20090108Vol VI [technical hearing] pgs 716-1023.pdf

ORIGINAL
'.BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS
RATES AND CHARGES FOR ELECTRIC
SERVICE TO ELECTRIC CUSTOMERS IN
THE STATE OF IDAHO.
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) CASE
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Idaho Public Utilties Commission
Office of the SecretaryRECEIVED
NO. IPC-E-08-10
JAN -8 2009
Boise, Idaho
BEFORE
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER JIM D. KEMPTON.
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:December 17, 2008
VOLUME VI - Pages 716 - 1023
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CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone] * [phone]
Email csb~heritagewifi.com
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1 APPEARANCES
2 For the Staff:
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5 For Idaho Power Company:
Neil Price, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83720-0074
Barton L. Kline, Esq.
and Lisa D. Nordstrom, Esq.
and Donovan E. Walker, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
RICHARDSON & 0' LEARY
by Peter J. Richardson, Esq.
Post Office Box 7218
Boise, Idaho 83702
RACINE, OLSEN, NYE, BUDGE
& BAILEY
by Eric L. Olsen, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
Arthur Perry Bruder, Esq.
Assistant General Counsel
U. S. Department of Energy
1000 Independence Ave., SW
Washington, DC 20585
GIVENS PURSLEY LLP
by Conley E. Ward, Esq.
Post Office Box 2720
Boise, Idaho 83701-2720
BOEHM, KURTZ & LOWRY
by Kurt J. Boehm, Esq.
36 E. Seventh Street
Suite 1510
Cincinnati, Ohio 45202
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FISHER PUSCH & ALDERMAN LLPby John R. Hamond, Jr., Esq.
Post Office Box 1308
Boise, Idaho 83701
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For Industrial Customers
of Idaho Power:
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For Idaho Irrigation
Pumpers Association:
For The United States
Department of Energy:
For Micron Technology,
Inc. :
For The Kroger Company:
(Of Record)
(Of Record)
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APPEARANCES
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1 A P PEA RAN C E S (Continued)
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3 For the Community Action
Partnership of Idaho:
Brad M. Purdy, Esq.
Attorney at Law
2019 North 17th Street
Boise, Idaho 83702
Mr. Ken Miller
5400 West Franklin
Boise, Idaho 83705
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For Snake River Alliance:
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CSB REPORTING
[phone]
APPEARANCES
1 I N D E X.2
3 WITNESS EXAMINATION BY PAGE
4 Courtney Waites Mr.Walker ( Direct)716(Idaho Power Company)Prefiled Direct Testimony 719
5 Prefiled Rebuttal Testimony 737
Mr.Richardson (Cross)755
6 Mr.Purdy (Cross)768
Mr.Price (Cross)777
7 Commissioner Kempton 789
Commissioner Smith 793
8 Mr.Walker (Redirect)795
Commissioner Redford 798
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Darlene Nemnich Mr.Walker (Direct)806
10 (Idaho Power Company)Prefiled Direct Testimony 808
Mr.Richardson (Cross)84811
Jeannette Bowman Mr.Walker (Direct)858
12 (Idaho Power Company)Prefiled Direct Testimony 860
Commissioner Smith 885.13
Gregory W.Said Commissioner Redford 887
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15 Dennis W.Goins Mr.Bruder (Direct)897
(Idaho Power Company)Prefiled Direct Testimony 900
16 Prefiled Rebuttal Testimony 945
Mr.Ward (Cross)978
17 Mr.Olsen (Cross)987
Mr.Walker (Cross)99618Commissioner Smith 999
Mr.Bruder (Redirect)100419Commissioner Redford 1008
Commissioner Kempton 101320
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1 EXHIBITS
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3 NUMBER DESCRIPTION PAGE
4 FOR IDAHO POWER COMPANY:
5 72 - Calculation of Proposed Rates,
Schedule 1
Premarked
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73 - Typical Monthly Billing Comparison, Premarked7 Schedule 1
8 74 - Calculation of Proposed Rates, Premarked
Schedule 7
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75 - Typical Monthly Billing Comparison, Premarked10 Schedule 7
11 76 - Calculation of Proposed Rates for Premarked
Schedules 15, 24, 39, 40, 41 & 42
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77 - Billing Impact of Proposed Rates,
Schedule 24
Premarked
14 78 - Summary of Revenue Impact Premarked
15 79 Proposed Revised Tariff Sheets in
Legislati ve Format
Premarked
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80 - Proposed. Revised Tariff Sheets Premarked17
19 FOR THE STAFF:
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154 - Rocky Mountain Power, Utah
Residential Rate Survey
Identified 782
155 - Stipulation in '07 Utah case Identified 789
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Wilder, Idaho 83676 EXHIBITS
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1 E X H I BIT S (Continued)
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3 NUMBER DESCRIPTION PAGE
4 FOR U. S. DEPARTMENT OF ENERGY:
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607 - Al ternati ve Classification of
Production Function Costs:
3CP/12CP
Premarked
7 608 - 3CP/12CP Class Cost of Service
Study Premarked
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609 - Peak & Average Class Cost of
Service Study
Premarked
10 610 - W12CP Class Cost of Service
Study Premarked
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611 - W12CP Class Cost of Service
Study Premarked
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Wilder, Idaho 83676
EXHIBITS
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1 BOISE, IDAHO, WEDNESDAY, DECEMBER 17, 2008, 9:00 A. M.
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4 . COMMISSIONER SMITH: Good morning,
5 everyone. It's time to resume our hearing and,
6 Mr. Walker, I think we're ready for your next witness.
7 MR. WALKER: Idaho Power calls Courtney
8 Wai tes as its next witness.
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10 COURTNEY WAITES,
11 produced as a witness at the instance of the Idaho Power
12 Company, having been first duly sworn, was examined and
13 testified as follows:
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15 DIRECT EXAMINATION
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17 BY MR. WALKER:
18 Q Could you please state your name and spell
19 your last name for the record?
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A Courtney Waites, W-a-i-t-e-s.
Q And by whom are you employed and in what
22 capaci ty?
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A Idaho Power as a pricing analyst.
Q And are you the same Courtney Waites that
filed direct testimony on June 27, 2008 and also prepared
CSB REPORTING
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716 WAITES (Di)
Idaho Power Company
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1 exhibits numbered 72 and 73?
2 A Yes, I am.
3 Q And did you also file rebuttal testimony
4 on December 3rd?
5 A Yes, I did.
6 Q And there were no rebuttal exhibits?
7 A Correct.
8 MR. WALKER: Madam Chairman, as a
9 housekeeping matter in Ms. Waites' direct testimony,
10 sorry, on page 5, line 14 through 16, I believe the last
11 sentence in that paragraph starting with "since" and
12 ending with "case" should be stricken to be consistent
13 wi th the deletion of that sentence that Mr. Gale
14 explained wi thin his direct.
15 Q BY MR. WALKER: And, Ms. Waites, do you
16 have any other corrections or changes to your direct or
1 7 rebut tal?
18 A I did have one change to my rebuttal
19 testimony. On page 12, line 9, the 89 percent should be
20 changed to 79 percent.
21 Q And if I were to ask you the questions set
22 out in your prefiled testimony, would your answers be the
23 same here today?
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A Yes.
MR. WALKER: I would move that the
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717 WAITES (Di)
Idaho Power Company
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1 prefiled direct and rebuttal testimony of Ms. Waites be
2 spread upon the record as if read and that her exhibits
3 be marked for identification.
4 COMMISSIONER SMITH: If there is no
5 objection, it is so ordered.
6 (The following prefiled direct and
7 rebuttal testimony of Ms. Courtney Waites is spread upon
8 the record.)
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718 WAITES (Di)
Idaho Power Company
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1 Q.Please state your name and business address.
2 A.My name is Courtney Waites. My business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company as a
6 Pricing Analyst.
7 Q.Please describe your educational background.
8 A.In December of 1998, I received a Bachelor of
9 Arts degree in Accounting from the University of Alaska
10 in Anchorage, Alaska. In 2000, I earned a Master of
11 Business Administration degree from Alaska Pacific
12 Uni versi ty. I have attended New Mexico State
13 Uni versi ty' s Center for Public Utili ties and the National
Association of Regulatory Utility Commissioners Practical
15 Skills for the Changing Electric Industry conference and
16 the Electric Utility Consultants, Inc., Introduction to
17 Rate Design and Cost of Service Concepts and Techniques
18 for Electric Utili ties conference.
19 Q.Please describe your business experience with
20 Idaho Power Company.
21 A.I became employed with Idaho Power Company in
22 December 2004 in the Accounts Payable Department. In
23 2005, I accepted a Regulatory Accountant position in the
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719 WAITES, DI 1
Idaho Power Company
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1 Finance Department where one of my tasks was to assist
2 responding to regulatory data requests pertaining to the
3 finance scope of work. In 2006, I accepted my current
4 posi tion, a Pricing Analyst, in the Pricing and
5 Regulatory Services Department. My duties as a Pricing
6 Analyst include providing support for the Company's
7 various regulatory activities including tariff
8 administration, regulatory ratemaking and compliance
9 filings, and the development of various pricing
10 strategies and policies.
11 Q.What is the scope of your testimony in this
, 12 proceeding?
13 A. My testimony will address the Company's rate
14 design proposal for the residential customer class.
15 Q.What are your overall obj ecti ves in arriving at the
16 proposed rate design for the customers taking
17 Residential Service?
18 A.Under the direction of Mr. Gale, I have
19 developed a rate design proposal that is both cost-based
20 and encourages increased energy efficiency.
21 Q.How does your proposal implement the directive
22 given to you by Mr. Gale?
23 A.My proposal implements these obj ecti ves by
24 pricing the individual rate components closer to the cost
25 of providing electric service, by increasing the
720 WAITES, DI 2
Idaho Power Company
.1 differential between the first and second energy blocks
2 during the summer months, and by implementing tiered
3 rates in the non-summer months.
4 Q.What are the Company's Residential Service
5 schedules?
6 A.The Company has three Residential Service
7 schedules, Schedules 1, 4, and 5. Schedule 1 is
8 available to all customers taking service for general
9 domestic use. Both Schedules 4 and 5 are optional,
10 time-variant pricing programs and are available only to
11 residential customers in the Emmett valley area who are
12 part of the Company's Advanced Metering Infrastructure.13
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("AMI") Phase One proj ect. The time-variant nature of
these two programs is enabled by the ability of AMI to
15 dynamically capture hourly energy consumption.
16 Schedule 4, the Energy Watch Program, is a
17 fixed-price critical peak pricing program in which
18 participants pay a flat rate for all kilowatt-hours
19 (" kWh") used during the summer months except for those
20 kWh used during an Energy Watch Event. During an Energy
21 Watch Event, the rate is nearly four times higher than
22 the flat rate. Energy Watch Events may be called on up
23 to ten weekdays a year between June 15 and August 15
24 during the hours of 5:00 p.m. to 9:00 p.m..25
721 WAITES, DI 3
Idaho Power Company
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1 Schedule 5, the Time-of-Day Program, defines
2 three time periods during the summer months during which
3 participants pay specific prices for energy consumption:
4 On-Peak, Mid-Peak, and Off-Peak. The Off-Peak rate is
5 the lowest rate and the Mid- and On-Peak rates are 35
6 percent and 85 percent higher, respectively.
7 Q.What is the annual revenue requirement to be
8 recovered from Residential Service customers?
9 A.The annual revenue requirement to be/recovered
10 from Residential Service customers, which includes
11 Schedule 1, Schedule 4, and Schedule 5, is $338,033,548,
12 as shown on page four of Mr. Tatum's Exhibit No. 70.
13 Q. What are the maj or changes to the current rate
design for Residential Service that you are proposing?
A.For Residential Service customers, I am
16 proposing two changes that are common to all residential
17 service schedules, Schedules 1, 4, and 5. The first
18 change is an increase in the Service Charge. The second
19 is the addition of tiered rates during the non-summer
20 months. In addition, I am proposing to modify the block
21 levels and differential between the block Energy Charges
22 during the summer months for Schedule 1 only.
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722 WAITES, DI 4
Idaho Power Company
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1 SCHEDULE 1
2 Q.Please describe the present rate structure for
3 Residential Service under Schedule 1.
4 A.As Mr. Gale stated in his testimony, the rates
5 I will describe as the present rate structure are the
6 rates filed in Case No. IPC-E-08-01 related to the
7 Danskin Combustion Turbine. The actual rates approved by
8 the Commission in Case No. IPC-E-08-01 (Order No. 30559)
9 vary slightly from those originally filed. In Order No.
10 30559, the Commission excluded a relatively small part of
11 the investment from inclusion in rates ($422,000). The
12 Company has not included this small impact in the General
13 Rate Case filing because of the time impact associated
14 wi th reprocessing all the analyses and studies.
15 Residential Service customers taking service
16 under Schedule 1 pay a monthly Service Charge of $4.00.
17 During the non-summer months, September through May, they
18 pay an Energy. Charge of 5. 77 93ç per kWh for all kWh used.
19 During the summer months, June through August, they pay a
20 base Energy Charge of 5. 77 93ç per kWh for the first 300
21 kWh of energy used and 6.5164ç for all energy used over
22 300 kWh.
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723 WAITES, DI 5
Idaho Power Company
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1 Q.Please describe your proposal to increase the
2 Service Charge.
3 A.The Service Charge is intended to recover costs
4 that do not vary with the amount of energy or capacity
5 used. Historically, the Service Charge has been well
6 below the unit cost, meaning that the Service Charge,
7 from a cost of service standpoint, has under-collected
8 the customer-related fixed costs associated with this
9 rate component. In an attempt to meet our obj ecti ve and
10 move the individual rate components closer to the cost of
11 providing electric service, I am proposing to increase
12 the Service Charge to $5.00 per month. The $5.00 per
13 month Service Charge represents approximately 34 percent
14 of the cost-of-service result of $14.89 shown at line 60
15 on page one of Mr. Tatum's Exhibit No. 67.
16 Q.Please describe your proposal for tiered
17 non-summer rates.
18 A.Currently, during the non-summer months,
19 September through May, Schedule 1 customers pay the same
20 rate for all kWh used, 5. 7793ç. I am proposing to
21 implement a two-tier inverted block rate that mirrors the
22 structure of the summer rate design. Customers would pay
23 a lower rate for their first block of energy usage,
24 5.8891ç, and a rate 5 percent higher, or 6.1836ç, for the
25 second
724 WAITES, DI 6
Idaho Power Company
1 block of energy usage..2 Q. Why are you now suggesting a tiered rate for
3 the non-summer months for all residential customers?
4 A.While the Company continues to experience the
5 highest power supply costs during the summer months, the
6 costs during the non-summer months continue to rise.
