costs,
19 then cost minimization would require that we operate in a
20 world without capitalization of investments. It is hard
21 to imagine a modern economy operating on that basis.
22 Capitalization and amortization raises costs to
23 customers only if you assume that there is no time value
24 of money for customers, that a dollar paid out today is
25 seen as the equivalent of a dollar paid out in thirty
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1 years. We know that this is not the case. Households
2 and businesses have significantly positive internal
3 discount rates: A dollar today is worth significantly
4 more than a dollar thirty years from now. For households
5 this is especially the case. The 15 to 20 percent
6 interest rates that households pay on their credit card
7 balances clearly indicates the time value of money to
8 them. For Idaho Power to raise customers' rates now so
9 that it can save those customers a nine percent carrying
10 charge is not to do those customers a favor. Such a
11 tradeoff leaves customers worse, not better off.
12 Q What conclusion do you reach from this
13 analysis?
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1 A Normal regulatory treatment of these DSM
2 investments supports the capitalization and amortization
3 over 24 years that is currently being used. Idaho Power
4 has provided no evidence that conflicts with this. In
5 fact, it has recently submitted evidence to this
6 Commission that supports the 24 year amortization period.
7 If the Commission wants to fine tune the amortization, it
8 could have the amortization match the projected life of
9 each program's investments. Those programs with a ten
10 year life would be amortized over ten years; those with a
11 30 year life would be amortized over 30 years, etc. The
12 Commission may also wish to take into account the
13 relatively long deferral period caused by the infrequent
14 rate cases. If DSM investments are deferred for five
15 years and only then amortized for ratemaking purposes,
16 the effective amortization period may exceed the expected
17 life of the measures. Some adjustment of the
18 amortization period may be appropriate to correct this.
19
20 3. The Impact of an Increasingly Competitive Electric
21 Utility Industry
22 Q Idaho Power seems to be arguing that
23 because the electric utility business is becoming more
24 competitive customers' rates have to be raised. Is this
25 what the advocates of competition usually suggest about
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1 the impact of competition?
2 A No. Competition is supposed to bring
3 customers lower rates overall, not higher rates. What
4 Idaho Power is trying to do in this case is protect
5 itself against the dangers of competition while it not
6 only does not offer customers any of the benefits of
7 competition but it also raises customers' rates to fund
8 that protection from competition for itself. This is
9 likely to leave customers more than a little cynical
10 about electric industry restructuring.
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1 Q In your discussion above you have ignored
2 one of the main points that Idaho Power has made: The
3 electric utility business is changing and DSM financing
4 has to adjust to meet those changes. Why have you not
5 focused upon that concern?
6 A Because Idaho Power has not explained what
7 it is talking about. That makes it very hard to respond
8 or discuss appropriate policy. I suspect Idaho Power is
9 relatively silent on this issue, relying instead on
10 general "hints" and "suggestions" because to discuss
11 competitive pressures directly would cast the issue in
12 "stranded cost" terms and reduce the likelihood of Idaho
13 Power obtaining the accelerated amortization that it
14 seeks in this case.
15 Q How can we clarify what the competitive
16 issue is when it comes to DSM investments?
17 A One can turn to recent Commission orders
18 for one expression of those concerns. The Commission,
19 apparently, feels more confident spelling out the issue
20 than Idaho Power does.
21 Last July the Commission, in discussing the costs
22 of Idaho Power's participation in the Northwest Energy
23 Efficiency Alliance, expressed the concern that almost
24 certainly lies behind Idaho Power's current application:
25 "...the restructuring of the electric industry had
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1 begun and it was well known that Idaho Power,
2 along with all other investor-owned utilities, was
3 becoming increasingly concerned about the future
4 recovery of its regulatory assets, especially its
5 capitalized and deferred investment in
6 conservation." (Order No. 27045, p. 4)
7 Q Is this a legitimate concern when it comes
8 to DSM investments?
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1 A That depends upon whether retail electric
2 competition is going to be allowed in Idaho and the
3 arrangements that are made to facilitate and control the
4 impact of that retail competition.
5 DSM investments are "regulatory assets," meaning
6 that their recovery relies upon the continuation of some
7 type of regulation that imposes upon customers the
8 obligation to make payments for these DSM investments.
9 In addition, those payments for DSM have to be collected
10 from customers in a way that is not undercut by a
11 competitive commodity market. If, for instance, a
12 utility tried to collect them in the charge for electric
13 commodity where retail electric supply competition was
14 allowed, market pressures would eliminate either the DSM
15 charge or the sales that would have contributed to paying
16 the DSM costs.
17 It is possible to imagine scenarios where DSM
18 investment costs cannot be recovered because of the ways
19 in which the electric industry and regulation have
20 changed. It is just as easy, however, to specify a
21 regulatory structure that assures recovery of the DSM
22 investments.
23 Q Is increased electric supply competition
24 likely to strip Idaho Power of the regulatory protection
25 that assures the value of its regulatory assets?
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1 A No. The competition that is being
2 discussed in the electric industry is largely competition
3 among electric suppliers for customers. Almost no
4 observers expect the transmission and distribution system
5 to be deregulated and left to competitive markets.
6 Almost all utility analysts expect distribution and
7 transmission to remain "natural monopolies" regulated by
8 state and federal agencies. Electric restructuring is
9 more appropriately labeled "re-regulation" rather than
10 deregulation. Because regulation of Idaho Power's
11 distribution and transmission systems is almost a
12 certainty, the value of Idaho Power's regulatory assets
13 can continue to be protected.
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1 Q If markets in the future will dictate the
2 price that customers pay for electric commodity, how can
3 regulators assure that those prices will allow Idaho
4 Power to recover its DSM investments?
5 A In retail electric markets open to electric
6 supply competition, DSM recovery should not be tied to
7 market determined commodity charges. Instead, DSM
8 recovery should take place through the distribution and
9 transmission charges that remain regulated. DSM
10 investments would be recovered through non-bypassable
11 wires charges that all of Idaho Power's current customers
12 would be required to pay regardless of from whom they
13 purchase their electric supply. That arrangement assures
14 ongoing regulatory protection of that recovery and
15 assures that competition does not block the recovery.
16 Q If the accelerated amortization being
17 recommended for DSM were applied to other Idaho Power
18 investments, would it also lead to inappropriate results?
19 A Yes. Assume, for instance, that during the
20 late 1980s when the south Idaho boom got under way, Idaho
21 Power had invested in a generating facility that had
22 total embedded generation costs of 3.5 cents per kwh so
23 that adequate electric energy would be available in south
24 Idaho at a reasonable cost. Given that coal-fired plants
25 had been built in the 1980s with embedded costs of about
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1 5 cents per kwh, such a facility might have looked like a
2 good deal. Assume also that as of 1998, electric energy
3 was available at market rates of 1.5 to 2.5 cents per
4 kwh. "In an increasingly competitive electric industry,"
5 the new 3.5 cent facility might begin to look uneconomic.
6 In that setting Idaho Power might worry about the future
7 recovery of its investment in that facility. Following
8 the logic of what is being proposed in this case, Idaho
9 Power could propose to accelerate recovery of the
10 investment in that generating facility from 30 years to 5
11 years. I am absolutely certain
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1 that this Commission would never seriously consider such
2 a proposal. It should not do so for the DSM investments
3 either.
4 Q What conclusion do you reach from the above
5 analysis?
6 A The possibility that Idaho may at some
7 point open its electric retail markets to competitive
8 electric supply should not be used to justify the
9 accelerated amortization of DSM investments. There are
10 regulatory arrangements readily available to assure the
11 recovery of these investments over the existing
12 amortization periods. The recovery of DSM investments
13 are not threatened by the changes taking place in the
14 electric utility industry.
15 Q Are you recommending that such a
16 non-bypassable DSM charge be established at this time?
17 A No. Idaho has not authorized electric
18 retail competition and it may not do so in the immediate
19 future or ever. If and when Idaho seeks to accommodate
20 some degree of electric retail competition, DSM
21 investments will be only one category of utility
22 investments and regulatory assets that have to be
23 evaluated. There are many others. Taken collectively,
24 the evaluation of these past utility costs has come to be
25 labeled "stranded cost" analysis. Just as Idaho Power
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1 insists that it has a right to recover its DSM
2 investments no matter what changes take place in the
3 electric utility industry, Idaho Power's customers will
4 insist that they have a claim on any above book asset
5 value associated with the generating facilities that
6 Idaho Power purchased or constructed under regulation.
7 In addition, there are QF contracts, deferred taxes, and
8 other costs to be taken into account. One cannot take
9 these potential stranded costs one at a time and make a
10 decision about their recovery. An overall analysis of
11 all above and below market costs is required. Effective
12 mitigation of these costs by the utility has to be
13 demanded. Only then can a decision be made about
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1 what, if any, stranded costs are appropriately collected
2 from customers. Until that type of rigorous stranded
3 cost analysis is carried out, it would be inappropriate
4 to specify the equivalent of DSM stranded costs and
5 authorize recovery of them. To do so would be to focus
6 on the above-market costs that potentially will burden
7 customers while ignoring the benefits of below-market
8 costs on which customers have a claim.