7 Since 2003, the average non-summer marginal cost has
8 risen 152 percent compared to the average summer marginal
9 cost, which has risen 129 percent. Likewise, the
10 differential between the summer and non-summer marginal
11 costs is decreasing; another indication non-summer
12 marginal costs are on the rise..13 In addition to rising power supply costs during
14 the non-summer months, the usage of the residential
15 customer class has continued to increase consistently,
16 even in years. when summer usage decreased. Similarly,
17 the 2008 peak system coincident demand for the
18 residential customer class is in December and has been in
19 the non-summer months during each of the previous three
20 test years filed in general rate case proceedings. In
21 2008, the forecasted peak demands in December, January,
22 February, and March are all greater than the average
23 summer demand. Keeping with the objectives of the rate
24 design, I am proposing to implement the tiered rate for.25 the non-summer months in an effort to move the
725 WAITES, DI 7
Idaho Power Company
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1 energy rate closer to the marginal cost as well as
2 encourage energy efficiency for the residential customer
3 class year round.
4 Q.How will a tiered rate for the non-summer
5 months encourage energy efficiency?
6 A.Inverted block rates are a mechanism for
7 providing an incentive to customers to conserve energy.
8 By charging customers a higher rate for energy as the
9 amount of energy usage increases, customers are given a
10 price signal to encourage energy efficiency.
11 Q.Please describe your proposal to increase the
12 size of the first block of energy usage during the summer
13 and non-summer months.
14 A.Currently, customers taking service under
15 Schedule 1 pay one rate for the first 300 kWh of energy
16 used (the first block) and a slightly higher rate for all
17 energy used over 300 kWh (the second block). I am
18 proposing to increase the first block of energy usage to
19 600 kWh for both the summer and non-summer months. For
20 the summer months, the rate proposed for the first block
21 is 6.137 6ç per kWh and 7. 3409ç per kWh for all energy
22 used over 600 kWh. During the non-summer months, the
23 proposed rate is 5.8891ç for energy use from 0-600 kWh
24 and 6.1836ç for all energy use over 600 kWh. This
25 proposed rate design
726 WAITES, DI 8
Idaho Power Company
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1 is shown on page one of Exhibit No. 72.
2 Q.In Order No. 29505, the Commission stated that
3 "providing the first 300 kWh of summer usage at the
4 non-summer rate allows some basic electric usage, such as
5 for lighting and home appliances . . ."Why is the
6 Company proposing to increase the size of the first block
7 of energy usage?
8 A.The Company has found that basic electric usage
9 entails more than 300 kWh per month. According to the
10 Department of Energy ("DOE"), the end use consumption of
11 only lighting and home appliances (which includes a
12 refrigerator, electric range, electric oven, a microwave,
13 and a water heater) is 512 kWh per month. Likewise, in
14 their Housing Choice Voucher Program Guidebook, the US
15 Department of Housing and Urban Development ("HUD")
16 estimates 700-850 kWh per month for the same basic
17 electric usage. Based on this information, it appears
18 that 300 kWh is not adequate to cover basic electric
19 service. I have included both the DOE and HUD basic
20 electric usage calculations in my work papers.
21 Q.How' did you determine that 600 kWh per month is
22 the appropriate amount for the first block of energy
23 usage?
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727 WAITES, DI 9
Idaho Power Company
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1 A.First, I looked at the baseline load of the
2 residential class. To estimate the baseline load, I
3 looked at customers' loads during the spring and fall
4 months, a time when it is reasonable to assume that
5 nei ther an air conditioner nor a heater would be running,
6 or, if running, would have minimal usage. This would
7 likely occur in May and October. The 2007 average usage
8 was 806 kWh and 838 kWh, respectively. This average
9 energy usage, which is slightly higher than that detailed
10 by the DOE and HUD studies, would probably include a
11 customer's lighting, basic home appliances (a
12 refrigerator, range, oven, microwave, and water heater)
13 as well as other household appliances such as clocks,
14 stereos/radios, telephones, vacuum cleaners, televisions,
15 and clothes washers and dryers. Next, I looked at the
16 average monthly residential customer energy usage. In
17 Idaho, it was approximately 1,065 kWh per month in 2007.
18 As Mr. Gale stated in his testimony, the Company's
19 obj ecti ve is to encourage energy efficiency for all
20 customers year round. In an effort to incent customers
21 to conserve, I am proposing to set the first block at
22 approximately 60 percent of the average monthly energy
23 usage for the Company's customers in Idaho, or 600 kWh.
24 This level will also align with the basic electric usage
25 studies performed by the DOE and HUD and the
728 WAITES, DI 10
Idaho Power Company
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1 Company's baseline load estimates. Furthermore,
2 adjusting the first consumption tier to 600 kWh will
3 allow a large percentage of what might be considered
4 basic electric usage to be priced at the lower rate while
5 still providing an incentive to conserve.
6 Q.Are there any other changes to the proposed
7 Schedule 1 rate design?
8 A.Yes. In addition to the changes I have
9 discussed, I am proposing to increase the differential
10 between the first and second energy blocks of the summer
11 months. In its Order in Case No. IPC-E-03-13, the
12 Commission found a differential of 12.56 percent to be
reasonable. However, in an effort to keep in line with
the Company's obj ecti ves and move individual rate
15 components closer to the cost of service, I am proposing
16 to increase that differential to 20 percent. According
17 to the cost of service results, the unit energy cost
18 during the summer months is approximately 27 percent
19 higher than the cost during the non-summer months (see
20 page one of Mr. Tatum's Exhibit No. 67). In addition,
21 increasing the differential of 12.56 percent during the
22 summer months to 20 percent will send a stronger price
23 signal to customers encouraging the efficient use of
24 energy, another obj ecti ve of the Company.
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729 WAITES, DI 11
Idaho Power Company
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1 Q. Please summarize the proposed charges for
2 Residential Service customers taking service under
3 Schedule 1.
4 A.The rate design proposal for Schedule 1 is
5 included on page one of Exhibit No. 72. Under the
6 proposed rate design, Schedule 1 customers would pay a
7 $5.00 per month Service Charge. During the summer
8 months, they would pay a base Energy Charge of 6.1376ç
9 per kWh for the first 600 kWh used and 7. 3409ç per kWh
10 for all energy used over 600 kWh. During the non-summer
11 months, they would pay 5. 8891ç per kWh for the first 600
12 kWh and 6.1836ç per kWh for all energy used over 600 kWh.
13 Q. What impact does this rate design proposal have
14 on Residential Service customers taking service under
15 Schedule 1?
16 A.The typical monthly billing comparison for
17 Residential Service customers taking service under
18 Schedule 1 appears on page one of Exhibit No. 73. As
19 shown on this exhibit, for customer's whose usage equals
20 or exceeds 600 kWh, the lower their monthly usage, the
21 lower the overall percentage increase. Also noticeable
22 is the fact that a slightly higher first block will
23 provide some rate relief for lower usage customers.
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730 WAITES, DI 12
Idaho Power Company
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1 Q.Are you proposing any other changes to Schedule
2 1 ?
3 A.No.
4 SCHEDULE 4
5 Q.Please describe the present rate structure for
6 Residential Service under Schedule 4.
7 A.Under Schedule 4, the Energy Watch Program,
8 customers pay a monthly Service Charge of $4.00. During
9 the non-summer months, September through May, they pay an
10 Energy Charge of 5. 7793ç per kWh for all kWh used.
11 During the summer months, June through August, they pay
12 the same rate of 5. 7793ç per kWh except for those kWh
13 used during an Energy Watch Event. During an Energy
14 Watch Event, the rate they pay is 20ç per kWh.
15 Q.Which of the maj or changes that you are
16 proposing for residential service impact Schedule 4
17 customers?
A.There are two proposed changes common to all
19 residential customers that impact customers taking
20 Residential Service under Schedule 4, the increase to the
21 Service Charge and the implementation of tiered block
22 rates in the non-summer months.
23 Q.Are you proposing to increase the Service
24 Charge to $5.00 per month like that of Schedule 1?.25
731 WAITES, DI 13
Idaho Power Company
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1 A.Yes.
2 Q.Please describe your proposal for tiered
3 non-summer rates.
4 A.For Residential Service customers taking
5 service under Schedule 4, I am proposing to implement the
6 same two-tier inverted block rates during the non-summer
7 months I discussed previously for Schedule 1 customers.
8 Customers would pay a lower rate for their first 600 kWh
9 of energy usage and a rate five percent higher for all
10 energy used over 600kWh.
11 Q.Are there any changes to the summer rate design
12 for customers taking service under Schedule 4?
13 A. There are no proposed changes to the summer
14 rate design; however, I am proposing increases to the
15 summer Energy Charges in order to maintain the
16 relationship between the Energy Watch Event rate and the
17 rate for all other kWh used during the summer months as
18 well as keeping the rate for all other kWh used during
19 the summer months equal to the first block of the summer
20 Energy Charge for Schedule 1 customers.
Q.Please summarize the proposed charges for
22 Residential Service customers taking service under
23 Schedule 4.
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732 WAITES, DI 14
Idaho Power Company
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1 A.The rate design proposal for Schedule 4 is
2 incl uded on page two of Exhibit No. 72. Under the
3 proposed rate design, the Service Charge is $5.00 per
4 month. The Energy Charge during the Energy Watch Event
5 hours would increase to 22 ç per kWh. The Energy Charge
6 during all other hours of the summer months would be
7 6.137 6ç per kWh, the same as that proposed for the first
8 block of the summer Energy Charges for Schedule 1.
9 During the non-summer months, customers would pay 5. 8891ç
10 per kWh for the first 600 kWh and 6.1836ç per kWh for all
11 energy used over 600 kWh, the same rates as proposed for
12 customers taking Residential Service under Schedule 1.
13 Q. What impact does this rate design proposal have
14 on Residential Service customers taking service under
15 Schedule 4?
16 A.The typical monthly billing comparison for
17 Residential Service customers taking service under
18 Schedule 4 appears on page two of Exhibit No. 73. As
19 shown on this exhibit, similar to Schedule 1 customers,
20 for customer's whose usage equals or exceeds 600 kWh, the
21 lower their monthly usage, the lower the overall
22 percentage increase.
23 SCHEDULE 5
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Q.Please describe the present rate structure for
Residential Service under Schedule 5.
733 WAITES, DI 15
Idaho Power Company
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1 A.Under Schedule 5, the Time-of-Day Program,
2 customers pay a monthly Service Charge of $4.00. During
3 the non-summer months, September through May, they pay an
4 Energy Charge of 5. 7793ç per kWh for all kWh used.
5 During the summer months, June through August, the Energy
6 Charge customers pay during the On-Peak Period is 8. 8701ç
7 per kWh, during the Mid-Peak Period customers pay 6.5164ç
8 per kWh, and during the Off-Peak Period customers pay
9 4.8084ç per kWh.
10 Q.Which of the major changes that you are
11 proposing impact Schedule 5 customers?
12 A.There are two proposed changes common to all
13 residential customers that impact customers taking
14 Residential Service under Schedule 5, the increase to the
15 Service Charge and the implementation of tiered block
16 rates in the non-summer months.
17 Q.Are you proposing to increase the Service
18 Charge to $5.00 per month like that of Schedule 1?
19 A.Yes.
Q.Please describe your proposal for tiered
21 non-summer rates.
22 A.For Residential Service customers taking
23 service under Schedule 5, I am proposing to implement the
24 same two-tier inverted block rate that I discussed
25
734 WAITES, DI 16
Idaho Power Company
.
.
.
1 previously for Schedules 1 and 4. Customers would pay a
2 lower rate for the first 600 kWh of energy usage and a
3 rate 5 percent higher for all energy used over 600 kWh.
4 Q.Are there any changes to the summer rate design
5 for customers taking service under Schedule 5?
6 A.I am not proposing any changes to the summer
7 rate design, however I am proposing increases to the
8 summer Energy Charges equal to the overall percentage
9 increase for the residential class, or 6.31 percent, to
10 maintain the relationships between the On-, Mid-, and
11 Off-Peak periods.
12 Q.Please describe the proposed charges for
13 Residential Service customers taking service under
14 Schedule 5.
15 A.The rate design proposed for Schedule 5 is
16 shown on page three of Exhibit No. 72. Under the
17 proposed rate design, the Service Charge is $5.00 per
18 month. The existing Energy Charge differentials between
19 the three pricing blocks are maintained with the summer
20 On-Peak Energy Charge set at 9.4298ç per kWh, the summer
21 Mid-Peak Energy Charge set at 6. 9276ç per kWh, and the
22 summer Off-Peak Energy Charge set at 5.1118ç per kWh.
23 During the non-summer months, the Energy Charge would be
24 5.8891ç per kWh for the first 600 kWh and 6.1836ç per kWh
25 for all energy used over 600 kWh.
735 WAITES, DI 17
Idaho Power Company
.
.14
15
16
17
18
19
20
21
22
23
24.25
1 Q.What impact does this rate design proposal have
2 on Residential Service customers taking service under
3 Schedule 5?
4 A.The typical monthly billing comparison for
5 Residential Service customers taking service under
6 Schedule 5 appears on page three of Exhibit No. 73. As
7 shown on this exhibit and similar to Schedules 1 and 4,
8 for customer's whose usage equals or exceeds 600 kWh, the
9 lower their monthly usage, the lower the overall
10 percentage increase.
11 Q.Are you proposing any other changes to
12 Schedules 1, 4, or 5?
13 A.No.
Q.Does this conclude your testimony?
A.Yes, it does.
736 WAITES, DI 18
Idaho Power Company
.
.
.
1 Q.Please state your name.
2 A.My name is Courtney Waites.
3 Q.Are you the same Courtney Waites that has
4 previously presented direct testimony in this case?
5 A.Yes, I am.
6 Q.Have you had the opportunity to review the
7 pre-filed direct testimony of Community Action
8 Partnership Association of Idaho's ("CAPAI") witness Ms.
9 Ottens, Industrial Customers of Idaho Power's (" ICIP")
10 witness Dr. Reading, and Commission Staff's witnesses Mr.
11 Hessing, Mr. Elam, and Mr. Lanspery?
12 A.Yes, I have.
13 Q.What is the scope of your rebuttal testimony?
14 A.My testimony will focus on issues raised by the
15 intervening parties and the Commission Staff regarding
16 the Company's rate design proposals as well as issues
17 raised by the Industrial Customers of Idaho Power with
18 regard to the virtual peaker program. It should be noted
19 that any omission on my part in addressing issues raised
20 by the parties does not indicate my concurrence with
21 those issues.
22
23
24
25
737 WAITES, DI REB 1
Idaho Power Company
.
.
1 I . RATE DESIGN
2 A. CAAI
3 Q. Ms. Ottens's testimony indicates on several
4 occasions (pages 3, 4, and 5) that the proposed rate
5 increase for residential customers is 15 percent. Is
6 that correct?
7 A.No. As shown on page 4 of 4 of Mr. Tatum's
8 Exhibi t No. 70 of the Company's filing, the final revenue
9 allocation to the residential class results in an average
10 increase of 6.31 percent.
11 Q.Are there any other statements in Ms. Ottens's
12 testimony that are incorrect?
13 A. Yes. When discussing the baseline load, CAPAI
14 commends Idaho Power for recognizing the disparity
15 between actual baseline usage and the amount included in
16 the tier but states that "a movement to only 60% of
17 actual baseline load is not adequate ."Ottens,
18 DI, p. 5. The' first tier proposed by the Company at 600
19 kWh was set at approximately 60 percent of average
20 residential class usage, not baseline usage.
21 Q.What is the difference between average usage
22 and baseline usage?
23 A.Average residential class usage includes all
24 end uses of customers in the residential class, which in.25
738 WAITES, DI REB 2
Idaho Power Company
.
.
.
1 2007 was approximately 1,065 per month. As described in
2 my direct testimony, baseline usage refers to the basic
3 electric usage of lighting and home appliances.
4 IPC-E-03-13, Order No. 29505, p. 56. According to the
5 Department of Energy ("DOE") the end use consumption of
6 lighting and ~ome appliances in 2001 is 512 kWh. The
7 U. S. Department of Housing and Urban Development's
8 ("HUD") Housing Choice Voucher Program Guidebook states
9 that lighting and home appliance usage is between 700-850
10 kWh. A first tier of 600 kWh as proposed by the Company
11 would cover more than the Department of Energy's
12 estimation of baseline usage and 71-86 percent of the
13 basic usage as defined by HUD. This level is more in
14 line with the Company's obj ecti ves of encouraging energy
15 efficiency for customers year-round.
16 Q.Do you agree with Ms. Ottens's assertion that
17 customer loads in the spring and fall determine a
18 baseline usage?
19 A.No. Using the end use consumption data from
20 HUD of 700-850 kWh for baseline load, Ms. Ottens
21 inaccurately states "Witness Waites believes that even
22 this is too low and estimates, by relying upon average
23 spring and fall usage, a baseline load for Idaho Power's
24 customers is 806-838 kWh/mo." On page 10 of my direct
25 testimony, I explain that looking at customers' loads
during the spring
739 WAITES, DI REB 3
Idaho Power Company
.
.
1 and fall months, which is the 806-838 kWh usage, would
2 resul t in an overstatement of baseline usage as it would
3 include other household appliances such as clocks,
4 stereos/radios, telephones, vacuum cleaners, televisions,
5 clothes washers and dryers, and may even include some
6 heating and cooling usage.
7 Q.When discussing the level at which the Company
8 set the first tier, Ms. Ottens states "if the level is
9 set at an unreasonably low level then low income families
10 generally will not benefit from this proposal." Do you
11 agree with this statement?
12 A.I agree that the level of the first tier must
13 be set appropriately. However, the Company's proposål
14 actually raises the level at which the first tier is set,
15 from 300 kWh to 600 kWh, which benefits most customers,
16 particularly the low use customers. As I described
17 above, the proposed first tier of 600 kWh will cover a
18 larger percentage, if not all, of a customer's baseline
19 load.
20 Q.In her direct testimony, Ms. Ottens recommends
21 the first tier be set at a higher level. Do you agree
22 wi th her recommendation?
23 A.No. The Commission has stated that the intent
24 of the first block is to cover some basic electric usage,.25 such as lighting and home appliances. Case No. IPC-
740 WAITES, DI REB 4
Idaho Power Company
.
.
.
1 E-03-13, Order No. 29505, p. 56. Using the DOE and HUD's
2 end use consumption data, a first tier higher than 600
3 kWh would, in most cases, cover more than basic electric
4 usage.
5 B. Commission Staff
6 Q.Staff Witness Lanspery proposes a three-tiered
7 rate structure rather than the two-tiered rate structure
8 the Company has proposed because he believes it provides
9 a stronger and more accurate price signal. He also
10 states on page 12 of his direct testimony that the
11 farther a customer is from the tier break point, the
12 weaker the price signal. Do you agree with Mr.
13 Lanspery's three-tiered rate structure?
14 A. No. The Company's research and past experience
15 with tiered rates indicate three-tiered rates confuse and
16 dissatisfy customers. Mr. Lanspery noted in his
17 testimony that PacifiCorp currently has a three-tiered
18 rate structure in Utah. However, in their last general
19 rate case filing, PacifiCorp rej ected the three-tier
20 approach and proposed to go back to a two-tier rate
21 structure. A survey of their customers indicated they
22 did not understand tiered rates and therefore were not
23 responding to the price signals being sent.
24 Idaho Power experienced this same lack of
25 understanding when three-tiered rates were implemented in
741 WAITES, DI REB 5
Idaho Power Company
.
.
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1 May 2001. Customers were very confused and our customer
2 service representatives had a difficult time helping the
3 customers fully understand the rate structure. The
4 Company experienced its lowest customer satisfaction
5 rating ever and had a large number of PUC complaints
6 relating to the rate structure. Whether a two-tiered
7 structure or a three-tiered structure is in place,
8 customers receive a price signal indicating the more
9 energy used, the higher the price. Even though under a
10 two-tiered structure you move further away from the tier
11 break as your consumption rises, your average price per
12 kWh continues. to increase; a price signal is still being
13 sent.
14 Q.Did the Company face other challenges when a
15 three-tiered rate structure was in place?
16 A.Yes. In addition to the three-tiered rate
17 structure being confusing, customers who were owners of
18 all-electric homes felt the Company was now penalizing
19 them for their electric use. And, customers whose bill
20 read dates were further apart had usage falling in the
21 third tier when it may not have otherwise done so had
22 their meter been read sooner. Similarly, master-metered
23 customers had as much as 90 percent of their usage fall
24 in the third tier when it was likely only a portion of
25 this usage should have been priced at the higher rates.
Two-tiered rates can
742 WAITES, DI REB 6
Idaho Power Company
.
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1 effectively send an adequate price signal for all usages
2 while minimizing dissatisfaction among customers.
3 Q.Staff Witness Lobb states that "Staff simply
4 believes that we can and should do more to send the most
5 appropriate price signal to as many residential customers
6 as possible." Does a two-tiered rate structure
7 accomplish this?
8 A.Yes. In fact, based on 2007 actual customer
9 usage, the Company's two-tiered rate structure proposal
10 sends a stronger price signal to a larger percentage of
11 residential customers than does the Staff's three-tiered
12 proposal. Under the Company's proposed rate structure,
13 68 percent of residential customers in the summer months
14 and 66 percent of customers in the non-summer months fall
15 into the second tier and therefore would have experienced
16 a stronger price signal while the top two tiers of Mr.
17 Lanspery' s three-tiered proposal combined would have only
18 impacted 43 percent and 41 percent of customers in the
19 summer and non-summer months , respectively.
20 Q.Why is there such a difference in the number of
21 customers impacted?
22 A.The primary reason is because of the level at
23 which Mr. Lanspery sets the first tier. He proposes a
24 first tier at 1000 kWh. Based on 2007 actual customer
25
743 WAITES, DI REB 7
Idaho Power Company
.
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1 usage, this would mean that 57 percent of customers
2 would, in essence, have a flat rate in the summer months.
3 For the non-summer months, 59 percent of customers would
4 have all of their usage fall in the first block. These
5 customers would receive no price signal at all.
6 Q.Do you agree with Mr. Lanspery' s proposal to
7 set the first tier at 1000 kWh?
8 A.No. As I stated earlier, a first tier at 1000
9 kWh does not meet Staff's obj ecti ve of sending the
10 appropriate price signal to as many residential customers
11 as possible nor does it meet the Company's obj ecti ve of
12 encouraging increased energy efficiency.
13 Q. How would Staff's first block level discourage
14 energy efficiency?
15 A.Wi tness Lanspery proposes setting the first
16 block at 1000 kWh because this is 8 percent below the
17 2008 average usage and he believes an 8 percent reduction
18 in usage is more attainable for customers. However, this
19 approach ignores the fact that while 1000 kWh is 8
20 percent below average annual usage, 1000 kWh is actually
21 above average monthly usage six out of twelve months a
22 year. In fact, the average monthly usage in July 2007
23 and July 2008 was 925 kWh and 922 kWh, respectively.
24 This would mean that during a time when the Company's
25 electrical system is
744 WAITES, DI REB 8
Idaho Power Company
1 typically constrained the most and when we are.2 experiencing our highest system coincident peak, the
3 average residential customer would not be sent an
4 appropriate price signal because all of their usage would
5 fall in the first block. The average residential
6 customer would have no incentive to conserve at a time
7 when the Company would need load reduction the most.
8 Q.Do you have any other issues regarding Mr.
9 Lanspery' s proposal to set the first block at 1000 kWh?
10 A.Yes. When the Commission first established the
11 two-tiered rate structure in Case No. IPC-E-03-13, it
12 indicated the first block of energy usage should allow.13 for some basic electric usage, such as for lighting and
14 home appliances. Order No. 29505, p.56. In his
15 rationale for increasing the first block to 1000 kWh, Mr.
16 Lanspery states heating and cooling should also be
17 included in the basic electric use calculation. However,
18 he also acknowledges that heating and cooling usage is a
19 point at which residential customers begin to differ from
20 one another in their usage patterns, indicating that
21 heating and cooling usage can be somewhat discretionary.
22 Discretionary usage, Mr. Lanspery states, "serves as a
23 poor basis for setting a base." Lanspery, DI, p. 11.
24 Yet, rather than using the shoulder months of May and.25 October as a basis for setting a
745 WAITES, DI REB 9
Idaho Power Company
.
.
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1 block level to cover basic electric usage as the Company
2 has in its proposal, Mr. Lanspery suggests August and
3 January are more appropriate months. In 2007, the
4 residential class usage peaked in the summer month of
5 August and peaked in the non-summer month of January,
6 dri ven primarily by customers' space cooling and electric
7 heat usage. The Company's proposal to base the level of
8 the first tier on the months that customers have the
9 least amount of discretionary energy use, May and
10 October, is more appropriate.
11 Q.Are there other reasons the Company believes
12 the shoulder months of May and October should be used as
13 a basis for setting the level of the first block?
14 A. Yes. In support of using May and October as a
15 basis for setting the first block level, Mr. Lanspery
16 appropriately notes that "what is generally considered
17 basic use, such as lighting, does not translate into
18 efficient use." By setting the first block level
19 slightly below the average May and October usage, the
20 Company attempts to adj ust for inefficient use of
21 electricity. It is important to note, as I discussed
22 earlier in my' testimony, end use consumption of lighting
23 and home appliances according to the DOE is 512 kWh,
24 which falls below the block level of 600 kWh proposed by
25 the Company.
746 WAITES, DI REB 10
Idaho Power Company
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1 At this level, there is still some room for discretionary
2 use to be covered in the first tier and aligns with the
3 Company's obj ecti ves of encouraging increased energy
4 efficiency.
5 Q.Were there any other issues or inconsistencies
6 in Staff's rate design proposal you would like to
7 discuss?
8 A.Yes. Mr. Lanspery states another of his
9 obj ecti ves was to "design a tiered rate structure that
10 provides meaningful signals to customers that incent
11 efficient usa~e but does not unduly punish a subset\ of
12 residential customers." Lanspery, DI, p. 7. He goes on
13 to say that rates should be higher for higher consumption
14 levels, but not to the point that some residential
15 customer face. excessively large increases. However, if
16 adopted, the three-tiered rate structure Mr. Lanspery has
17 proposed would result in a rate for customers whose usage
18 falls in the three-tier that is 21 percent higher than
19 the current rate in the summer months and 29 percent
20 higher than the current rate in the non-summer months.
21 Despi te Mr. Lanspery' s obj ecti ves, this proposal appears
22 to unduly punish higher use customers and raises a
23 significant risk for revenue erosion. Mr. Lanspery
24 agrees with this risk stating that "by pricing it too
25 high there is a significant risk that
747 WAITES, DI REB 11
Idaho Power Company
.
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1 the Company will be unable to collect its
2 Commission-approved costs." Lanspery, DI, p. 7.
3 Q.While the price signal may unduly punish a
4 subset of residential customers, how is Mr. Lanspery' s
5 proposal inconsistent in giving the desired price signal?
6 A.As shown on Mr. Lanspery's Exhibit No. 136,
7 Staff's proposal gives a rate decrease for all customers
8 using less than an average of 1500 kWhs per month, which,
9 based on our 2007 actual billing data, impacts 79 percent
10 of residential customers. The result: a rate design that
11 gi ves a price signal encouraging energy use. Because
12 tiered rates are not able to send a price signal based on
13 the time of day, the risks raised by Staff's rate design
14 could have significant impacts on the Company's revenue
15 recovery while potentially giving the exact opposite
16 price signal desired.
17 Q.Staff has not proposed any adjustments to
18 Schedule 4, the Energy Watch Program, and Schedule 5, the
19 Time-of-Day Program, but commented on the rate
20 differentials. Do you agree with these comments?
21 A.No.. Mr. Lanspery states that the rate
22 differentials of these programs have remained the same
23 since the advent of the pilot programs. This is
24 incorrect. As described in the Company's response to
25 Staff's
748 WAITES, DI REB 12
Idaho Power Company
.
.
.
1 Production Requests Nos. 40 and 108, the differentials
2 between the on-peak and mid-peak rate of the Time-of-Day
3 program were initially set at 11 percent and 30 percent
4 between the on-peak and off-peak rate. The Commission
5 later approved differentials of 36 percent between the
6 on-peak and mid-peak and 85 percent between the on-peak
7 and off-peak. Mr. Lanspery further states the Company
8 should address the rate differentials in these programs
9 in a different venue than a general rate case because
10 these are still considered pilot programs. However,
11 Schedule 4 and Schedule 5 were approved as optional
12 pricing programs by the Commission on April 12, 2007, and
13 no longer have pilot status.
14 Q. Are there any other topics regarding Staff's
15 rate design proposals you would like to discuss?
16 A.Yes. Mr. Gale stated in his direct testimony,
17 "Idaho Power has consistently advocated for the principle
18 that rate spread among the customer classes and for
19 component pricing within the customer classes should be
20 primarily cost-based." Gale, DI, p. 23. Subsequently,
21 all of the Company's rate design witnesses have utilized
22 this underlying principle in their class and rate
23 component pricing proposals. Staff also supports the
24 principle of cost-of-service; Witness Lobb states that
25 rate design
749 WAITES, DI REB 13
Idaho Power Company
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1 should "move toward, but not all the way to cost of
2 service as indicated in the study." Lobb, DI, p. 19. He
3 also states "Staff believes the Company has done a good
4 job of proposing customer rates that meet the Staff
5 obj ectives. " Lobb, DI, p. 20.