9 Q Does that mean that you oppose all changes
10 in how DSM investments are recovered?
11 A Not necessarily. Idaho Power has been
12 significantly reducing its DSM expenditures on its own
13 system and shifting dollars towards a regional effort,
14 the Northwest Energy Efficiency Alliance that was the
15 subject of hearings before this Commission last year.
16 The Manufacture Home Acquisition, Partners in Industrial
17 Efficiency, Design Excellence Award, Commercial Lighting,
18 and Agricultural Choices programs are all being
19 terminated in Idaho. That will leave a reduced Low
20 Income Weatherization Program and the Northwest Energy
21 Efficiency Alliance as the primary remaining DSM
22 programs. The total annual Idaho jurisdictional cost of
23 ongoing DSM programs may be about one million dollars
24 compared to as much as $5.8 million in years past (1994).
25 It is possible that at the reduced level of
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1 spending, future DSM expenditures could be expensed
2 annually rather than being deferred and capitalized. Low
3 income weatherization is not just a DSM resource
4 acquisition program. It is also heavily a social program
5 aimed at making household energy services affordable to
6 low income households. The NEEA is likely to be engaged
7 in a mix of relatively short term activities including
8 public education, research and development, and marketing
9 as well as initial subsidization of new technologies. In
10 both cases, the money being spent is not solely or
11 primarily investments in resource acquisition. That
12 change in the focus
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1 of the remaining DSM programs may also justify a shift to
2 annual expensing of these costs. Such a shift, of
3 course, would allow the Commission and Idaho Power to
4 avoid the deferral and capitalization of costs on a going
5 forward basis. The deferral and capitalization of costs
6 is something the Commission has expressed some concern
7 about and has acted to try to reduce through the use of
8 the revenue sharing amounts to offset DSM carrying
9 charges (Order No. 26925, p. 4).
10 Q Have you attempted to estimate the impact
11 on rates if this change were implemented for the current
12 and future cost of the ongoing DSM programs?
13 A No, I have not. If the immediate impact
14 were to be substantial, that would counsel for caution in
15 moving in this direction.
16 Q Given that Idaho Power does not have annual
17 rate cases and that this Commission has always insisted
18 in reviewing DSM expenditures before they were granted
19 ratemaking treatment, how could the expensing of DSM
20 costs be implemented?
21 A I am not a utility accountant, so I cannot
22 answer that in any detail. I see two possibilities. The
23 first is that the Commission take a close look at the
24 remaining DSM programs and assure itself that those
25 programs are well run and appropriately pursuing public
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1 purposes. It could then authorize a rate increase to
2 cover an approved annual level of expenditure on these
3 programs. This would not be much different than the
4 inclusion of other test year expenditures in the
5 utility's revenue requirement. The utility would be
6 expected to continue expenditures at that level in
7 between rate cases.
8 Alternatively, the Commission could authorize a
9 rate increase to cover the annual expected level of
10 ongoing DSM expenditures, but these revenues would go
11 into a DSM account along with the utility's deferred
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1 DSM costs until the next rate case. At that time the
2 Commission could review the DSM programs and expenditures
3 and authorize utility recovery of its DSM expenditures
4 from that account. If rates had to be adjusted upward or
5 downward because of changes in DSM program expenditures,
6 that could also be done at that time.
7 4. Changing the Allocation of DSM Costs Among Customer
8 Classes
9 Q Idaho Power is proposing that the
10 allocation of DSM costs among customers be changed for
11 those DSM investment that took place after 1993. Mr.
12 Said proposes that these post-1993 DSM costs "be
13 allocated based upon the ability of the customer class to
14 participate in programs" (p.11 at 19). Do you agree?
15 A Absolutely not.
16 Q What justification does Mr. Said give for
17 this shift in the allocation of these costs among
18 customer classes?
19 A All he offers is the assertion that "DSM is
20 currently viewed from the perspective of the direct
21 benefits (i.e., ability to participate in programs) that
22 customers receive from expenditures made on their
23 behalf." (Said, p. 12 at 3) He does not specify who
24 views it that way or when they started viewing it that
25 way. He cites no sources in support of that assertion.
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1 A data request to Idaho Power (ICC No. 5) seeking
2 citations to Commission orders, regional authorities,
3 past Idaho Power policy statement, etc. that would
4 support this assertion resulted in no additional evidence
5 or citations. In that sense, Mr. Said's assertions and
6 proposal are completely unsupported by any evidence.
7 Q What is the justification of allocating DSM
8 investments to classes based upon their electric usage?
9 A The DSM investments were resource
10 acquisition investments that sought to pursue the most
11 cost effective sources of additional electric supply.
12 For that reason, the DSM investment costs have been
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1 allocated to customer classes in approximately the same
2 way that other electric supply costs are allocated.
3 Q What is the impact on different classes of
4 customers of Idaho Power's proposal to shift from a
5 demand and energy allocator to a potential beneficiary
6 basis?
7 A The share of the DSM costs assigned to the
8 residential class increases by 50 percent and that to the
9 irrigation class increases by 67 percent. For most other
10 customer classes, their responsibility for the DSM
11 investments is cut in to a half or a third of what it
12 otherwise would have been.
13 Q Why do you object to this change in the
14 basis of the cost allocation from a demand and energy
15 allocator to a "potential class benefit" allocator?
16 A First, four years after some of these
17 program costs were incurred, Idaho Power is proposing to
18 retroactively change the allocation. This amounts to
19 retroactively changing the rules of the game. When those
20 costs were incurred, there was a clear expectation by
21 customers about how those costs would be collected from
22 customers. For the utility, based on its current
23 subjective judgment, to cast backward and change the
24 allocation formula is simply inappropriate. It comes
25 close to breaking faith with its customers.
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1 In addition, the proposed new allocation would
2 lead to absurd results if applied to individual programs.
3 For instance, it would call for low income customers to
4 pay for the Low Income Weatherization Program. It would
5 recommend that only those customers living in
6 manufactured housing pay for the manufactured housing
7 program. In fact, carried to its logical conclusion, it
8 would call for those customers on whose property DSM
9 investments were made to pay for the DSM themselves. If
10 the new principle is that those who get the "direct
11 benefits" pay for
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1 the DSM, we should be going back to all of those
2 customers who got the direct benefit of the DSM
3 investment and retroactively billing them for those DSM
4 measures. Clearly the new allocation principle being
5 proposed by Idaho Power is not reasonable. It leads to
6 absurd and unfair results. The allocation formula that
7 was assumed at the time the investments took place should
8 continue to be used.
9 Q Does this conclude your prefiled direct
10 testimony?
11 A Yes, it does.
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1 (The following proceedings were had in
2 open hearing.)
3 MR. FOTHERGILL: And we submit the witness
4 for cross-examination.
5 COMMISSIONER SMITH: Mr. Gollomp, do you
6 have any questions?
7 MR. GOLLOMP: No questions.
8 COMMISSIONER SMITH: Mr. Ward.
9 MR. WARD: No questions.
10 COMMISSIONER SMITH: Mr. Jauregui.
11 MR. JAUREGUI: No questions.
12 COMMISSIONER SMITH: Mr. Richardson.
13 MR. RICHARDSON: No questions, Madam Chair.
14 COMMISSIONER SMITH: Mr. Richey.
15 MR. RICHEY: No questions.
16 COMMISSIONER SMITH: Mr. Budge.
17 MR. BUDGE: No questions.
18 COMMISSIONER SMITH: Mr. Purdy.
19 MR. PURDY: No questions.
20 COMMISSIONER SMITH: Mr. Ripley.
21 MR. RIPLEY: Yes, Dr. Power, just a few.
22
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1 CROSS-EXAMINATION
2
3 BY MR. RIPLEY:
4 Q If you could direct your attention to
5 page 8 of your prepared testimony.
6 A Yes.
7 Q On line 4 you refer to the fact that DSM
8 investments are regulatory assets.
9 A Yes.
10 Q Meaning that their recovery relies upon the
11 continuation of some type of regulation; is that a
12 correct paraphrasing?