6 Furthermore, on page 12 of Staff Witness Hessing's
7 direct testimony, he states "I propose that Cost of
8 Service results be used as a guide in establishing class
9 revenue requirements for the various rate classes" while
10 Staff Witness Lanspery states "effective rate design
11 should be based on sending cost-based price signals that
12 promote efficient consumption of energy." Lanspery, DI,
13 p. 2. Whether it is a Company or Staff witness, all
14 concur that energy efficiency as well as customer equity
15 and effectiveness are all best served when pricing is
16 cost-based.
17 Q.If both Staff and Company witnesses concur that
18 energy efficiency and customer equity are best served
19 when pricing is cost based, what is the Company's
20 concern?
21 A.While it is easier to move pricing components
22 closer to cost when a significant overall revenue
23 increase is being proposed, it is still possible to move
24 closer to cost of service even in a situation when there
25 is no change at all to the rate class's proposed
750 WAITES, DI REB 14
Idaho Power Company
.
.
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1 revenues. The Company's cost of service model clearly
2 illustrates that many rate classes' cost components are
3 out of sync with the current pricing structure. As a
4 resul t, Company Witnesses Nemnich, Bowman, and I all
5 proposed individual rate components for rate classes that
6 would move pricing closer to cost of service. However,
7 contrary to stated obj ecti ves of moving closer to cost of
8 service, the Staff witnesses' recommendations sometimes
9 propose no changes at all or they exacerbate the current
10 inequi ties. For example, in the residential and small
11 commercial classes, the Company's cost of service model
12 clearly indicates there is currently an over-reliance on
13 energy charges and an under-reliance on customer charges.
14 Yet, the Staff recommends no change to the service
15 charges.
16 Even in cases where there is no change in the
17 class's overall revenue requirement, there is still an
18 opportunity to move the pricing components within the
19 class closer to cost of service. As an illustration of
20 this principle, see page 2 of Witness Bowman's workpapers
21 in which Ms. Bowman moves all the rate components 7
22 percent closer to the cost of service. Whether or not a
23 class's overall revenue requirement increases
24 significantly or not at all, movement toward cost of
25 service should occur within
751 WAITES, DI REB 15
Idaho Power Company
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1 the rate class' s individual rate components when the
2 opportuni ty to do so exists.
3 II . VIRTUAL PEAR
4 Q.On page 26 of his direct testimony, ICIP
5 wi tness Dr. Reading states the Company has been "less
6 than enthusiastic about implementing a shared interest in
7 customer owned generation for purposes of meeting peak or
8 providing stand-by reserves." Do you agree with this
9 statement?
10 A.No, I do not. The Company has done substantial
11 research into a virtual peaker program, presenting
12 potential program designs, soliciting input from
13 customers, making on-site visits to customers' premises
14 for interconnection cost studies, and performing
15 financial analyses to determine the feasibility of such a
16 program. Unfortunately, the Company has not found a
17 program design that offers a material economic benefit to
18 the Company or its customers.
19 Q.Has the Company shared its findings with the
20 ICIP?
21 A.Yes. The Company has held several meetings
22 with the ICIP and Commission Staff discussing our
23 research and findings. However, none of those meetings
24 resulted in
25
752 WAITES, DI REB 16
Idaho Power Company
.
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1 an answer that produced a filing for a virtual peaker
2 program.
3 Q.Have any conclusions been drawn from the
4 meetings that were held?
5 A.Yes. The Company has agreed to further analyze
6 a virtual peaker resource option targeting new
7 installations fueled by natural gas as part of its 2009
8 Integrated Resource Plan. Idaho Power has also expressed
9 its willingness to work with interested parties to
10 convene workshops to discuss the possibility of an
11 interruptible rate option.
12 Q.Were there any other issues or inconsistencies
13 in Dr. Reading's testimony you would like to discuss?
14 A. Yes. On page 27 of his direct testimony, Dr.
15 Reading indicates that if emergency generators are
16 installed to operate on natural gas rather than diesel
17 fuel, the cost of energy would be equal to that of Idaho
18 Power's industrial gas turbines. Furthermore, he states
19 that the cost of the capacity would be much lower than
20 that of the gas turbines.
21
22
Q.Do you agree with Dr. Reading's statement?
A.No. In talking with Idaho Power's Power Supply
23 department, it is my understanding that Dr.
24
25
753 WAITES, DI REB 17
Idaho Power Company
.
.
20
21
22
23
24.25
1 Reading's assumption is incorrect. Due to the lower
2 compression ratio required in a spark ignition engine
3 (natural gas), the displacement of the engine must
4 increase by at approximately 25 percent to produce the
5 same amount of power as a diesel generator.
6 Q.Does this increase in engine size cause any
7 issues?
8 A.Yes. According to our Power Supply department,
9 this increase in engine size for the same power output
10 causes several issues. First, the larger, natural gas
11 engine costs nearly double when compared to its diesel
12 counterpart. Second, the larger engines have much more
13 mass and require a longer period of time to startup and
14 begin producing power. Finally, even though the natural
15 gas reciprocating engines have made advances in emission
16 technologies, the lower emission models currently
17 available still produce nearly five times more nitrogen
18 oxides per kilowatt hour than Idaho Power's new Danskin
19 gas turbine.
Q.Does this conclude your testimony?
A.Yes, it does.
754 WAITES, DI REB 18
Idaho Power Company
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1
2 open hearing.)
(The following proceedings were had in
MR. WALKER: And the witness is now
4 available for cross-examination.
3
5 COMMISSIONER SMITH: All right. Mr.
6 Richardson, do you have any questions?
7
8 do.
9
10
11
MR. RICHARDSON: Thank you, Madam Chair, I
CROSS-EXAMINATION
12 BY MR. RICHARDSON:
13 Q Good morning.
Good morning.
Ms. Waites, you address the Company's
16 investigation. into a virtual peaking program; correct?
17
18
14 A
Yes.
And can you tell us how long the Company
19 has been investigating a virtual peaker program?
20
15 Q
A program of the nature for approximately
21 10 years; more recently for the past two years.
22
A
Q
A
Q And who at the Company is in charge of
23 that investigation?
24
25
A
recently.
I have been the lead analyst most
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Idaho Power Company
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1
2
Q And prior to your taking the helm?
A That was before I was with the Company, so
3 I don't know for sure.
4
5 long?
6 A
Q And you've been with the Company for how
7 Q
Four years.
And so you've been in charge of this
8 program for four years?
9 A No, for two.
For two?
Approximately.
And before you were in charge, who was in
There was an analyst immediately prior to
15 me who is no longer with the Company and prior to that,
18
19
10 Q
And who was that analyst?
Danna White.
Okay, and in your investigation into this
20 program, I assume you've looked at other programs around
11 A
12 Q
13 charge?
14 A
16 I'm not sure.
17 Q
A
Q
21 the country?
22
23
A
Q
Correct.
24 in place at Portland General Electric?
And have you looked at the program that's
25 A Yes.
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17
18
1 Q And who is in charge of that program?
2 A Mr. Osborne. I don't recall his first
3 name.
4 Q Okay, and have you done an analysis as to
5 exactly why it is that Portland General finds that this
6 program is successful for them such that they have at
7 least 30 megawatts of installed virtual generation on
8 line and it's not effective, cost effective, for Idaho
9 Power?
10 A It is my understanding that their benefits
11 are different than what the Company, their operational
12 benefi ts are different than what it would be for Idaho
13 Power.
14 Q And have you examined why that is?
15 A Not specifically. We were only able to
16 get limited information from them.
Q Why is that?
A That was all they were willing to
19 provide.
20 Q Are you aware that they have a wealth of
21 information out on the web on their virtual peaking
22 program and the fact that they promote it quite
23 heavily?
24
25
A Yes, I did read that information.
Q And it's your testimony that they won't
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Idaho Power Company
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20
1 provide information to you about why their program is
2 different from what you understand it would work in
3 Idaho?
4 A Could you repeat your question, please?
5 Q I believe you stated earlier that Portland
6 General was resistant to give information on their
7 program.
8 A On what specifically their benefits, where
9 they found the most benefits.
10 Q And what is your understanding of the
11 reason for their reluctance to share information with
12 Idaho Power?
13 A They were willing to share that they
14 recei ve the most benefits in the reserve value. They
15 were reluctant to share and quantify those benefits.
16 Q Don't they have to quantify those benefits
17 to get rate recovery from the Oregon Public Utili ties
18 Commission?
19 A I don't know.
Q Do you know if they filed with the Oregon
21 Public Utilities Commission any rate recovery proceedings
22 at all?
23
24
25
A I'm not familiar.
Q So you haven't looked at what they've done
at the Oregon PUC to receive rate recovery of their costs
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Idaho Power Company
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20
1 of this program?
2 A Not in my involvement in the research.
3 Q On page 17 of your rebuttal testimony
4 is it rebuttal? Yeah, on page 17 of your rebuttal
5 testimony, beginning on line 19, you state in response
6 to, in regards to, Dr. Reading, you state, "he states
7 that the cost of the capacity would be much lOwer than
8 that of gas turbines." Are you aware of the Company's
9 study that indicates on a 20-year levelized fixed cost
10 that according to the Company's 2008 IRP, a simple cycle
11 peaker including transmission is $5.46 where the combined
12 cost of the diesel peaker investigated is estimated to be
13 only $2.63?
14 A Could you repeat your question, please?
15 Q Are you aware that the 20-year levelized
16 fixed cost per kW month according to the 2008 IRP, a
17 simple cycle peaker including transmission is $5.46 where
18 the combined cost of a diesel peaker is estimated to be
19 $2.63?
A I'm not familiar with those numbers, but
21 as I stated in this rebuttal testimony, this information,
22 I'm not the expert in this area. This information was
23 given to me by the experts in our power supply
24 department..25 Q So you're not able to address the
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Idaho Power Company
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1 estimated costs of the virtual peaker program as they
2 compare to other resource potential costs to the
3 Company?
4 A Could you repeat your question, please?
5 Q Yeah. Did you just tell me that you were
6 unprepared to address the comparable costs of a virtual
7 peaker program to the costs of a simple cycle generator
8 identified in your 2008 IRP?
9 A Our power supply department does the
10 financial analyses models for this proj ect. I am
11 familiar with the megawatt-hour cost as approximately
12 $340 compared to the megawatt-hour of a simple cycle
13 peaker which is $80.00 per megawatt. I'm not familiar
14 wi th the numbers you're reading from the IRP.
15 Q Also, on page 17 you talk about the
16 Company has agreed to target new customers as part of
17 its -- to investigate virtual peaking partners, if you
18 will, as part of the Company's 2009 IRP, and on page 18,
19 line 10, you state that natural gas costs are nearly
20 double from a diesel -- when compared to a diesel unit
21 and produce five times the nitrogen oxides than the
22 Company's Danskin unit. Is this analysis going to be
23 included in your 2009 IRP investigation?
24
25
A I'm not involved in the 2009 IRP
investigation, but if this is, as I'm told by our power
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760 WAITES (X)
Idaho Power Company
.1 supply department, a factor, I would guess it would be
2 incorporated.
So what is your role in terms of ensuring
4 that the virtual peaking program is in fact investigated
3 Q
I am not involved in the 2009 IRP, so...
But as the person in charge of the Idaho
8 Power's virtually peaking program, do you think it would
5 in the 2009 IRP?
6 A
9 be prudent for you to insert yourself into the 2009 IRP
7 Q
10 process to ensure that this potential resource is in fact
.
11 investigated?
12 A I believe we have adequate employees that
13 are involved in that process.
16 A
14 Q So there are other people in the Company
15 who are also in charge of virtual peaker investigation?
20
17 Power, yes.
18 Q
It was a team of employees with Idaho
And you're in charge of that team?
I am not in charge of that team.
Oh, I thought you said earlier you were
21 responsible for the program at Idaho Power.
22
19 A
I was the analyst working on the rate
23 design portion of it, the program design.
24.25
Q
A
Q
program?
So you're not the person in charge of the
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761 WAITES (X)
Idaho Power Company
.1 A No, I am not.
Well, who is?
It was a team of employees that was
Is anyone person responsible? If the CEO
6 of Idaho Powe~ said I want to know who is responsible for
2 Q
7 the fact that we don't have a program up and running, who
.
3 A
Ric Gale.
So Ric Gale is in charge of the virtual
He's been involved in the peaker program,
And is he in charge?
I can't say who's in charge. I don't know
But you're the witness the Company put
18 forth to talk about this issue?
4 involved.
5 Q
Correct, because I was working on the rate
20 design piece of it, the program design.
21
8 would he turn to?
9 A
Would you characterize the Company's
22 investigation into a virtual peaker program as one of an
10 Q
23 enthusiastic investigation?
24.25
11 peaker program?
12 A
I believe so, yes.
And the investigation has been going on
13 yes.
14 Q
15 A
16 that.
17 Q
19 A
Q
A
Q
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Idaho Power Company
.1 for 10 years?
2 A That is what I have been told, yes.
And we're not sure who's in charge of the
It's evolved over time. We've had some
How long has Ric Gale been with the
I don't know that for sure.
You note that there's a distinct
11 disadvantage for using natural gas units as a virtual
3 Q
12 peaker because they require a longer time period to start.
4 program?
5 A
13 up. What is the start-up time period for a diesel
17 start-up time is.
18 Q
6 turnover.
7 Q
As I indicated in my testimony, I'm not
16 the expert in that area, so I don't know what the
8 Company?
9 A
And do you know what start-up time is for
19 a natural gas unit?
20
10 Q
14 unit?
15 A
21 and answered.
22
MR. WALKER: Objection, that's been asked
MR. RICHARDSON: The witness testified as
23 to the difficulty of using natural gas as a virtual
24 peaker unit because of the long time to start the unit.25 when compared to a diesel unit and I assume that her
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Idaho Power Company
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1 testimony has some basis in fact.
2 COMMISSIONER SMITH: I'll allow her to
3 answer.
4 Q BY MR. RICHARDSON: Do you know how long
5 it takes to start up a diesel virtual peaking unit?
6 A I do not.
7 Q Okay; so the foundation for your testimony
8 is based upon your discussions with other people on your
9 team?
10 A For the specifics of a natural gas peaking
11 unit, yes.
12 Q And they're not here to testify as to the
13 basis of their understanding, are they?
14 A Correct.
15 Q So we could characterize your testimony as
16 hearsay; correct?
17 MR. WALKER: Objection, Your Honor. She's
18 not an attorney.
19 MR. RICHARDSON: I'll withdraw the
20 question, Your Honor.
21 Q BY MR. RICHARDSON: Has the Company
22 undertaken any analysis calculating the value of using
23 virtual peaking units as reserves?