13 A Yes.
14 Q Based upon your experience in the
15 regulatory field, how does the accounting industry look
16 at regulatory assets, do you know?
17 A Yes. Well, I'm not an accountant, so I'm
18 speaking from some distance, but in terms of a variety of
19 hearings in various jurisdictions, regulatory assets that
20 involve delayed recovery of utility expenditures in
21 general as I recall the standards need to be recovered,
22 first of all, there has to be a very definite statement
23 by the commission that they are recoverable and then the
24 limit is that they be recovered within a 10-year time
25 frame.
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1 Q Now, when you talk about the delayed
2 recovery, is that the fact that the accounting industry
3 looks at the expenditures as being expenses unless the
4 regulatory agency defers the recovery of that expense?
5 A I should be careful in what I profess to
6 know in those terms. What's at issue are assets created
7 by the regulatory process where the utility does not have
8 a physical asset itself that it could sell or its
9 bondholders could sell in order to recover their original
10 investment. We're talking about an expense that's been
11 capitalized or that the utility is trying to capitalize.
12 I shouldn't really say anything more than that I don't
13 think.
14 Q But it's your understanding from your
15 testimony and also I assume from your experience and I'll
16 only ask your own opinion and judgment, the only reason
17 that DSM expenditures are regulatory assets is because
18 the Commission has stated that it will permit the
19 recovery of those expenditures over a period of time?
20 A Yes, exactly.
21 Q And if Idaho Power Company were not
22 regulated and it made these expenditures, it would simply
23 expense them in the year that it incurs those costs?
24 A Well, I'm not sure that businesses never
25 accumulate expenses and amortize them, but there's a much
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1 shorter time frame that accountants are willing to accept
2 in that sort of setting, but in general, it certainly
3 would be, any amortization would be, over a much briefer
4 period of time.
5 Q Now, again in your testimony on page 8, you
6 point out that the regulatory asset itself is dependent
7 upon the fact that the regulator will permit the recovery
8 of that expenditure.
9 A Yes, sir.
10 Q Now, is it the position of the Idaho
11 Citizens Coalition that Idaho Power Company should
12 recover its demand side management expenditures that it
13 has accrued and is the subject matter of this proceeding?
14 A If these are cost-effective investments
15 that were prudently made, my position is that they should
16 be recoverable.
17 Q So really all that we're arguing about in
18 this proceeding from your perspective is who should pay
19 to permit the utility to recover those expenditures?
20 A Well, that was my position coming in, but
21 this morning I've been very confused by the Company's
22 testimony. As I understood it, the verbal testimony
23 given this morning was that the utility now doubts that
24 from a system point of view there are any benefits or
25 only short-term benefits associated with these DSM
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1 investments, that although there may be benefits to the
2 individual households or businesses in which these
3 investments were made, there are no system benefits. If
4 that's the case, that raises a serious question that I
5 didn't think was at issue in this case as to whether
6 these investments were cost effective, are cost-effective
7 investments. I'm somewhat confused as to what the
8 Company's current position is about the legitimacy of
9 these as systemwide investments.
10 Q All right, but coming in at least into this
11 proceeding, it was your position, as I understand it from
12 your testimony, that really all that was at issue is who
13 should pay for the accumulated DSM expenditures?
14 A Yeah, the time period over which they
15 should be collected which is a matter of who and when
16 they should be paid for as well as then how those costs
17 should be allocated across customer classes.
18 Q But, again, that all goes back to the same
19 issue and that is who should pay for the recovery of that
20 DSM expenditure by the utility?
21 A Yes.
22 Q How you allocate it, who pays for it, that
23 all boils down to the same issue?
24 A Well, the Company has divided it between
25 the length of the amortization period and the allocation
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1 of the costs across customer classes. I think that's a
2 useful division that it helps clarify. To stick to that
3 division, one could try to reduce it to just who is going
4 to pay for it, but I think that stirs two quite separate
5 questions together.
6 Q What are those two separate questions?
7 A One is the time period over which those
8 costs are going to be collected and, as I say, you could
9 say that's only a matter of who, but it really isn't. I
10 mean, it's a matter of how intensively, if you want,
11 those investments are going to be collected by the
12 Company from customers, and then the other question is
13 the allocation across classes of customers.
14 Q And as you point out, any customer that has
15 his choice between paying something now or deferring it
16 will select to defer it?
17 A As long as the carrying cost is reasonable,
18 yes.
19 Q Now, if the customer thinks that it's a
20 good idea to defer it as long as possible, then,
21 conversely, that must not be a very good idea for the
22 utility.
23 A No, I don't think that's the case.
24 Although utilities sometimes forget it, they do operate
25 in a market and they do have customers whose demand is
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1 elastic, customers who have alternatives, so rate
2 increases aren't necessarily an unmixed blessing for the
3 utility. They tee off their customers, they discourage
4 use, they may lead to the loss of customers, so I think
5 the utility also, as Mr. Said said this morning, is
6 concerned about rate shock, not just because it's
7 good-hearted, but because rate shock is a very real
8 business concern.
9 Q So you'd agree with Mr. Said that we should
10 look at the impact of the proposal on the particular
11 customers?
12 A Impact is definitely important, has always
13 been in regulation.
14 Q Have you read any of the testimony of any
15 of the other witnesses?
16 A Yes, I have.
17 Q Have you read the testimony of Mr. Bonn for
18 FMC?
19 A Yes.
20 Q Now, Mr. Bonn urges that because of a
21 change in the contract between Idaho Power and FMC that
22 FMC's obligation to pay for previously incurred DSM
23 programs should be reduced. Do you think that's a fair
24 paraphrase of his position as you understand it?
25 A Yes. I think he was keying off Idaho
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1 Power's position that it's ability to benefit from the
2 program that should determine the allocation of costs and
3 given a change in the contract limited their ability to
4 benefit from the system benefits of DSM, they shouldn't
5 have to pay for that part.
6 Q Now, that same argument could be used by
7 any large customer of Idaho Power Company if it changed
8 its method of operating, reduced its consumption and
9 decided to internally generate power or whatever, would
10 that be accurate? That same customer could come in and
11 say I do not want to pay for the previously incurred
12 expenditures of DSM because now I can demonstrate that
13 I'm not benefiting as much, does that follow?
14 A Well, yes, but that would be true not just
15 of large customers, any customer that reduced their
16 consumption given the way in which, given that these are
17 allocated on the basis of demand and energy, any customer
18 that reduced their usage, their electric usage, would
19 avoid some of the costs associated with those DSM
20 programs. That's just the nature of the way in which
21 we're collecting those resources and I don't know how the
22 DSM responsibility that the Commission has decided that
23 FMC has, how that is collected.
24 In theory, as I understand what the
25 Commission has been trying to do, those DSM expenses or
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1 costs have been collected as if these were costs
2 associated with generating facilities. If FMC has part
3 of its load interruptible, I assume that typically it's
4 forgiven some of the fixed costs associated with
5 generation. If one was being completely symmetrical here
6 in how DSM was being handled, I would assume that FMC
7 would avoid some of the DSM costs, too, but the
8 arrangement may not be symmetrical in that way.
9 MR. RIPLEY: That's all the questions that
10 I have. Thank you, Doctor.
11 COMMISSIONER SMITH: Do we have questions
12 from the Commissioners?
13 COMMISSIONER HANSEN: No.
14 COMMISSIONER NELSON: I don't.
15 COMMISSIONER SMITH: Dr. Power, I just had
16 one.
17
18 EXAMINATION
19
20 BY COMMISSIONER SMITH:
21 Q On page 5 of your testimony at the top, you
22 talk about the standard practice of recovering these
23 investment costs over the expected useful life and I'm
24 curious whether you have any familiarity with what other
25 state public utilities commissions have done with this
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1 issue and any idea of how many years they're using to
2 amortize or how they've dealt with it.
3 A Well, I think in recent years commissions
4 have been moving towards shorter periods of amortization
5 or no amortization at all, simply expensing DSM, but
6 there's a difference between what those states have been
7 doing, including Montana, which went from useful life to
8 ten years to expensing over the last four years in the
9 sense that they've done that on a going forward basis,
10 not a casting backward basis, so that DSM that had
11 already been approved and was already, the amortization
12 period had already been set or measures already, adopted
13 that the utility had already invested in, the previous,
14 whatever previous rule applied to that and it was only on
15 a going forward basis that the rules have changed.
16 Now, Idaho is in a somewhat unusual
17 circumstance here given the lengthy deferral that leaves
18 a significant chunk of DSM that the Commission hasn't
19 ruled on yet. The other, the pre-'94, the Commission
20 has ruled on. There is a useful life basis for the
21 amortization period. I'm not aware of states that have
22 gone back and changed those amortization periods, so
23 there is something significantly different about what is
24 being proposed here.
25 Idaho Power isn't just proposing on a going
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1 forward basis we should be using five years or we should
2 be using expensing. There might be general agreement in
3 this room if that's what was being proposed, but
4 something quite different is being proposed here.
5 COMMISSIONER SMITH: Okay, thank you.
6 Do you have redirect Mr. Fothergill?
7 MR. FOTHERGILL: No, we have no redirect.
8 Thank you.
9 COMMISSIONER SMITH: Thank you for your
10 help, Dr. Power.
11 (The witness left the stand.)
12 COMMISSIONER SMITH: Dr. Peseau.
13 MR. RICHARDSON: Madam Chairman, the
14 Industrial Customers of Idaho Power call Dr. Peseau to
15 the stand.
16 COMMISSIONER SMITH: Thank you,
17 Mr. Richardson.
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1 DENNIS PESEAU,
2 produced as a witness at the instance of the Industrial
3 Customers of Idaho Power, having been first duly sworn,
4 was examined and testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MR. RICHARDSON:
9 Q Dr. Peseau, will you please state your name
10 and business address for the record, please?
11 A Yes. My name is Dennis is E. Peseau,
12 P-e-s-e-a-u. My business address is 1500 Liberty
13 Street SE, Salem, Oregon.
14 Q By whom are you employed and in what
15 capacity?
16 A I'm the president of Utility Resources,
17 Inc.
18 Q Are you the same Dr. Peseau who caused
19 prefiled testimony and exhibits marked 501 and 502 to be
20 prepared and filed in this case?
21 A Yes.
22 Q And do you have any corrections or
23 additions to make to your prefiled testimony or exhibits?
24 A Yes, I have a couple.
25 Q Will you please make those on the record
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1 now?
2 A On page 2, line 9 begins an answer, a three
3 sentence answer, I'd like the second two sentences to be
4 removed so that the answer is "This is nothing more than
5 an unsupported opinion."
6 Q And that would conclude the answer for that
7 question?
8 A Yes. The other correction is at page 5,
9 line 5. The word "that" should have an "n." It should
10 be "than." That concludes my corrections.
11 MR. RIPLEY: I'm sorry, Pete, I didn't get
12 that one.
13 MR. RICHARDSON: The second correction?
14 MR. RIPLEY: Yes.
15 Q BY MR. RICHARDSON: Would you please state
16 that again, Dr. Peseau?
17 A Yes, on page 5, line 5, there's the word
18 "t-h-a-t." That word should be spelled "t-h-a-n," than.
19 MR. RICHARDSON: With that, I'd ask that
20 Dr. Peseau's testimony be spread upon the record as if it
21 were read in full and that Exhibits 501 and 502 be marked
22 for identification purposes.
23 COMMISSIONER SMITH: Mr. Richardson, there
24 had been a prefiled Exhibit 503. Has that been
25 abandoned?
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1 MR. RICHARDSON: Pardon me, Madam Chairman,
2 thank you, and Exhibit 503. That has not been abandoned.
3 COMMISSIONER SMITH: If there's no
4 objection, we will spread the prefiled testimony of
5 Dr. Peseau upon the record as if it had been read and
6 identify Exhibits 501, 502 and 503.
7 (The following prefiled testimony of
8 Dr. Dennis Peseau is spread upon the record.)
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1 Q PLEASE STATE YOUR NAME AND BUSINESS
2 ADDRESS.
3 A My name is Dennis Peseau and my business
4 address is 1500 Liberty Street SE, Salem, Oregon.
5 Q BY WHOM ARE YOU EMPLOYED AND IN WHAT
6 CAPACITY?
7 A I am President of Utility Resources, Inc.
8 Q ON WHOSE BEHALF ARE YOU PROVIDING
9 TESTIMONY?
10 A I have been asked by the Industrial
11 Customers of Idaho Power to testify in this matter.
12 Q WHAT ARE YOUR QUALIFICATIONS AND
13 EXPERIENCE?
14 A My resume is attached as Exhibit No. 501.
15 Q WHAT IS THE PURPOSE OF YOUR TESTIMONY?
16 A The purpose of my testimony is to express
17 the objections of the ICIP to Idaho Power's attempted
18 acceleration of the amortization of its deferred Demand
19 Side Management (DSM) expenses.
20 Q WHAT EVIDENCE DOES IDAHO POWER OFFER TO
21 SUPPORT ITS REQUESTED FIVE-YEAR AMORTIZATION RATE?
22 A None.
23 Q HOW CAN THAT BE?
24 A Amazingly enough, Idaho Power has offered
25 not a single objective reason in its testimony or
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1 exhibits to support its requested five-year amortization
2 period.
3 Q I THOUGHT IDAHO POWER ADDRESSED THE LENGTH
4 OF THE AMORTIZATION PERIOD IN ITS APPLICATION AND
5 TESTIMONY?
6 A It does. In the application Idaho Power
7 states:
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1 Since the issuance of that order [Order No.
25880], it has become apparent that a 24-year
2 amortization period for DSM expenditures is far
too long.
3
In Mr. Said's prefiled testimony, he states at page 5,
4 lines 16 through 21:
5 In recognition of the likelihood of changes in the
electric industry, a five year recovery period
6 seems like a reasonable time period for recovering
expenditures from the customers from whom the
7 expenditures were made. The current 24-year time
period for recovery of DSM expenditures is no
8 longer reasonable.
9 Q ISN'T THAT EVIDENCE OF THE REASONABLENESS
10 OF THE FIVE-YEAR AMORTIZATION PERIOD?
11 A This is nothing more than an unsupported
12 opinion.
13 Q WHAT WOULD SUFFICE AS EVIDENCE OF THE
14 REASONABLENESS OF IDAHO POWER'S REQUESTED ACCELERATED
15 AMORTIZATION OF ITS RECOVERY OF THE DEFERRED DSM
16 EXPENSES?
17 A In the last general rate case the
18 Commission made specific findings that a 24-year
19 amortization period is appropriate based on testimony
20 from numerous witnesses. The Commission carefully
21 weighed the various recommendations and determined that
22 twenty-four years is the best approximation of the
23 estimated useful lives of the DSM measures at issue. It
24 is helpful to quote from the Commission's order here to
25 fully understand the thought and reasoned balancing of
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1 the competing proposals offered to the Commission in that
2 proceeding. This quote is taken from Commission Order
3 No. 25880 at pages 16 and 17:
4 IPCo proposed in its Application to amortize all
DSM program expenditures over seven years. Staff
5 recommended that the program expenditures be
amortized over a period equal to the approximate
6 effective life of each program,...
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1 Similarly, FMC recommended an amortization period
of 24 years for the accumulated DSM program
2 expenditures, which is the average effective life
projected for the DSM programs.... As Staff
3 testified, the Commission has previously indicated
it expects expenditures for DSM programs to be
4 amortized over the expected useful life of the
program. See, e.g. Order Nos. 22299 and 22893.
5 Such an amortization properly spreads program
costs over the expected useful life.
6
7 Q HAS IDAHO POWER SUGGESTED THAT THE EXPECTED
8 USEFUL LIFE OF ITS PROGRAMS HAS CHANGED SINCE THE
9 COMMISSION MADE THE ABOVE RULING?
10 A No. Quite to the contrary. Idaho Power
11 has responded to discovery questions propounded by the
12 ICIP that the DSM measures under consideration will not
13 become "physically obsolete and useless" prior to 24
14 years; they will not "become technologically obsolete and
15 useless" prior to 24 years; and they will not become
16 "economically obsolete and useless" prior to 24 years.
17 See Idaho Power's response to the First Production
18 Request of the ICIP, Request Nos. 4, 5 and 6
19 respectively. The identified production request is
20 attached hereto as Exhibit No. 502.
21 Q IN THE FACE OF THE PRIOR COMMISSION ORDER
22 OUTLINING THE REASONED AND DETAILED RATIONALE FOR
23 ADOPTING A 24-YEAR AMORTIZATION PERIOD, HOW CAN THE
24 COMMISSION ADOPT FIVE YEARS IN THIS CASE?
25 A Frankly, I don't see any basis in Idaho
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1 Power's application or testimony supporting anything
2 other than the status quo. I will be the first to admit
3 that the Commission does not have to have overwhelming or
4 even compelling evidence to effect a change in rates or
5 ratemaking policy. But I do think that the Commission
6 needs something more than almost casual remarks by an who
7 is not an accountant or depreciation expert that 5 years
8 is appropriate.