24.25
A Yes, we have.
Q And what were the results of those
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764 WAITES (X)
Idaho Power Company
1 studies?.2 A I don't have those with me today.
3 Q Did you participate in those studies?
4 A Our power supply department was the one
5 that quantified those.
6 Q And you don't know the results of those
7 studies?
8 A I don't have them with me today.
9 Q Do you know the results of the studies?
10 A I don't know them off the top of my head,
11 no.
12 Since virtual peaking units areQ
13 distributed throughout the Company's service terri tory,.14 has the Company undertaken any analysis calculating the
15 value of reduced transmission and distribution congestion
16 costs during periods of critical peak demand?
17 A Could you repeat your question, please?
18 Q Certainly. Since virtual peaking units
19 would potentially be distributed throughout the Company's
20 service terri tory and particularly located at load
21 centers, has the Company undertaken any analysis
22 calculating the value of reduced transmission and
23 distribution congestion costs during periods of critical
24 peak demand?.25 A I'm not sure if that was included in the
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Idaho Power Company
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18
1 interconnection cost analyses.
2 Q So as a member of the team, would that be
3 something that you would seek to have included in the
4 2009 IRP investigation into this program?
5 A Would you repeat your question, please?
6 Q As a member of the virtual peaking team,
7 would you attempt to make sure that this issue that I
8 just asked about is also included in the investigation
9 and analysis conducted as part of the 2009 IRP process?
10 A I can make sure it's included.
11 Q And would you?
12 A Yes.
13 Q Changing topics a bit, were you in the
14 room when President Keen stated that anything the Company
15 can do to manage peak in the summer would be a benefit to
16 Idaho Power?
17 A Yes, I was in the room.
Q And you state in your rebuttal testimony
19 that Mr. Lans~ery' s rate proposal would "unduly punish
20 higher use customers and raises a significant risk for
21 revenue erosion," and that's at page 11, line 20 if you
22 need the reference. Do you recall that?
23
24
25
A Yes, I do.
Q Do you agree that changing customer
behavior to align demand with cost is one of the goals of
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766 WAITES (X)
Idaho Power Company
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18
19
1 an effective rate design?
2 A Yes.
3 Q Doesn't this mean that customers would be
4 lowering electric consumption during high cost periods?
5 A That could be true, yes.
6 Q Isn't that one of the goals of an
7 effective rate design is to reduce consumption during
8 high cost periods?
9 A Yes.
10 Q And if in fact customers respond to an
11 effective rate design that causes them to reduce
12 consumption during high cost periods, wouldn't that lower
13 revenues for the Company?
14 A It could potentially.
15 Q So wouldn't it be fair to say that
16 "revenue erosion" is a natural consequence of aligning
17 rates with costs?
A Could you repeat your question, please?
Q Certainly; so wouldn't it be fair to say
20 that "revenue erosion," which is the words you used in
21 your testimony, that that is a natural consequence of
22 aligning rates with costs?
23
24.25
A It could be.
Q Well, you stated earlier that aligning
rates with costs would reduce revenues.
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Idaho Power Company
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1 A Pardon?
2 Q You agreed with me that because lower
3 customer consumption in response to higher costs during
4 high cost time periods would lower revenue for the
5 Company.
6 A It could.
7 MR. RICHARDSON: Okay. Madam Chair,
8 that's all I have.
9 COMMISSIONER SMITH: Thank you, Mr.
10 Richardson. Mr. Purdy.
11 MR. PURDY: Thank you, Madam Chair.
12
13 CROSS-EXAMINATION
14
15 BY MR.PURDY:
Q Good morning,Ms.Waites.
A Good morning.
Q I just want to ask you a few questions
about your tiered rate proposal,and I want to start off
16
17
18
19
20 wi th a brief discussion of semantics. If you could,
21 would you turn to page 9 of your direct testimony for me?
22 Are you there?
23
24.25
A Yes.
Q Now, you've criticized or critiqued Ms.
Ottens on behalf of Community Action for her tiered rate
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Idaho Power Company
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1 proposal, characterizing her testimony as incorrect; is
2 that a fair statement? And if you need a reference,
3 that's in your rebuttal. I'm jumping around a little.
4 A I believe that in my rebuttal testimony I
5 state there are some statements she makes that are
6 incorrect.
7 Q Okay, and one of those has to do with her
8 selection of the appropriate benchmark on which to base a
9 first-tiered rate block; is that correct?
10 A I believe on page 2 of my rebuttal
11 testimony I state that the statement she makes beginning
12 on line 16 "a movement to only 60 percent of actual
13 baseline load is not adequate."
14 Q And you go on to discuss her selection of
15 be it baseline load or some other terminology is what you
16 take exception with; right?
17 A What I'm stating here is that I did not
18 use 60 percent of baseline load to set the first block.
19 I used 60 percent of average load.
20 Q Okay. Well, just to briefly illustrate,
21 perhaps, and clear up some confusion here, if you could
22 turn back to page 9 of your direct testimony, I'm just
23 going to real' quickly go through the various terminology
24 that you've employed, and that is, first, on line 8,
25 basic electric usage; line 10, end use consumption; then
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Idaho Power Company
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20
1 over on page 10, line 1, baseline load; on line 7,
2 average usage; and line 8, average energy usage; line 15,
3 average monthly residential customer energy usage; and on
4 line 21, average monthly energy usage.
5 Now, I'm not trying to be unduly harsh, I
6 just want to understand, again, the semantics of this and
7 perhaps have you as succinctly as possible describe for
8 the Commission how you came up with the 600 kilowatt-hour
9 proposed first-tier block and what benchmarks you used
10 and precisely what you call that benchmark.
11 A Sure. Turning back to page 9 of my direct
12 testimony, basic electric usage was defined by the
13 Commission in the 2003 rate case Order. That includes
14 lighting and home appliances. I use baseline usage
15 synonymously with that; whereas, average usage is all end
16 usage, usage of residential customers, so that would
17 include your basic and then anything on top of that, your
18 heating, your cooling, TVs, computers, that type of
19 thing.
Q So let me stop you there, baseline is
21 synonymous with what?
22
23
24.25
A Basic.
Q Basic usage?
A Yes.
Q Thank you. Please continue.
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Idaho Power Company
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1 A Could you repeat your question?
2 Q Well, I just asked you a very general
3 question to describe, and if you're done, you're done,
4 how you calculated the 600 kilowatt-hour proposed block
5 and what you base that off of.
6 A Okay; so using the basic electric usage
7 that the Commission defined in the 2003 rate case Order,
8 i looked at some end use consumption studies that
9 indicated lighting and home appliances was actually, if
10 you look at the DOE studies, closer to 512 kilowatt-hours
11 a month or if you looked at the HUD Housing Choice
12 Voucher Program Guidebook, it was approximately 700 to
13 850 kilowatt-hours, so 600 kilowatt-hours a month seemed
14 like a reasonable amount to cover basic electric usage.
15 Again, looking at Idaho Power customers to
16 determine a basic electric usage, I looked at the
17 shoulder months May and October, thinking that at that
18 time you would have basic and then maybe if you had any
19 heating or cooling, it would be minimal and just some
20 discretionary usage in there, so I looked at the 2007
21 average usage for those months, which was approximately
22 800 kilowatt-hours a month, so setting that block at 600
23 seemed like a. reasonable amount to exclude any
24 discretionary usage or any heating and cooling usage.
25 Q All right, but when you just used the term
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771 WAITES (X)
Idaho Power Company
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1 I looked at the average of 800 kilowatt-hours a month,
2 that,again,is exclusive of perhaps a great number of
forms of energy consumption,including heating and
cooling,is it not?
A The average usage in May and October is
all end usage of the residential class.
3
4
5
6
7 Q Well, please look at page 10, line 17 of
8 your direct testimony. You refer to 1,065 kilowatt-hours
9 per month in 2007. What does that reflect?
10 A That's the average for the year. If you
11 take all the usage of the residential class for 2007
12 di vided by the bills, that's the average for the year.
13 Q Total consumption divided by 12?
14 A Correct.
15 Q Okay; so essentially you've utilized, I
16 don't mean to. appear dense, but maybe I am, you've taken
17 the shoulder month usage and is it May and October; is
18 that correct?
19
20
A Yes.
Q And just assumed that that is more or less
21 exclusi ve of any heating and cooling; correct?
22 A The assumption is that there may be
23 heating and cooling in there, but it would be minimal.
24
25
Q All right. Now, if you would look,
please, back to your direct on page 9, beginning on line
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Idaho Power Company
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1 9, you state that according to the Department of Energy,
2 the end use consumption of only lighting and home
3 appliances, and you then specify that that includes a
4 refrigerator, electric range, electric oven, microwave
5 and water heater, is 512 kilowatt-hours a month. You
6 compare that, however, with a differing opinion by HUD of
7 700 to 850 and that's the range that you've utilized to
8 come up with the 600, is it not?
9 A Correct.
10 Q All right, and 850, I think as we know, is
11 what Ms. Ottens proposes to be the first-tier block
12 level; correct?
13 A Ms. Ottens didn't propo5e a level in her
14 testimony.
15 Q Are you aware that in a response to
16 discovery, to a discovery request by Idaho Power, she
17 clarified that to be 850 kilowatt-hours?
18 A I don't have that in front of me. I was
19 remembering something different.
20
21
22
23
Q What do you remember?
A I was remembering 800.
Q All right. Well, we'll clear that up
later. If the assume hypothetically, subj ect to
24 check, for me, if you will, that she did clarify that to
25 be 850 kilowatt-hours per month and if that just includes
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773 WAITES (X)
Idaho Power Company
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1 the appliances listed, the refrigerator, electric range,
2 electric oven, microwave and water heater, isn' t it fair
3 to say that that's a pretty -- I don't know if lifeline
4 level of consumption is the appropriate terminology or we
5 ought to just keep it more conceptual and say that that's
6 pretty bare bones in terms of energy consumption for any
7 residential customer, is it not? Not a lot of fat on the
8 meat there?
9 A Right.
10 Q All right. In reality, a person is
11 probably going to need more than that to survive in this
12 day and age, are they not?
13 A I don't know.
14 Q Well, do you have your heater running
15 right now?
16 A Yes.
17 Q It's pretty chilly out. Wouldn't it be
18 wise to recognize that perhaps this range is quite a bit
19 on the low side of what it takes for the average
20 residential customer to make it through a month in terms
21 of electric consumption?
22 A Not according to some of the studies I
23 reviewed.
24
25
Q Really? You think that just these
appliances listed are sufficient to get through the
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774 WAITES (X)
Idaho Power Company
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1 average day for a residential customer?
2 A Those appliances and lighting are what's
3 considered basic electric usage as defined by the
4 Commission in their Order.
5 Q But you are proposing a deviation from
6 that Order, are you not?
7 A I'm not proposing a deviation from the
8 definition.
9 Q All right. If we are to now, I believe
10 in a question from Commissioner Kempton to Ms. Drake --
11 you were here for that question, were you not?
12 A Yes.
13 Q Commissioner Kempton suggested that
14 perhaps according to Ms. Drake's testimony, the
15 industrial class poses a greater opportunity to obtain
16 energy efficiency resources than the residential class.
17 Do you recall that testimony?
18 A Yes, I do.
19 Q All right; so I think we can agree, can we
20 not, that trying to capitalize on whatever DSM energy
21 efficiency resource the residential class offers is
22 something we should strive to do?
23
24.25
A Correct.
Q All right. If we set the threshold for
the first-tier block rate too low for the residential
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775 WAITES (X)
Idaho Power Company
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1 class, are we running the risk of losing that resource
2 insofar as if a customer is not able to survive, to exist
3 on simply 600 kilowatt-hours a month, they're going to
4 blow through that first block fairly quickly in a month
5 and it sort of gets lost in the distance in terms of
6 sending a price signal, does it not?
7 A A customer is still sent a price signal no
8 matter where the level is set.
9 Q Well, if you set it at 50 kilowatt-hours
10 for the first block, that's not very meaningful in terms
11 of a price signal, is it?
12 A A price signal is still sent, though.
13 Q Well, that's not my question. My question
14 is how meaningful is that going to be if they cannot
15 achieve it?
16 A The average price per kilowatt-hour would
17 still go up for each kilowatt-hour that's used.
18 Q And Staff in this case has proposed a
19 first-tier block rate of 1,000 kilowatt-hours; is that
20 right?
21
22
A Correct.
Q All right. Do you recall, and if you
23 don't, I'm not asking you to testify on behalf of Staff
24 or necessarily interpret their testimony, but do you
25 recall why Mr. Lanspery proposed a significantly higher
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Idaho Power Company
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1 first block threshold?
2
3
A
Q
I don't recall why.
You don't, all right. You did review that
4 testimony, I assume, prior to hearing?
5
6
A I did.
7 Madam Chair. Thank you.
MR. PURDY: I will leave it at that,
8
9 Mr. Olsen.
10
11
12
13
14
15
COMMISSIONER SMITH: Thank you, Mr. Purdy.
MR. OLSEN: I have no questions.
COMMISSIONER SMITH: Mr. Ward.
MR. WARD: No questions. Thank you.
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: No questions.
COMMISSIONER SMITH: Mr. Miller is not
16 here, so, Mr. Price, it's all yours.
17
18 Madam Chair.
19
20
21
22 BY MR. PRICE:
23
24
25
A
Q
Q
MR. PRICE: I'm up. Thank you,
CROSS-EXAMINATION
Good morning, Ms. Waites.
Good morning.
All right. Well, you take some issue with
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Idaho Power Company
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18
1 Mr. Lanspery' s setting of the first-tier block at 1,000
2 kilowatt-hours; correct?
3 A Correct.
4 Q And if the Commission were to order the
5 first tier to be set at 1,000 kilowatt-hours, that
6 wouldn't be the first time that it had done so;
7 correct?
8 A Correct.
9 Q And that was back in 2001 through 2002;
10 correct?
11 A I believe it was May through May, yes.
12 Q And prior to 2001, the rate structure was
13 a flat rate structure; correct?
14 A Correct.
15 Q So residential customers went from a flat
16 rate to a three-tier rate in 2001?
17 A Correct.
Q And you mention in your testimony and
19 cross, your direct testimony and cross testimony,
20 rebuttal testimony, that the Company experienced some
21 feedback from customers that was negative regarding the
22 three-tier structure; correct?
23
24
25
A Correct.
Q Isn't it true that during the period of
2001-2002 that the Company's rates increased
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778 WAITES (X)
Idaho Power Company
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1 precipitously in the matter of approximately 31
2 percent?
4 I know they did increase.
I'm not familiar with the percentage, but3A
Did you review Mr. Lanspery' s testimony in
Yes, I did.
Do you recall him referring to a
9 Commission Order in that testimony?
5 Q
i do.
That Order number, I can refer you to it,
12 Mr. Lanspery' s testimony at page 20.
6 this case?
7 A
I don't have that in front of me.
MR. KLINE: We can get it.
16 it's page 20, starting with line 19.
MR. PRICE: And for those following along,
8 Q
17 (Mr. Kline approached the witness.)
18
10 A
11 Q
13 A
14
15
19 page was that?
20 Q
THE WITNESS: Thank you. I'm sorry, what
BY MR. PRICE: That would be page 20, line
21 19, Mr. Lanspery's direct testimony, and he cites to
22 Commission Order 29026 and it states -- could you please
23 read the paragraph starting with the block quote?
24
25
A Sure. "Although it is appropriate to use
flat residential rates this year, this Order should not
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Idaho Power Company
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1 be interpreted as precluding the use of tiered rates in
2 the future. We believe that last year's tiered rates
3 were effective in sending a price signal to customers to
4 conserve. However, many of these customers experiencing
5 an increase of 31 percent or more had limited ability to
6 significantly alter energy consumption...". Keep going?
7 Q Yes, please, to the next page.
8 "A once they received the price signal.
9 It is our belief that with additional customer education
10 and increased availability of residential DSM programs
11 like Time-of-Use metering, tiered residential rates may
12 be an appropriate rate design option in the future as
13 circumstances dictate."
14 Q Okay, thank you very much; so would you
15 agree with the Commission in that it is most likely
16 difficul t for residential customers to distinguish on
17 their bill between a general rate increase of
18 approximately' 31 percent and the three-tier structure
19 that went in about the same time?
20
21
A I don't know.
Q You said that the Company received a lot
22 of feedback regarding the three-tier structure. Wasn't
23 most of that feedback associated with the dramatic rise
24 in the customers' bills?
25 A It was confusion about the rate design.
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Idaho Power Company
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20
1 Q Did it include any comments regarding the
2 rise in the rates?
3 A The data I looked at specifically, I was
4 just concerned about the rate design. I'm not familiar
5 if any of that had to do with -- we can differentiate
6 between those two.
7 Q Okay, and just for the record, Staff, as
8 far as you know, is not proposing a general increase for
9 the residential class in this case?
10 A Correct.
11 Q So we wouldn't have any of those sorts of
12 problems of confusion between a general rate increase for
13 residential class versus a three-tier structure being
14 implemented at the same time?
15 A A customer who is a high use customer may
16 not understand that the difference, the reason their bill
17 is going up under Staff's proposal is because of the rate
18 design and not an increase in rates.
19 Q Okay. You also state in your rebuttal
testimony that you cite to PacifiCorp' s experience
21 with a three-tier structure; correct?
22
23
A Correct.
Q And you state that -- let me get this
24 right. Page 5, lines 15 through 20 of your rebuttal, you.25 state that Mr. Lanspery noted that PacifiCorp had a
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Idaho Power Company
.1 three-tiered structure and that PacifiCorp rej ected that
2 three-tier approach and went back to a two-tier structure
3 and that they surveyed their customers and it indicated
4 that they didn't understand the tiered rates; is that
5 your testimony?
6 A Correct.
7 Q I have -- may I approach the witness?
8 COMMISSIONER SMITH: Yes, you may.
9 (Mr. Price approached the witness.)
10 MR. PRICE: I have a little handout here.
11 I think the exhibit number we left off with was 154.
12 ( Staff Exhibit No. 154 was marked for.13 identification. )
14 Q BY MR. PRICE: Could I have you turn to
15 the second page, they're not numbered, the second page of
16 this survey, and just for the record, could you please
17 read the title on the first page?
18 A Rocky Mountain Power, Utah Residential
19 Rate Survey, Final results.
20 Q Have you reviewed this document previous
21 to today?
22 A No, I have not.
23 Q So the survey that you're referring to in
24 your rebuttal testimony doesn't include this survey?.25 A The information I provided in my rebuttal
CSB REPORTING
[phone]
782 WAITES (X)
Idaho Power Company
.
.
.
1 testimony was taken from testimony of a witness in the
2 Rocky Mountain Power rate case.
3 Q And could you please for the record recite
4 what date this survey was effective or conducted?
5 A September 10th through the 19th, 2007.
Can you now turn to page 2 and would you
7 read the line starting with Q1B?
6 Q
"Ease of understanding your electric
And from reviewing this as a customer
11 service analyst, can you tell me whether the number
8 A
12 what was the means score at the bottom there?
9 rates. "
10 Q
7.42.
And in your experience, what would that
15 reflect regarding this question?
13 A
That you have a portion of your customers
17 that don't understand your rates.
18
19
20
14 Q
And what would that portion be?
Approximately 30 percent.
And what portion would you say -- where
21 would the means score of 7.42 fall at? What percentage
16 A
22 of the customers are at or above that level?
23
24
25
Q
A
Q
A
Q
Approximately 70 percent, 65.
So it's fair to say that an overwhelming
maj ori ty of the customers for PacifiCorp understood their
CSB REPORTING
[phone]
783 WAITES (X)
Idaho Power Company
.
.
.
18
1 rates?
2 A I wouldn't sayan overwhelming, no.
3 Q More than a maj ori ty?
4 A More than average.
5 Q All right, you also in your rebuttal
6 testimony address the problem of those who heat their
7 homes with only electric heat; correct?
8 A Correct.
9 Q And in the Commission's previous
10 institution of the three-tiered rate structure, the
11 second-tiered rate in non-summer months, the tier break
12 was at 2,000 kilowatt-hours a month; correct?
13 A That is what I'm remembering, yes.
14 Q And in Mr. Lanspery's proposal, he
15 includes approximately 3,000 kilowatt-hours for that
16 second-tier break; correct?
17 A Correct.
Q So in comparison to those two three-tiered
19 rate structures, Mr. Lanspery' s proposal gives
20 approximately 1,000 more kilowatt-hours a month for
21 non-summer residential users; correct?
22 A In the second tier or the third tier? I'm
23 sorry.
24
25
Q For the second tier until the third tier
actually takes effect; correct?
CSB REPORTING
[phone]
784 WAITES (X)
Idaho Power Company
.
.
.
1 A Correct.
2 Q And you mentioned in your rebuttal in your
3 testimony today that customers had a hard time
4 understanding the three-tier structure in that '01
5 through' 02 period. What, if anything, has the Company
6 done to educate customers regarding a tiered rate
7 structure?
8 A I'm not familiar with what education the
9 customer service representatives use when they have a
10 customer on the phone and discuss the rate structure.
11 Q Does the Company have any education
12 programs available to inform customers regarding tiered
13 rates?
14 A I don't know.
15 Q Is it your understanding when I believe we
16 just read from Mr. Lanspery' s testimony and in that Order
17 that we read the Commission ordered the Company to
18 undergo education programs, is that accurate, to inform
19 its customers. regarding tiered rates? Again, that's on
20 page 20 through 21 of Mr. Lanspery's testimony.
21 A I don't believe it is ordered. It says,
22 "It is our belief that with additional customer
23 education. . . ".
24
25
Q Okay; so do you think that education
programs would be helpful in order for residential
CSB REPORTING
[phone]
785 WAITES (X)
Idaho Power Company
.
.
.
18
1 customers to understand the tiered rate structure?
2 A Possibly.
3 Q And you're not aware of any current
4 education programs that the Company has to inform
5 residential users regarding tiered rates?
6 A I'm not aware of any.
7 Q In your rebuttal at page 5, lines 15
8 through 20, again, you note that Utah or PacifiCorp to
9 the Utah Commission proposed a two-tier structure in its
10 last general rate case; is that correct?
11 A Correct.
12 Q And that's not the current rate case that
13 was filed in April; correct?
14 A They proposed it in the 2007 case and
15 again in the 2008 case.
16 Q Do you know whether the Utah Commission
17 approved the two-tiered rate structure in 2007?
A It is my understanding that they kept the
19 three-tiered structure.
20 Q And PacifiCorp signed a stipulation, in
21 fact, that kept that three-tiered structure in place;
22 correct?
23
24
25
A Yes.
Q You state in I'm going to refer you to
page 8 of your rebuttal, lines 21 through 23 -- you state
CSB REPORTING
(208) 890-5l98
786 WAITES (X)
Idaho Power Company
.
.
.
1 in there that the average monthly usage of July 2007 and
2 July 2008 was 925 and 922 kilowatt-hours, respectively.
3 Is that through any analysis? I'm curious as to where
4 that number emanates from. Was it included in any
5 exhibits?
6 A That's a monthly report that's filed with
7 the Commission with the fixed cost adj ustment.
8 Q And that's just for the July month;
9 correct? I think you had stated earlier that the average
10 yearly usage averaging all the months is well over 1,000
11 kilowatt-hours; correct?
12 A Just over 1,000.
13 Q On page 11, lines 15 through 20, in there
14 you state Mr. Lanspery' s proposal would lead to a rate
15 that is 21 percent higher than the current rate in the
16 summer months and 29 percent higher than the current rate
17 in the non-summer months?
18 A Correct.
19 Q And you're just referring to the actual
20 kilowatt-hour rate; right?
21
22
23
24
25
A Correct.
Q Not the customers' bills?
A No, the rate.
Q So the customers wouldn't see a 21 percent
increase in their actual bill?
CSB REPORTING
[phone]
787 WAITES (X)
Idaho Power Company
.
.
1 A The rate would be 21 percent higher.
2 Q You talk about the risk of revenue
3 erosion. I believe you spoke to that with
4 Mr. Richardson. Doesn't the Company have a fixed cost
5 recovery mechanism to compensate for revenue erosion?
6 A We do have a fixed cost adjustment rate,
7 yes.
8 Q And the purpose of that fixed cost
9 adj ustment is to allow or remove the disincentive for the
10 Company to engage in energy efficiency programs like
11 tiered rates; correct?
12 A I am not familiar, as familiar with the
13 fixed cost adjustment rate, so I can't answer that.
14 Q I just have one more actually exhibit that
15 I would like to enter into the record and it is regarding
16 a question that has already been asked.
17 (Mr. Price approached the witness.)
18 Q BY MR. PRICE: I asked you if in 2007 that
19 PacifiCorp stipulated to keeping the three-tiered rate
20 structure. Also, in that stipulation, were you aware
21 that the Company consented to undergo education programs
22 for its residential customers regarding tiered rates?
23
24.25
A Yes, I am.
Q And that is the document that is before
you; is that correct?
CSB REPORTING
[phone]
788 WAITES (X)
Idaho Power Company
.
.
1 A That is correct.
2 MR. PRICE: I believe that would leave us
3 at Exhibit 155.
4 COMMISSIONER SMITH: So we'll mark that
5 Exhibi t 155.
6 (Staff Exhibit No. 155 was marked for
7 identification. )
8 Q BY MR. PRICE: And just for the record,
9 can you confirm that that is a portion of the stipulation
10 entered in the 2007 PacifiCorp rate case to the Utah
11 Commission?
12 A This looks like the document I reviewed.
13 MR. PRICE: Thank you~ I have nothing
14 further.
15 COMMISSIONER SMITH: Thank you. Are there
16 questions from the Commission? Commissioner Kempton.
17
18 EXAMINATION
19
20 BY COMMISSIONER KEMPTON:
21 Q . Ms. Waites, in your rebuttal testimony on
22 page 9, you talk about the average residential customer.
23 It goes on to say that during time of constrained peak
24 that the average residential customer would not be sent.25 an appropriat~ price signal because all of their usage
CSB REPORTING
[phone]
789 WAITES (Com)
Idaho Power Company
.
.
.
1 would fall in the first block. Well, statistics are
2 interesting, but let's talk about the person below the
3 average and the person above the average. Would the
4 person below the average be inclined to use more power as
5 a result of the fact that the average is at 1,000
6 megawatts?
7 A They may.
8 Q They may? My question is would they?
9 Would they be inclined to use more power?
10 A Possibly if they wanted their house cooler
11 to be more comfortable.
12 Q Would the person above the average be
13 inclined to reduce their power?
14 A They may.
15 Q So we can safely say that considering the
16 point where the average person is referred to here refers
17 only to a statistical average and that one person is
18 basically what's being described in this section of your
19 testimony, your rebuttal. It is an average residential
20 customer and there are customers above the average and
21 customers below the average?
22
23
A Correct.
Q If a person were to retain the same amount
24 of usage that they had before this was put in and let's
25 say they were. using 600 megawatts and if that person
CSB REPORTING
[phone]
790 WAITES (Com)
Idaho Power Company
.
.
1 continued to use 600 megawatts, would that have any
2 effect on Idaho Power's financial recovery from the month
3 where the 1,000 megawatt tier started? In other words,
4 if they were using 600 megawatts on one day and the next
5 day the tiered rate was put in and they were using power
6 that day and they also used the same 600 kilowatts, their
7 consumption didn't change, would that affect Idaho
8 Power's financial revenue on those two comparisons?
9 A As long as the rate was designed to be
10 revenue neutral, no.
11 Q Okay, and if the person, say, is higher
12 than this and, let's say, they're using 1,200 kilowatts
13 and they're 200 kilowatts above the 1,000 kilowatt base,
14 on the first case, they would be using 1,200 kilowatts
15 and in the second case they would be using 1,200
16 kilowatts, 200 above the 1,000 and they would be
17 penalized for it, would that affect Idaho Power's revenue
18 recovery?
19 A As long as the rate was designed revenue
20 neutral, no.
21 Q And would there be a reduction -- if that
22 person then were to reduce their use back down to 1,000
23 kilowatts because of the tier, would there be efficiency
24 in the system as a result of the recovery of those 200.25 kilowatts?
CSB REPORTING
[phone]
791 WAITES (Com)
Idaho Power Company
.
.
20
21
1 A I'm sorry, can you repeat that?
2 Q Would there be a recovery -- would there
3 be energy efficiency recovery as a result of the person
4 that's above the average at 1,200 kilowatts if he dropped
5 back down to 1,000 kilowatts?
6 A No.
7 Q What happened to the 200 kilowatts that he
8 didn't use?
9 A I'm sorry, I guess I'm not understanding.
10 Q This is not a very difficul t situation.
11 There's a customer at one point in time before this goes
12 into effect is using 1,200 kilowatts, all right, before
13 it went into effect.
14 A Correct.
15 Q When it goes into effect, he's no longer
16 an average system customer, he's now one that's above the
17 average and he's at 1,200 kilowatts and he has a penalty
18 to pay because you have a rate increase at 1,000
19 kilowatts; correct?
A Under Staff's proposal, yes.
Q If he is inclined because of the fact he's
22 paying more to come back down to 1,000 kilowatts, there's
23 no impact to Idaho Power's recovery, but there is 200
24 kilowatts of energy efficiency that's recovered; is that.25 correct?