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1 Q DIDN'T THE COMMISSION INVITE IDAHO POWER TO
2 INITIATE A PROCEEDING THAT WOULD PROVIDE FOR A
3 COMPREHENSIVE REVIEW OF THE EXISTING DSM INVESTMENT AND
4 RECOVERY?
5 A It did.
6 Q ISN'T THIS CASE A RESPONSE TO THAT REQUEST?
7 A Mr. Said quotes the Commission's order on
8 this issue at page 3 of his prefiled testimony. He noted
9 that the Commission encouraged Idaho Power to file a
10 "comprehensive review of its existing DSM investment and
11 recovery." Clearly the Company has every right to seek a
12 review of its DSM investment and method of recovery. But
13 this case is any thing but comprehensive. It strikes me
14 that Idaho Power simply assumes the Commission will
15 approve its filing almost as a formality without
16 questioning the underlying assumptions for the change,
17 despite the significant rate increase it causes.
18 Q SO I TAKE IT THAT YOUR ANSWER TO MY
19 PREVIOUS QUESTION IS "NO?"
20 A That is right.
21 Q IS THE ICIP OPPOSED TO THE RECOVERY BY
22 IDAHO POWER OF ITS DEFERRED DSM EXPENSES?
23 A No. The ICIP is not requesting
24 disallowance of approved and prudently incurred DSM
25 expenditures. Ultimately, however, it is our
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1 recommendation to not exacerbate a problem.
2 Q PLEASE EXPLAIN.
3 A Accelerating the write off of "select"
4 assets will lead to bigger problems upon the deregulation
5 of the electric utility industry.
6 Q WHAT ROLE SHOULD DEREGULATION PLAY IN THIS
7 MATTER?
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1 A No one knows for sure what the future
2 holds. Deregulation does, however, clearly drive Idaho
3 Power's application.
4 Q HOW CAN YOU BE SURE THAT DEREGULATION IS
5 DRIVING IDAHO POWER'S REQUEST IN THIS MATTER?
6 A There is no reason for Idaho Power's
7 application other than to clear its books in the event of
8 deregulation. If there were no deregulation on the
9 horizon, the issue before the Commission would simply be
10 whether the lives of the DSM assets are closer to the
11 current (24-year amortization rate) or the requested
12 (five year amortization rate).
13 Q PLEASE EXPLAIN.
14 A If Idaho Power were seeking to change the
15 amortization period for a reason other than pending
16 deregulation of fear of stranded costs, it would have
17 offered some rational basis for its requested five year
18 amortization period. It has not done so. In fact, it
19 appears to refuse to do so in light of its responses to
20 the discovery requests propounded in this matter. See
21 Exhibit No. 502.
22 Q HOW CAN YOU BE SURE THAT DEREGULATION IS
23 DRIVING IDAHO POWER'S REQUEST IN THIS MATTER?
24 A There is no other reason for Idaho Power to
25 make an application such as this. The Company is made
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1 whole regardless of which amortization method is
2 used - assuming no deregulation or stranded cost issues
3 down the road. If there are stranded cost issues down
4 the road then Idaho Power risks not being able to fully
5 recover its investment in this asset.
6 Q ARE THERE OTHER INDICIA THAT IDAHO POWER IS
7 CONCERNED WITH RESPECT TO ITS DSM INVESTMENT ABOUT
8 STRANDED COSTS?
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1 A Yes. I have attached as Exhibit No. 503
2 Idaho Power's last two versions of its Partners in
3 Industrial Efficiency Program Agreement. The first page
4 of the exhibit is the iteration that was drafted or
5 effective as of 4/94 as indicated in the notation in the
6 lower left hand corner of the agreement. The second page
7 of the exhibit is the version of the agreement that
8 became effective on 1/13/97 also as indicated in the
9 lower left hand corner notation. I would draw your
10 attention to paragraph four on the second page of that
11 exhibit.
12 Q WHAT DOES PARAGRAPH FOUR INDICATE?
13 A It most clearly indicates that Idaho Power
14 was anticipating competition in the electric industry and
15 was actually preparing for that competition in its PIE
16 program agreements.
17 Q PLEASE EXPLAIN.
18 A Paragraph four of the 1997 iteration of the
19 PIE agreement provides:
20 If the customer obtains electrical service or
energy from a supplier other than the Company, the
21 Customer agrees to reimburse the Company the
amount of the incentive payment which has not yet
22 been amortized by the Company. Amortization of
the incentive payment is based upon a 27-year
23 period. Accordingly, the reimbursement amount
will be calculated by reducing the original amount
24 of the incentive payment, including any applicable
interest, by 1/27 for each year following the year
25 the Project commences operations.
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ICIP
1 The effect of this amendment to the PIE contract very
2 late in the program is clear.
3 Q WHAT IS THAT EFFECT?
4 A It would clearly discourage participation
5 in the program due to the requirement that the
6 participant incur a 27-year obligation to Idaho Power. I
7 don't think many plant managers would be pleased with
8 such a long-term liability. It also discourages
9 participation in that it restricts the ability of these
10 customers to have choice of electric
11
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1 suppliers when competition arrives. It seems
2 anticompetitive. In addition, it is clear evidence that
3 Idaho Power is primarily motivated by a fear of
4 competition and not by a conviction that a five-year
5 amortization period is more appropriate than a 24-year
6 amortization period.
7 Q DO YOU HAVE ANY OTHER CONCERNS REGARDING
8 THIS PARAGRAPH OF THE PIE AGREEMENT?
9 A Yes. It allows for double recovery of
10 Idaho Power's DSM deferrals.
11 Q PLEASE EXPLAIN.
12 A If Idaho Power's application is approved,
13 then after the five-year amortization period has lapsed,
14 Idaho Power will have recovered from the general body of
15 ratepayers all of its DSM deferrals, with interest. Then
16 after that initial time period has lapsed, any PIE
17 customer who selects a different electric supplier will
18 have to reimburse Idaho Power as if there were a 27-year
19 amortization period. A clear case of double recovery on
20 Idaho Power's part.
21 Q DO YOU HAVE ANY OTHER CONCERNS?
22 A Yes. I do not recall having seen any
23 Commission approval of this restrictive and
24 anticompetitive language. In addition, the 27-year
25 amortization period is different from any we have seen in
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1 the Commission orders and is different from any
2 amortization period recommended by the Company in prior
3 proceedings.
4 Q IS THERE ANY GOOD ACCOUNTING REASON TO
5 SHORTEN THE PERIOD OVER WHICH IDAHO POWER'S DEFERRED DSM
6 EXPENDITURES ARE RECOVERED?
7 A Absolutely not. As noted earlier, in Case
8 No. IPC-E-94-5, the Commission ordered that deferred DSM
9 be recovered over a 24-year period which is
10
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1 consistent with the period over which the various DSM
2 programs provide benefits. A fundamental principle of
3 accounting is that the costs of long lived assets match
4 the period over which the assets provide service; in
5 other words, the costs be amortized over the period that
6 the assets provide service. Thus, the Commission's order
7 was consistent with fundamental accounting principles for
8 amortizing the costs of DSM programs. Shortening the
9 recovery period would produce a mismatch between expense
10 recovery and benefits which would violate fundamental
11 economic principles.
12 Q DOES ACCELERATING THE AMORTIZATION VIOLATE
13 THE MATCHING CONCEPT COMMONLY USED IN UTILITY ACCOUNTING?
14 A Yes. In this application, Idaho Power is
15 requesting that the costs be amortized over a much
16 shorter period, 5 years. In response to ICIP Data
17 Requests Nos. 2-4, Idaho Power indicates that none of
18 their DSM programs will become physically,
19 technologically or economically obsolete in a period
20 shorter than the 24 years over which they provide
21 benefits. In their testimony and workpapers, they offer
22 no reason why 5 years is more appropriate than 24 years
23 other than Mr. Said's opinion, unspecified changes in the
24 electric utility industry and reduced total costs over
25 the whole recovery period. If reduced overall costs were
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1 a good reason for reducing the recovery period, the costs
2 of all assets and programs should be expensed in the year
3 incurred because interest expense is always more when the
4 recovery period is longer. Interest costs are simply the
5 costs of matching expenses with services and so should
6 not be used as a basis for determining the amortization
7 period. Therefore, there is no basis for reducing the
8 amortization period.
9 Q CAN YOU ENVISION ANY INSTANCE WHEN THE
10 AMORTIZATION OF DSM PROGRAM COSTS SHOULD BE REDUCED TO
11 FIVE YEARS?
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1 A Possibly, if it could be shown that a
2 portion of DSM expenditures were stranded. However,
3 Idaho Power has made no such showing. In fact, in
4 response to ICIP's data request No. 20, Exhibit No. 502,
5 Idaho Power indicates that it is its opinion that none of
6 the DSM costs can be stranded. Therefore, there is no
7 basis for reducing the amortization period because some
8 of the DSM costs are stranded.
9 Q COULD YOU EXPLAIN HOW DSM COSTS COULD BE
10 STRANDED AND WHY THAT MAY JUSTIFY RECOVERY OVER A SHORTER
11 PERIOD?
12 A Yes. Money was expended on DSM programs
13 because the expenditures were less than (or equal to)
14 Idaho Power's cost to generate the same amount of energy
15 saved by the DSM programs. The programs have saved
16 energy over many years. The amortization period was set
17 to recover the expenditures over the expected number of
18 years that the programs were designed to save energy.
19 If, after the money was expended, the cost to generate
20 energy fell because of falling market prices for energy,
21 the amount of expenditure that was initially made for the
22 programs could not be justified. The difference between
23 the unamortized initial expenditure and the value of
24 energy to be saved over the remaining life of the program
25 at the lower market prices would be considered stranded
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ICIP
1 investment in the DSM program. That excess amount of
2 expenditure could not be recovered in a competitive
3 energy market at the then current energy prices.
4 Q WHAT TIME PERIOD WOULD BE APPROPRIATE FOR
5 RECOVERY OF STRANDED INVESTMENTS?
6 A If the Commission allows recovery of all,
7 or a portion of the stranded portion of DSM expenditures,
8 the recovery period could be five years, or any other
9 period determined by the Commission, because there is no
10 benefit, or service, to which the expenditures could be
11 matched.
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1 Q IF IDAHO POWER COULD SHOW THAT A PORTION OF
2 DSM EXPENDITURES WERE STRANDED, DO YOU THINK THE
3 COMMISSION SHOULD ALLOW RATES TO BE INCREASED TODAY TO
4 RECOVER THOSE COSTS OVER FIVE YEARS?
5 A No. It is my opinion that the current
6 amortization should continue until the Commission
7 addresses the total stranded costs issue. That includes
8 stranded generation, purchased power contracts, DSM
9 expenditures and other regulatory assets. At that time
10 it is very likely that Idaho Power will have stranded
11 benefits in total, not stranded cost. If the Commission
12 allows rates to increase today to recover only stranded
13 DSM, then there will be the need for an even greater rate
14 reduction in the future to refund to ratepayers stranded
15 benefits to which they are entitled. If any stranded DSM
16 is held until the total stranded cost issue is addressed,
17 then stranded DSM can be used to offset some of the
18 stranded benefit, and reduce the size of the future rate
19 decrease to refund stranded benefits to Idaho Power's
20 ratepayers.
21 Q WHY DO YOU SAY THAT IDAHO POWER WILL HAVE
22 STRANDED BENEFITS RATHER THAN STRANDED COSTS?
23 A The results of a recent study completed by
24 Resource Data International, Inc., which was published in
25 the June 1, 1997 issue of Public Utilities Fortnightly,
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1 estimated that Idaho Power has approximately $44 million
2 in stranded benefits, or negative stranded costs. That
3 estimate includes generation, purchase contracts,
4 wholesale sales contracts and other regulatory assets.
5 Idaho Power's FERC Form 1 indicates that at least a
6 portion of its DSM expenditures are included on the
7 balance sheets as a regulatory asset. Therefore, the
8 $44 million stranded benefit estimate may already include
9 all or some of Idaho Power's unrecovered DSM
10 expenditures. Even if the regulatory asset component of
11 that estimate does not include unrecovered DSM
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1 expenditures, it still is greater than Idaho Power's
2 unamortized DSM expenditure balances of $34.4 million.
3 So, even if Idaho Power's total amount of unrecovered DSM
4 expenditures is stranded, it is more than offset by its
5 stranded benefits and its rates should still be reduced
6 to refund the remaining stranded benefit balance and not
7 increased now to recover a smaller stranded cost.
8 Q IF THE COMMIMSSION ALLOWS RATES TO BE
9 INCREASED TO RECOVER DSM OVER 5 YEARS, SHOULD THE
10 INCREASE BE AS MUCH AS REQUESTED BY IDAHO POWER?
11 A No. Idaho Power's request examines
12 accelerating DSM recovery in isolation. More rapid
13 recovery of DSM expenditures will have other effects that
14 will reduce Idaho Power's cost of service.
15 Q WHAT OTHER EFFECTS DOES ACCELERATED
16 RECOVERY OF DSM HAVE ON COST OF SERVICE?
17 A Accelerated recovery of DSM expenses will
18 increase Idaho Power's cashflows and recover investment
19 more rapidly which will benefit shareholders. Increased
20 cashflow can be used to reduce the need for external
21 financing, retire outstanding debt, increase dividends
22 and/or fund activities in unregulated affiliates, all of
23 which benefit shareholders. More rapid recovery of
24 investment is also preferred by investors, all else
25 equal. Idaho Power, in response to ICIP data request
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1 No. 17, indicates that accelerated recovery of DSM
2 reduces the risk of recovery. In addition, Idaho Power
3 indicates in response to ICIP data request No. 18 that
4 the cost of borrowed funds to be repaid in 5 years would
5 be less than the cost of borrowed funds repaid in 24
6 years. The above factors will either increase Idaho
7 Power stock prices or reduce the cost of capital or
8 possibly both. Ratepayers should be credited with these
9 benefits because they will be funding the accelerated
10 recovery.
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1 Q ARE THERE ANY OTHER POTENTIAL BENEFITS OF
2 ACCELERATED RECOVERY OF DSM?
3 A Yes, there are at least two other possible
4 benefits. First, if increased cashflow were used to
5 retire outstanding debt, shareholders could possibly earn
6 a rate of return in excess of the current allowed rate of
7 return until a future rate case adjusted rate base and
8 cost of capital accordingly. Second, if book
9 amortization expense is not increased, or not increased
10 in like amount as accelerated regulatory amortization,
11 book income could increase even if regulatory income does
12 not increase. This may cause share prices to be bid up,
13 which would benefit shareholders. It could also increase
14 interest coverage which would increase the value of Idaho
15 Power's outstanding debt, benefiting current bondholders.
16 Again, these benefits, to the extent that they occur as a
17 result of accelerated amortization of DSM, should be
18 credited to ratepayers since they are funding the
19 accelerated recovery.
20 Q IF THE COMMISSION ALLOWS ACCELERATED
21 RECOVERY, DO YOU HAVE ANY SUGGESTIONS ON HOW TO ADJUST
22 IDAHO POWER'S PROPOSAL TO CREDIT RATEPAYERS FOR THE
23 BENEFITS TO INVESTORS YOU DISCUSS ABOVE?
24 A Exact estimation of the dollar value of
25 benefits to be credited to ratepayers would require
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1 extensive study. However, I have a simple suggestion
2 that will approximate the value of the major benefits
3 discussed above a direct it to ratepayers. My suggestion
4 is to assume for ratesetting purposes that current
5 unamortized DSM balances be financed with 5-year bonds
6 and that rate adjustments be calculated assuming that the
7 interest rate on the bonds is set at current rates on
8 5-year corporate bonds and that the bonds are repaid in
9 equal monthly payments over 60 months. This would reduce
10 the carrying cost on outstanding DSM to levels consistent
11 with the reduced risk of recovery
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1 and lower cost of a much shorter recovery period. In
2 addition, it would eliminate the income tax portion of
3 carrying charges.
4 Q COULD YOU ILLUSTRATE THE IMPACT OF YOUR
5 PROPOSAL?
6 A Yes Idaho Power proposes using their last
7 approved cost of capital of 9.199% to determine carrying
8 charges on unamortized DSM balances over the 5-year
9 recovery period. 5.55% of that represents taxable
10 return. Their proposal results in increased monthly
11 revenues of approximately $705,900 or $8.5 million
12 annually to recover DSM balances in 5 years, which
13 includes carrying costs and income taxes. Under my
14 proposal, carrying charges would be computed using a 6.3%
15 interest rate, an approximate rate for medium quality
16 corporate bonds maturing in less than 10 years. Since
17 the balances are assumed financed with debt, there would
18 be no tax component of carrying charges. Rate increases
19 necessary to recover DSM balances using my proposal would
20 be approximately $640,800 monthly, or $7.7 million
21 annually. My proposal is roughly 9% less than Idaho
22 Power's proposal.
23 Q DO YOU HAVE ANY OTHER CONCERNS IF THE
24 COMMISSION APPROVES IDAHO POWER'S PROPOSED 5 YEAR
25 AMORTIZATION?
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1 A Yes. I am concerned about the allocation
2 of the proposed increased revenue requirement to rate
3 classes. In my opinion, the allocation of the post 1993
4 DSM expenses is much more appropriate than the allocation
5 of the pre-1994 amounts. The allocation of pre-1994
6 expenditures is based on class use of system resources.