CSB REPORTING.
[phone]
792 WAITES (Com)
Idaho Power Company
.
.
1 A Correct.
2 Q My point is that there's a difference
3 between a statistical average that gives you no benefit
4 and the person in the real world who's below that at 600
5 kilowatts and the person who is above that at 1,200
6 kilowatts, they see this differently. They are not the
7 average person and that makes all the difference in how
8 the energy was recovered; is that not true?
9 A That is correct.
COMMISSIONER KEMPTON:Thank you.
COMMISSIONER SMITH:Is that it?
COMMISSIONER KEMPTON:No more.
COMMISSIONER SMITH:Any questions?
COMMISSIONER REDFORD:No questions.
10
11
12
13
14
15
16 EXAMINATION
17
18 BY COMMISSIONER SMITH:
19 Q I just had one. Looking at your direct
20 testimony, Ms. Waites, I notice on page 4 you state, "I
21 am proposing two changes," and you're proposing to modify
22 the block levels and the differential, and on 6, you
23 proposed to implement two-tier inverted blocks, and on 7,
24 you proposed the first block of energy usage at 600, and.25 on page 11, you're proposing to increase the differential
CSB REPORTING
[phone]
793 WAITES (Com)
Idaho Power Company
.
.
.
1 between the first and second energy blocks and my
2 question is, are you the person who decided on the 600
3 kWh number?
4 A Yes.
5 Q And what were your policy reasons for
6 that?
7 A I looked at the definition of the basic
8 electric usage.
9 Q So it was basically a mathematical
10 exercise in your mind?
11 A Correct, based on end use consumption
12 surveys.
13 Q And not the kind of question that
14 Commissioner Kempton just posited about the view of the
15 customer and their usage and the levels?
16 A No.
17 COMMISSIONER SMITH: Thank you. Do you
18 have any redirect, Mr. Walker?
19
20 Madam Chairman, could we take a short break or could I
MR. WALKER: Yes, just a few. Actually,
21 have just have a couple of minutes?
22
23
24
25
COMMISSIONER SMITH: Yes, you may.
MR. WALKER: Thank you.
(Pause in proceedings.)
COMMISSIONER SMITH: Let's go back on the
CSB REPORTING
[phone]
794 WAITES (Com)
Idaho Power Company
.
.
.
17
18
1 record. Mr. Walker.
2 MR. WALKER: Thank you.
3
4 REDIRECT EXAMINATION
5
6 BY MR. WALKER:
7 Q Ms. Waites, there was a lot of discussion
8 about Staff's and the Company's rate design proposal.
9 Could you tell us again what the goals of your rate
10 design were? What were the main goals?
11 A The two main goals were to move the
12 components of the rates closer to the cost of service ånd
13 to encourage energy efficiency.
14 Q And are those generally the same that
15 Staff was seeking to accomplish?
16 A Yes.
Q What's the main difference?
A Staff's proposal does not move the rates
19 closer to the cost of service.
20 Q What's the concern about setting a first
21 block larger than what you have proposed, what's your
22 concern with that?
23 A The biggest concern is during the summer
24 month, particularly July, we would not be sending a price
25 signal to our average customer at a time when the system
CSB REPORTING
[phone]
795 WAITES (Di)
Idaho Power Company
.
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19
20
21
1 is constrained and energy efficiency is most important.
2 Q And there was some discussion about the
3 FCA program. That program is currently in a pilot stage
4 in Idaho; is that your understanding?
5 A That is correct.
6 Q And with regard to what you discussed
7 first with Mr. Richardson, the virtual peaker program, do
8 you know in relation to PG&E' s program, do you know how
9 often, if at all, they've ever run that program?
10 A It's my understanding in the approximately
11 seven years they've had it they've only run it once.
12 MR. RICHARDSON: Madam Chair, I'm going to
13 obj ect to the form of that question.
14 COMMISSIONER SMITH: Mr. Richardson.
15 MR. RICHARDSON: The virtual peaking
16 program if it is in place runs all the time because it
17 provides availability of backup resources, so it is
18 available to run all the time.
COMMISSIONER SMITH: Mr. Walker.
MR. WALKER: Well, maybe I can clarify.
Q BY MR. WALKER: Do you know, have they
22 ever actually ran the program to produce energy?
23 COMMISSIONER SMITH: I don't think you
24 fixed the objection.
25 MR. RICHARDSON: He hasn't, Madam Chair.
CSB REPORTING.
[phone]
796 WAITES (Di)
Idaho Power Company
.
.
.
16
17
1 MR. WALKER: I'll move on, then.
2 COMMISSIONER SMITH: Okay.
3 Q BY MR. WALKER: You gave one answer to
4 Mr. Richardson that was kind of hard to hear, but it was
5 regarding the cost, the cost numbers, of the virtual
6 peaker program. I believe you said $340. Could you
7 rei terate and tell us what that was?
8 A Yes, the last financial analysis that was
9 done in April of 2008, a program like a virtual peaker
10 program, the variable cost would be approximately just
11 over $340 a megawatt compared to $80.00 for a simple
12 cycle peaker.
13 Q And didn't the Company and Staff and the
14 industrial customers, didn't they have meetings several
15 times to discuss this particular program?
A Yes, we did.
Q And these issues were discussed with the
18 parties at that time?
19
20
A Yes, it was.
Q And was anybody, anyone involved in those
21 discussions, were they able to demonstrate a quantifiable
22 customer benefit in this program?
23
24
25
A No.
MR. WALKER: I don't have anything else.
COMMISSIONER SMITH: Thank you, Mr.
CSB REPORTING
[phone]
797 WAITES (Di)
Idaho Power Company
.
.
.
10
1 Walker, and thank you, Ms. Waites.
2 COMMISSIONER REDFORD: I have some
3 questions.
4 COMMISSIONER SMITH: Oh, Commissioner
5 Redford.
6
7 EXAMINATION
8
9 BY COMMISSIONER REDFORD:
Q Thank you, Ms. Waites. You just
11 previously in answer to Mr. Donovan's query about average
12 customer, in the scheme of things as to these tiered
13
14
rates, what is the average customer's usage?
A For the year 2007, it was 1,065
15 kilowatt-hours a month.
16 Q So under any scenario, the average
17 customer would exceed the second tier?
18 A Correct. I believe that in 2007, it was
19 six of the 12 months they would only exceed.
20 Q In making your study, I understand that
21 you reviewed numerous studies which talked about tiered
22 rates. Could you let me know whether any of those
23 studies centered around low income people who -- low
24 income people or also low income people who are heating,
25 for instance, with electric heat?
CSB REPORTING
[phone]
798 WAITES (Com)
Idaho Power Company
.1 A I don't believe I reviewed any studies
2 specifically to low income people using electric heat.
3 As we've traveled around the state inQ
4 these hearings, we get a lot of testimony that suggests
5 that there are a lot of low income people who heat their
6 homes with electricity. Clearly, under the present 300
7 kilowatts, they fallout and probably under the i, 000
8 kilowatts they fallout as well. Have you taken into
9 consideration the ability to pay for customers in low
10 income areas and their ability to pay for basic
.
.
11 service?
12 That's more of a policy issue that wouldA
13 be addressed by Mr. Gale.
14 Q You have not participated in any study?
15 No.A
16 Do you think that may have been a goodQ
17 item to have studied?
18 Unfortunately, we don't have income dataA
19 on our customers, so we don't have any data to know the
20 magni tude.
21 Well, there are, of course, lots ofQ
22 government studies as to low income people in Idaho and
23 nationwide, actually. We read about it all the time. Do
24 you know if there was any policy decision made as to how
25 these tiered rates affect low income people?
CSB REPORTING
[phone]
799 WAITES (Com)
Idaho Power Company
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.
.
10
1 I don't know.A
2 I just also wondered, it appears from yourQ
3 testimony that you're not really a big fan of these
4 tiered rates.
5 I am a fan of tiered rates.A
6 But you only want two tiers?Q
7 Correct.A
8 And your reason for not wanting threeQ
9 tiers is because it's further confusing to ratepayers?
A That was our experience the last time they
11 were implemented.
12
13
14
Q If you know, what are -- and I know this
has been covered a little bit, how am I notified that
there's a two-tier system going into place and it's
15 either 600 or 1,000 is the block rate point, how am I
16 notified of that as a ratepayer?
17 A I believe there's separate line items on
18 the bill.
19 Q And are they very cryptic or do they tell
20 me that if I keep my power under 1,000 kilowatts that I
21 will be, in effect, rewarded, but if I go over the 1,000,
22 I'm going to be punished?
23 A I believe the line item says usage under
24 300 kilowatt-hours and lists the rate and usage over 300
25 kilowatt-hours and lists the rate.
CSB REPORTING
[phone]
800 WAITES (Com)
Idaho Power Company
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.
.
1 Q And that's the sole information that a
2 customer is given as to two tiers?
3 That I don't know for sure because I'm notA
4 on the customer service side.
5 Q Don't you think even though you're not,
6 don't you think it's a good idea that the Company
7 educates the users of the different blocks?
8 A Yes.
9 And you've stated previously that mostQ
10 customers don't understand that. Could that possibly be
11 because your education program doesn't exist?
12
13
A I don't know that it doesn't exist. I'm
just not involved in it, so I can't answer that
14 question.
15 Q So the only real information that you
16 studied was those particular studies that in fact
17 promoted your testimony as to the different blocks?
18 A I studied the results when the
19 three-tiered rates were put into effect in 2001.
20 Q And you don't really recall what you
21 studied?
22 I do.A
23 Q Okay, basically, what were those
24 studies?
25 A I talk about them in my rebuttal testimony
CSB REPORTING
[phone]
801 WAITES (Com)
Idaho Power Company
.
.
.
1 beginning on page 5 about the lack of understanding we
2 experienced back when these were implemented in 2001,
3 that customers were confused and our customer service
4 representatives had a hard time helping the customers
5 fully understand these tiered rates, that we experienced
6 our lowest customer satisfaction rating ever and had a
7 large number of PUC complaints regarding specifically the
8 rate structure.
9 So your study was in-house and you didn'tQ
10 make any other studies of any other sources that happened
11 to talk about. tiered rates and what the break point
12 should be?
13 i did studies with regards to the breakA
14 points of tiered rates. I specifically looked at
15 utilities in the Pacific Northwest, what other utilities
16 have in place, Rocky Mountain Power, looked at their
17 resul ts and that they were proposing to go back to a
18 two-tiered rate in both the last two rate cases.
19 Did they put out a study that youQ
20 requested and they provided to you or was this over the
21 telephone?
22 I reviewed their rate case filings.A
23 Did those rate case filings indicate whatQ
24 they had done by way of studies or surveys that may have
25 been generated outside the Company?
CSB REPORTING
[phone]
802 WAITES (Com)
Idaho Power Company
.
.
.
1 They indicated they did a customerA
2 survey.
3 Is that the survey you've talked about?Q
4 Correct.A
5 And from that you draw that, No.1,Q
6 three-tiered rates are not really appropriate and you
7 begrudgingly go from 300 kilowatts to 600 as the break
8 point?
9 From their study, their study supportedA
10 the experience we had in 2001 that the customers were not
11 understanding the rate structure.
12 It just seems to me that reviewing theQ
13 rate structure in a vacuum, that is, within the Company
14 and the small amount of other information that you
15 suggested, leaves out a lot of areas as to average
16 customer costs, low income and those issues. Now, that's
17 just a comment. To a person that's a low income who must
18 heat their home, even at the 600 kilowatt, what would you
19 say to them as to how to conserve energy?
20 Well, the rate design proposal that I haveA
21 made would actually help all customers because usage from
22 the 300 to 600 kilowatt-hours in the summer months, that
23 rate would decrease slightly because we've raised that
24 first block.
25 How do you determine how many customersQ
CSB REPORTING
[phone]
803 WAITES (Com)
Idaho Power Company
.
.
.
1 would be affected?
2 We look at bill frequency data.A
3 And what does that tell you?Q
4 It tells you the number of kilowatt-hours,A
5 total kilowatt-hours used in total bills during each of
6 the months.
7 So from that information you couldQ
8 calculate the frequency of customers going over the 600
9 kilowatts?
10 A Correct.
11 You've indicated that 600 kilowatts is theQ
12 break point and you've also stated that you don't agree
13 wi th the 1,000 kilowatts that the Staff has suggested.
14 Maybe I missed the reason, but why is 1,000 too much?
15 Primarily, my concern is in the JulyA
16 months when our average customer is using only just above
17 900 kilowatt-hours, a time when the system is
18 constrained, that they're not sent a price signal.
19 Well, they would be sent a price signal ifQ
20 they've gone over the 600 kilowatts, wouldn't they?
21 I'm sorry, I was referring to Staff'sA
22 proposal of 1,000. Correct, they would be sent a price
23 signal under my proposal.
24 The 900 kilowatts, you calculated thatQ
25 based upon usage in the last year?
CSB REPORTING'
[phone]
804 WAITES (Com)
Idaho Power Company
.
.
.
10
1 In 2007 and 2008 normalized data.A
2 Okay, and that's the only reason itQ
3 wouldn't send a signal?
4 I believe that that is -- I believe myA
5 proposal setting the block at 600 is more appropriate to
6 send a price signal to customers.
7 But if you don't have a program where youQ
8 instruct people or let them know really in layman's terms
9 as to the blocks, how would they know anyway?
A I can't be sure we don't have a program.
11 I don't know what the customer service representatives do
12 when they sign up a customer for service.
13 COMMISSIONER REDFORD: Okay, I have no
14 further questions.
15 COMMISSIONER SMITH: Any further redirect?
16 MR. WALKER: No.
17 COMMISSIONER SMITH: Okay, thank you.
18 (The witness left the stand.)
19 COMMISSIONER SMITH: Now we get our
20 ten-minute break. We'll come back at 35 after the hour.
21 (Recess. )
22 COMMISSIONER SMITH: We'll go back on the
23 record. Mr. Wal ker .
24 MR. WALKER: Thank you. Idaho Power calls
25 Darlene Nemnich as its next witness.
CSB REPORTING
[phone]
805 WAITES (Com)
Idaho Power Company
.
.
.
1 DARLENE NEMNICH,
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 EXAINATION
7
8 BY MR. WALKER:
9 Q Would you please state your name and spell
10 your last name for the record?
11 A My name is Darlene Nemnich. The last name
12 is N-e-m-n-i-c-h.
13 Q And by whom are you employed and in what
14 capacity?
15 A I'm employed by Idaho Power Company as a
16 senior pricing analyst.
17 Q And are you the same Darlene Nemnich that
18 filed direct testimony on June 27, 2008 and prepared
19 Exhibit Nos. 74 and 75?
20
21
A Yes, I am.