7 The allocation for post-1993 expenditures is based on
8 ability to participate. Since the predominant benefits
9 of DSM programs flow to participating customers through
10 lower
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1 power bills, an allocation of cost based on ability to
2 participate is much more appropriate because costs follow
3 benefits much more closely.
4 Q DO YOU HAVE ANY RECOMMENDATIONS ON CLASS
5 ALLOCATIONS?
6 A Yes. I recommend that all rate increases
7 resulting from accelerated amortization be allocated to
8 classes based on ability to participate, both pre-1994
9 and post-1993 balances. However, in response to ICIP
10 data request No. 7, Idaho Power indicates that they have
11 not performed an allocation of pre-1994 expenditures
12 based on ability to participate. I recommend that they
13 do so and use it for allocation of rate increases to
14 classes. If it is not possible, I recommend that they
15 use the allocation factors for post-1993 expenditures to
16 allocate pre-1994 expenditures to classes. That will
17 provide a much better matching of rate increases for
18 accelerated amortization to benefits derived from DSM
19 program expenditures.
20 Q DOES THIS CONCLUDE YOUR TESTIMONY?
21 A Yes, it does.
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1 (The following proceedings were had in
2 open hearing.)
3 MR. RICHARDSON: Thank you, Madam Chairman,
4 Dr. Peseau is available for cross-examination.
5 COMMISSIONER SMITH: Okay, let's see if
6 there are any questions. How about Mr. Budge.
7 MR. BUDGE: No, thank you.
8 COMMISSIONER SMITH: Mr. Richey.
9 MR. RICHEY: No, Madam Chairman.
10 COMMISSIONER SMITH: Mr. Jauregui.
11 MR. JAUREGUI: No questions.
12 COMMISSIONER SMITH: Mr. Ward.
13 MR. WARD: No questions.
14 COMMISSIONER SMITH: Mr. Gollomp.
15 MR. GOLLOMP: No questions.
16 COMMISSIONER SMITH: Mr. Fothergill.
17 MR. FOTHERGILL: No questions.
18 COMMISSIONER SMITH: Mr. Purdy.
19 MR. PURDY: Yes, just one or two.
20
21 CROSS-EXAMINATION
22
23 BY MR. PURDY:
24 Q Dr. Peseau, while you do not go into this
25 at great length, you do briefly discuss the matter of
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1 revenue allocation or cost allocation and I wanted to
2 touch on that briefly. Now, as I understand it, it's
3 your position that Idaho Power's proposal to allocate
4 post-'93 DSM costs based on the ability of a class to
5 participate is a reasonable proposal; is that correct?
6 A Yes.
7 Q And the ICIP -- well, strike that
8 question. Have you conducted any study to determine
9 whether DSM program participants received more benefits
10 compared to their costs than did non-participating
11 customers?
12 A Did I do a study? No.
13 Q Might it be possible that a DSM program
14 could turn out to be cost effective for the utility, but
15 not for a participating customer and I'm referring to any
16 type of DSM program?
17 A I think that's possible. I would think
18 under those circumstances that one would not participate.
19 Q Well, might it be possible that going into
20 the program, the individual customer had every
21 expectation and anticipation that its effort would turn
22 out to be cost effective, but nonetheless, for any number
23 of reasons, it turned out that it was not?
24 A That could be possible.
25 Q And would you agree with me that within a
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1 given class that some customers within that class might
2 benefit from a DSM program while others might not?
3 A Yes.
4 Q Would you agree that within a given class,
5 and I'm speaking specifically with regard to Idaho
6 Power's system, that customers within a given class might
7 not be able to participate in a DSM program designated
8 for their class for any number of reasons?
9 A I have no reasons in mind, but as a
10 hypothetical, I suppose that's possible.
11 Q Well, specifically let me ask you, then,
12 are you familiar with the Company's mobile home
13 acquisition program?
14 A Very generally.
15 Q Do you know whether or not that is a
16 program available or a program that is charged to the
17 residential class?
18 A I believe that's true.
19 Q And do you know whether every member of
20 Idaho Power's residential class can necessarily
21 participate in that program?
22 A No, they cannot.
23 Q And might it be possible that customers
24 will choose not to -- strike that. Might it be possible
25 that it would not be feasible for certain customers to
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1 participate in a DSM program because they have already
2 implemented by their own volition the DSM conservation
3 measures?
4 A That's possible.
5 Q All right; so presumably, they wouldn't
6 benefit from the program?
7 A Well, specifically, I think we started on
8 this line with the division between sort of general
9 resource benefits and individual benefits and they would
10 not by your construction be available for individual
11 benefits.
12 MR. PURDY: That's all I have. Thank you.
13 COMMISSIONER SMITH: Thank you.
14 Mr. Ripley.
15 MR. RIPLEY: Yes.
16
17 CROSS-EXAMINATION
18
19 BY MR. RIPLEY:
20 Q Doctor, first, if we could direct your
21 attention to the bottom of page 2, the top of page 3,
22 there you're quoting from a Commission Order. Do you see
23 that?
24 A Yes.
25 Q At the top of page 3, you state or the
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1 Order states, "Similarly, FMC recommended an amortization
2 period of 24 years...." Do you see that?
3 A Yes.
4 Q Were you not the witness for FMC in that
5 proceeding?
6 A I believe I was.
7 Q So this is really your recommendation?
8 MR. RICHARDSON: Madam Chairman, I object.
9 The Order reads it's FMC's recommendation. The Order
10 speaks for itself.
11 COMMISSIONER SMITH: Mr. Ripley.
12 MR. RIPLEY: Yes, I'll attempt to clarify
13 that for counsel.
14 Q BY MR. RIPLEY: Dr. Peseau, were you not
15 the witness for FMC?
16 A I was.
17 Q Was this not your recommendation that FMC
18 accepted?
19 A It's probably -- it was probably reached by
20 mutual discussion. We would undertake the analysis, make
21 certain recommendations and the company would either
22 agree or not agree, FMC being the company.
23 Q Is there any doubt in your mind that when
24 the Commission is referring to FMC and is referring to
25 the recommendations that FMC made that the Commission is
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1 not referring to your testimony?
2 A Oh, I think it's clear that the Commission
3 is designating the issue, the controller of the issue, as
4 being FMC. I think they're under -- they fully realize
5 that I wrote the testimony presenting that issue, yes.
6 Q All right. Now, your recommendation in
7 that proceeding was for 24 years; correct?
8 A Yes.
9 Q And was one of the prime reasons for your
10 recommendation the fact that you were concerned about, as
11 you put it, intergenerational transfer?
12 A I don't recall. The Order indicates that I
13 was concerned about the average effective life. I may
14 have discussed intergenerational.
15 Q Maybe I can refresh your memory.
16 A I thought maybe you would.
17 MR. RIPLEY: Could I have a moment?
18 COMMISSIONER SMITH: Certainly.
19 MR. RIPLEY: Could I approach the witness?
20 COMMISSIONER SMITH: Yes.
21 (Mr. Ripley approached the witness.)
22 (Pause in proceedings.)
23 Q BY MR. RIPLEY: Dr. Peseau, off the record
24 I shared with you a copy of your prepared testimony that
25 you filed in the proceeding that we've been talking about
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1 that's referenced by the Commission's Order at the top of
2 page -- at the bottom of page 2 and the top of page 3 of
3 your testimony and I asked you --
4 MR. RICHARDSON: Madam Chairman?
5 COMMISSIONER SMITH: Mr. Richardson.
6 MR. RICHARDSON: I'll note for the record
7 that the witness was shown prefiled testimony filed by
8 Dr. Peseau in the docket in which this Order was issued.
9 It was not a copy of the transcript, but for purposes of
10 this proceeding, we will agree that this was the
11 testimony that was spread upon the record as if it were
12 read.
13 COMMISSIONER SMITH: Okay.
14 Q BY MR. RIPLEY: Now, in that proceeding
15 were you not concerned with intergenerational transfers
16 of the DSM expenditures?
17 A Yes, I believe I addressed three areas of
18 concern and from the testimony you just showed me the
19 second concern expressed was intergenerational equity.
20 Q Do we have that same issue today, the same
21 concerns, the intergenerational transfer?
22 A Yes.
23 Q And could you explain that for us as to why
24 you believe that?
25 A Certainly. We have an expected life of a
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1 group of assets that will benefit customers in the future
2 and we're accelerating or Idaho Power is requesting
3 acceleration of that asset into a shorter time frame so
4 that customers in the next five years would pay for the
5 bulk of it or all of it.
6 Q Now, if there was a large customer that
7 left the system and left behind its obligation that the
8 Commission had previously determined that it was going to
9 have that customer pay, how does that coincide with your
10 problem of intergenerational transfer?
11 A Well, Dr. Power touched upon that. The
12 question is is just what this customer is giving up,
13 would give up obligations and would give up benefits and
14 I think that's just the nature of the opportunity to
15 leave the system, you'll leave behind both benefits and
16 obligations.
17 Q Now, in that proceeding what period of time
18 did Idaho Power Company propose, do you recall?
19 A I believe it was seven years.
20 Q Do you recall what the basis of that
21 contention was?
22 A No.
23 Q Do you recall that a witness for Idaho
24 Power Company testified that the Internal Revenue Service
25 utilized seven years to amortize these types of
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1 expenditures?
2 MR. RICHARDSON: Madam Chairman?
3 COMMISSIONER SMITH: Mr. Richardson.
4 MR. RICHARDSON: The witness said he didn't
5 recall the basis for Idaho Power's testimony in that
6 case. If Mr. Ripley would like to cross-examine
7 Dr. Peseau on Idaho Power's testimony in that case, I
8 would be more than happy to have him respond to questions
9 if he has a copy of the testimony and is able to refer to
10 it.
11 COMMISSIONER SMITH: Well, I think he was
12 asking him if he recalled any testimony of that nature
13 and I think I'll allow the answer.
14 THE WITNESS: I don't recall that.
15 Q BY MR. RIPLEY: Now, at the bottom of
16 page 3 of your prepared testimony, you state on lines 23
17 through 25, "I do think that the Commission needs
18 something more than almost casual remarks by an who is
19 not an accountant or depreciation expert that five years
20 is appropriate." Do you see that?
21 A Yes.
22 Q What in Mr. Said's testimony disturbs you
23 that he's not an accountant or a depreciation expert?
24 A What disturbs me is that there's no attempt
25 to justify the five-year period based on accounting,
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1 economic or financial principles.
2 Q Is it an accounting principle that we're
3 addressing here?
4 A I would cast -- it's an accounting
5 principle in that we're going to amortize it over some
6 period of time and there's some rather straightforward
7 mathematics that would follow the accounting
8 conventions. I believe it's more of an economic
9 convention or an economic principle than it is an
10 accounting, frankly.
11 Q And that would also then mean that you
12 don't need a depreciation expert to determine the
13 amortization period for DSM expenditures, wouldn't that
14 follow?
15 A That's correct.
16 Q So we're looking at economics from your
17 viewpoint?
18 A I would term it economics, perhaps finance
19 to some.
20 Q Now, on page 5 of your prepared testimony,
21 you advance the principle that deregulation is driving
22 the Company's application in this proceeding; is that a
23 fair summary of your testimony?
24 A Yes.
25 Q Do you think the utility should be
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1 concerned at all with who has to pay for expenditures
2 that it has made?
3 A Yes.
4 Q Do you think that could be driving Idaho
5 Power Company's decision in this matter that it does not
6 want to defer for a long period of time an expenditure to
7 be then paid for by future customers?
8 A My testimony advances just the opposite,
9 that the 24-year period originally was intended to track
10 cost incurrence and moving to a five-year period in my
11 mind does the opposite.
12 Q So therein lies the difference of opinion
13 between you and Mr. Said?
14 A Yes.
15 Q Now, you've also in your testimony referred
16 to the insertion by Idaho Power Company into its PIE
17 conservation agreements of a paragraph that required
18 amortization over 27 years. Do you recall that?
19 A Yes.
20 Q Did your counsel make available to you any
21 of the orders that were issued in that proceeding that
22 the Industrial Customers of Idaho Power participated in?
23 A Not that I can recall.
24 Q Are you aware that the Industrial Customers
25 of Idaho Power were the principal parties that filed
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1 comments in Idaho Power Company's application to
2 discontinue that program?
3 A No.
4 Q Are you aware of the position that the
5 Industrial Customers of Idaho Power took in that
6 proceeding?
7 A No.
8 MR. RIPLEY: Again, if I could approach the
9 witness.
10 COMMISSIONER SMITH: You may.
11 (Mr. Ripley approached the witness.)
12 (Pause in proceedings.)
13 Q BY MR. RIPLEY: Dr. Peseau, I've shown you
14 an Order that the Commission issued in reference to the
15 discontinuance of the PIE program --
16 A Yes.
17 Q -- and I would like to read to you from
18 that Order.
19 COMMISSIONER SMITH: Mr. Ripley, could we
20 have the Order number? That would help us.
21 MR. RIPLEY: Certainly. Order No. 26753.
22 COMMISSIONER SMITH: Thank you.
23 MR. RIPLEY: Entered in Case
24 No. IPC-E-96-22.
25 COMMISSIONER SMITH: Thank you.
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1 Q BY MR. RIPLEY: And in that Order,
2 Dr. Peseau, the Commission states, "We find that it would
3 be reasonable for Idaho Power to include in any PIE
4 contracts the requirement that in the event the customer
5 leaves Idaho Power's system before the PIE expenditure is
6 amortized, the customer is required to refund to the
7 Company all of the unamortized portion of the funding
8 provided by Idaho Power to that customer under the PIE
9 program."
10 A That's correct.
11 Q Now, at the time that the Commission's
12 Order was entered in this proceeding, the amortization
13 period for the recovery of PIE expenditures was 24 years,
14 was it not?
15 A Yes.
16 Q And the Company was required or permitted
17 to wait three years before it commenced the amortization
18 of an expenditure; correct?
19 A I believe that's correct.
20 MR. RICHARDSON: Madam Chairman, I'll
21 object to that question. I don't think that's what the
22 Commission's Order required that the Company wait three
23 years.
24 COMMISSIONER SMITH: Mr. Ripley.
25 MR. RIPLEY: Let me rephrase it. We want
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1 to make sure we get this to counsel's liking.
2 Q BY MR. RIPLEY: The Company was permitted
3 to wait up to three years before it commenced the
4 amortization?
5 A Okay.
6 Q Okay; so if you took three plus 24, you
7 would get 27 years' amortization; correct?
8 A That's correct.
9 Q Now, assuming that a customer does
10 participate in the PIE program as it was being
11 discontinued and it does enter into the contract that
12 states they'll pay it back if they leave the system
13 within 27 years and the Company recovers some of that
14 previously expended amount of money, then you contend
15 that if the period of time was reduced to five years,
16 Idaho Power Company would obtain a double recovery.
17 A That's possible, yes.
18 Q Now, that could simply be solved by the
19 Company refunding any of those dollars back to its
20 customers.
21 A It could.
22 Q In fact, it would have an obligation, would
23 it not?
24 MR. RICHARDSON: Madam Chairman.
25 COMMISSIONER SMITH: Mr. Richardson.
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1 MR. RICHARDSON: It calls for a legal
2 conclusion.
3 MR. RIPLEY: I'm not asking legal.
4 MR. RICHARDSON: On what basis are you
5 asking, then?
6 Q BY MR. RIPLEY: Well, do you think that the
7 Company would be, if it was regulated would be, wise to
8 recover an expenditure from its customers for doing a
9 certain act and then it recovers that expenditure again
10 from the customer it made the expenditure for, wouldn't
11 it just make sense to you that it would flow that money
12 back? You wouldn't do that?
13 A Not necessarily. I wouldn't be in a
14 position to do so. I think shareholders wouldn't favor
15 it and, secondly, if there were a rate freeze, it
16 wouldn't happen anyway.
17 Q Then that can be solved by the Commission
18 if it goes to five years inserting a provision in the
19 order that states if you recover back all your DSM
20 expenditures in five years and then recover back one of
21 those expenditures, you'll refund it to the customers.
22 A Then the problem of double recovery could
23 be reduced or eliminated.
24 COMMISSIONER SMITH: Mr. Ripley?
25 MR. RIPLEY: Yes.
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1 COMMISSIONER SMITH: The Commission has a
2 commitment that it needs to attend to now. I apologize
3 for interrupting, so we need to adjourn for our noon
4 recess and come back at 1:30.
5 MR. RIPLEY: Okay. What time are we going
6 to reconvene?
7 COMMISSIONER SMITH: 1:30, maybe 1:35.
8 (Noon recess.)
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