Q Do you have any corrections or changes to
22 your testimony?
23
24
25
A Yes, I do.
MR. WALKER: And excuse me, I believe
there's the same housekeeping deletion that was
CSB REPORTING
[phone]
806 NEMNICH (Di)
Idaho Power Company
.
.
.
1 referenced by Mr. Gale and Ms. Waites. That appears on
2 page 7 of her direct, lines 11 through 13, the same
3 sentence beginning with "since" and ending with "case."
4 Q BY MR. WALKER: Do you have any
5 corrections besides that?
6 A Yes, I do. On page 22 of my direct
7 testimony on line 21, the number "62" should be "57" and
8 on line 22, the number "74" should be "62," and then on
9 page 34 of my direct testimony on page 12 -- I mean, page
10 34, line 12, the number "46" should be "51." On line 20,
11 the number "46" should be "51," and on line 21, "Schedule
12 9 Primary" should be "Schedule 19 Primary."
13 Q And if I were to ask you the questions set
14 out in your prefiled testimony with those corrections,
15 would your answers be the same here today?
16 A Yes, they would.
17 MR. WALKER: I would move that the
18 prefiled direct of Ms. Nemnich be spread upon the record
19 as if read and that her Exhibits 74 and 75 be marked for
20 identification.
21 COMMISSIONER SMITH: If there is no
22 objection, it is so ordered.
23 (The following prefiled direct testimony
24 of Ms. Darlene Nemnich is spread upon the record.)
25
CSB REPORTING
[phone]
807 NEMNICH (Di)
Idaho Power Company
.
.
.
1 Q.Please state your name and business address.
2 A.My name is Darlene Nemnich. My business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company as a
6 Senior Pricing Analyst.
7 Q.Please describe your educational background.
8 A.In May of 1979, I received a Bachelor of Arts
9 degree in Business Administration with emphases in
10 Finance and Economics from the College of Idaho in
11 Caldwell, Idaho.
12 Q.Please describe your business experience with
13 Idaho Power Company.
14 A. In 1982, I was hired as an analyst in the
15 Resource Planning Department. My primary duties were the
16 calculation of avoided costs for cogeneration and small
17 power production contracts and the calculation of costs
18 of future generation resource options. In 1989, I moved
19 to the Energy Services Department where I performed
20 economic, financial and statistical analyses to determine
21 the cost effectiveness of demand-side management
22 programs. I stayed in that general area, designing,
23 implementing and evaluating programs until 2000, when I
24 was promoted to
25
808 NEMNICH, DI 1
Idaho Power Company
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18
1 Energy Efficiency Coordinator. In that capacity, I
2 coordinated the Company's effort to grow customer
3 programs and education in energy efficiency promotion. I
4 was responsible for complying with regulatory and
5 financial requirements in the area of energy efficiency.
6 In 2003, I was promoted to Energy Efficiency Leader where
7 I managed the Company's demand-side management effort ,
8 including strategic planning, design and development of
9 programs, regulatory compliance, and overall management
10 of the department. In 2006, I left the Company to pursue
11 personal opportunities. In April 2008, I returned to the
12 Company as a Senior Pricing Analyst in the Pricing and
13 Regulatory Services Department. My duties as Senior
14 Pricing Analyst include the development of alternative
15 pricing structures, analysis of the impact on customers
16 of rate design changes, and the administration of the
17 Company's tariffs.
Q.What is the scope of your testimony in this
19 proceeding?
20 A.My testimony will address the Company's rate
21 design proposal for commercial and industrial customers
22 taking service under Schedules 7, Small General Service;
23 Schedule 9, Large General Service; and Schedule 19, Large
24 Power Service, as well as the Special Contract customers.
25 I will also address the rate structure for Schedule 45,
809 NEMNICH, DI 2
Idaho Power Company
.
.
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1 Standby Service, and Schedule 46, Alternate Distribution
2 Service.
3 Q.How did you arrive at the proposed rate design
4 presented in this case?
5 A.The design of this rate proposal was
6 accomplished through analysis and input from the Pricing
7 and Regulatory Services Department and consultation with
8 Ms. Brilz, the Company's former Director of Pricing, Mr.
9 Gale, the Company's Vice President of Regulatory Affairs,
10 and the Company's legal staff. For changes to specific
11 schedules, I also consul ted with teams from many
12 different departments wi thin the Company, including Load
13 Research, Customer Billing Support, Data Warehouse
14 Management, Customer Relations and Energy Efficiency, and
15 Customer Service. In addition, I gathered customer input
16 on proposed rate design changes during a meeting held on
17 May 8, 2008, that included several of the Company's Large
18 General Service customers. A summary of this meeting is
19 included later in my testimony.
20 Q.What are your overall obj ecti ves in arriving at
21 the proposed rate designs for the Company's various
22 service schedules?
A.As indicated in Mr. Gale's testimony, the23
24 Company's primary objective is to establish prices which
25
810 NEMNICH, DI 3
Idaho Power Company
.
.
.
1 primarily reflect the costs of services provided. As
2 part of the Company's last several general rate cases,
3 the Company has continually moved to meet this primary
4 objective by emphasizing increases in the demand and
5 customer components and the inclusion of fewer
6 non-energy-related costs in the energy charges.
7 The second obj ecti ve is to provide customers
8 wi th cost-based price signals which encourage the wise
9 and efficient use of energy. This gives customers the
10 opportuni ty to manage their bills by conserving energy or
11 shifting usage to less expensive time periods. In
12 addition, consistency and stability in the structure of
13 the rate design is maintained in order to ameliorate
14 problems for customers who move from one rate schedule to
15 another.
16 Q.Are you emphasizing increases in the demand and
17 customer components in this case?
18 A.Yes I am. However, with the movement made in
19 the past several rate cases in setting rates closer to
20 costs, the magnitude of the proposed increases to the
21 demand components in most cases is less than in previous
22 proceedings.
23 Q.What are the maj or changes to the current rate
24 design you are proposing?
25
811 NEMNICH, DI 4
Idaho Power Company
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.
1 A.In addition to modifying the rate levels to
2 reflect the new revenue requirement, I am proposing three
3 rate design changes. First, for Schedule 7, Small
4 General Service, I am proposing to add a block rate on
5 the energy charge during the non-summer time period.
6 This block rate will mirror the existing summer block
7 rate and provide a conservation incentive for customers
8 using more than 300 kWh during non-summer months.
9 Second, in order to provide clear price signals and
10 provide opportunities for customers to manage their
11 electrici ty bills, I am proposing time-of-use rates for
12 customers taking service under Schedule 9, Large General
13 Service, at the Primary and Transmission levels. And
14 third, for Schedule 19, Large Power Service, I am
15 proposing to increase the differentials between the
16 On-Peak, Mid-Peak and Off-Peak Energy Charges during the
17 summer and non-summer seasons. This will provide an
18 increased incentive for customers to reduce or shift load
19 during the summer months, the Company's most expensive
20 time to provide power.
21 Q.Have you prepared any exhibits relating to your
22 rate design testimony?
23
24
25
812 NEMNICH, DI 5
Idaho Power Company
.
.
.
1 A.Yes. I am sponsoring the following exhibits
2 relating to rate design:
3 Exhibit Description
4 Exhibit No. 74 Calculation of Proposed Rates
5 Exhibi t No. 75 Typical Monthly Billing Comparisons
6 and Billing Impacts of Proposed Rates
7 Q.Please describe Exhibit No. 74.
8 A.Exhibi t No. 74 indicates the rate calculations
9 made, by billing component, for Service Schedules 7, 9,
10 19, and Special Contracts.
11 Q.Please describe Exhibit No. 75.
12 A.Exhibi t No. 75 shows the impact on customers'
13 bills of the proposed rate designs for Schedules 7, 9,
14 and 19.
15 Q.How have you organized the discussion of your
16 rate design proposals?
17 A.My testimony will address rate design proposals
18 for Schedules 7, 9, 19, the Special Contracts, and for
19 Standby and Alternate Distribution Services, in that
20 order.
21 SMAL GENERA SERVICE, SCHEDULE 7
22 Q.What is the present rate structure for Small
23 General Service under Schedule 7?
24
25
813 NEMNICH, DI 6
Idaho Power Company
.
.
.
1 A.As Mr. Gale stated in his testimony, the rates
2 I will describe as the present rate structure are the
3 rates filed in Case No. IPC-E-08-01 related to the
4 Danskin Combustion Turbine. The actual rates approved by
5 the Commission in Case No. IPC-E-08-01 (Order No. 30559)
6 vary slightly from those originally filed. In order No.
7 30559, the Commission excluded a relatively small part of
8 the investment from inclusion in rates ($422,000). The
9 Company has not included this small impact in the General
10 Rate Case filing because of the time impact associated
11 wi th reprocessing all the analyses and studies.
12 Schedule 7 is available to Customers whose
13 metered energy usage is 2,000 kWh or less, per billing
14 period for ten or more billing periods during the most
15 recent 12 billing periods. Customers taking service
16 under Schedule 7 pay a Service Charge of $4.00 per month.
17 During the summer months they pay an Energy Charge of
18 7. 0280ç per kWh for the first 300 kWh used and 7. 9158ç
19 per kWh for all usage over 300 kWh. During the
20 non-summer months of September through May, they pay
21 7. 0280ç per kWh for all kWh used. Demand is not billed
22 for Schedule 7 customers.
23
24
25
814 NEMNICH, DI 7
Idaho Power Company
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.
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1 Q. Please describe the rate design proposal for
2 Schedule 7.
3 A.I am proposing to add an inverted block rate
4 during the non-summer months for Schedule 7. This block
5 rate is set at 300 kWh, which is the same level as the
6 existing summer block rate on this Schedule.
7 Q Why did you determine that 300 kWh is the
8 appropriate level for the non-summer first block?
9 A.The existing first block in the summer season
10 is currently set at 300 kWh. For Schedule 7 customers,
11 approximately 40 percent of energy consumed during summer
12 months is in the first block, and, similarly, 39.0
13 percent of the energy consumed during the non-summer
14 months is in the first block. A first block higher than
15 300 kWh is not recommended because the average monthly
16 kWh for customers in this schedule is just over 500 kWh.
17 Q.Why is the Company proposing to add a block
18 rate in the non-summer months?
19 A.By setting a block rate in non-summer months,
20 the Company gives a price signal to encourage customers
21 to use electricity efficiently and wisely. Customers who
22 work towards reducing their monthly kWh usage can expect
23 a larger reduction on their bill when they conserve with
24 this block rate than if they had a flat rate.
25
815 NEMNICH, DI 8
Idaho Power Company
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1 Q.What are the proposed Energy Charges and
2 Service Charge?
3 A.The Energy Charge for both summer and
4 non-summer first block rates is 7. 4005ç per kWh. The
5 Energy Charge for the summer second block is 8. 8096ç per
6 kWh and the Energy Charge for the non-summer second block
7 is 7.8217ç per kWh. In addition, the Company is
8 proposing to increase the Service Charge from $4.00 to
9 $5.00 per month. The rate design proposal for Schedule 7
10 is included on page one of Exhibit No. 74.
11 Q.Please describe the proposed changes to the
12 Energy Charges for the first and second blocks.
13
14
A. To provide rate stability for lower use
customers, the Energy Charges for both first blocks in
15 the summer and non-summer seasons are equal. I
16 maintained the current differential between the summer
17 and non-summer Energy Charge for the second blocks. The
18 Energy Rates for the first blocks were increased by 5.3
19 percent over current rates. The Energy Rates for the
20 second blocks' for both the summer and non-summer months
21 were both increased by 11.29 percent over current rates.
22 In light of the overall revenue requirement increase of
23 10.63 percent for Schedule 7, this rate design gives a
24 stronger price signal in the summer than non-summer
25 months and a stronger price signal
816 NEMNICH, DI 9
Idaho Power Company
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1 for usage over 300 kWh per month.
2 Q.What is the revenue requirement to be recovered
3 from Small General Service customers taking service under
4 Schedule 7?
5 A.The annual revenue requirement for Schedule 7
6 customers as shown on page 4 of Mr. Tatum's Exhibit No.
7 70 is $16,772,713.
8 Q.What is the impact of this proposed rate design
9 on Small General Service customers?
10 A.Page 1 of Exhibit No. 75 shows the billing
11 comparison between the Schedule 7 existing rates and
12 proposed rates for typical billing levels. This exhibit
13 shows the impact of the added non-summer block rate.
14 LAGE GENERA SERVICE, SCHEDULE 9
15 Q.What is the present overall rate structure for
16 Schedule 9?
17 A.Service under Schedule 9 may be taken at
18 Secondary, Primary, or Transmission Service level. This
19 Schedule is applicable to customers whose metered energy
20 usage exceeds 2,000 kWh per billing period for a minimum
21 of three billing periods during the most recent 12
22 consecuti ve billing periods and whose metered demand per
23 billing period has not equaled or exceeded 1,000 kW more
24 than twice during the most recent 12 consecutive billing
25 periods. Idaho
817 NEMNICH, DI 10
Idaho Power Company
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.25
1 Power has 144 customers who take service at Primary
2 Service level, two customers who take service at
3 Transmission Service level, and 26,702 customers who take
4 service at Secondary Service level. All customers taking
5 service under Schedule 9 pay a Service Charge, a Basic
6 Charge, and both summer and non-summer Energy and Demand
7 Charges. Customers taking Primary or Transmission service
8 may also pay a Facilities Charge.
9 LAGE GENERA SERVICE, SCHEDULE 9 - SECONDARY
10 Q.What is the present rate structure for Schedule
11 9 Secondary Service?
12 A.The current rate structure for Schedule 9
13 Secondary Service includes a two-tier declining block
14 Energy Charge along with a block Demand Charge and a
15 block Basic Charge. Under this rate structure, the first
16 block Energy Charge applies to the first 2,000 kWh of
17 usage and the second block Energy Charge applies to all
18 usage greater than 2,000 kWh. In addition, there is no
19 charge for the first 20 kW of Billing Demand or the first
20 20 kW of Basic Load Capacity.
21 Q.What is the reason that Schedule 9 Secondary
22 Service has this block design in place?
23 A.The current block rate design structure for
24 Schedule 9 Secondary Service was put in place to remedy a
818 NEMNICH, DIll
Idaho Power Company
.1 pricing disparity that occurred when customers
2 transi tioned between Schedule 7 and Schedule 9 at the
3 Secondary level. Before this block structure was put in
4 place, many of the customers moving from Schedule 9 to
5 Schedule 7 would see an increase in their monthly bill of
6 more than 100 percent. This disparity provided an
7 incenti ve to artificially increase their usage to remain
8 on Schedule 9, even when they qualified for Schedule 7.
9 The block rate structure in place for Schedule 9
10 Secondary Service provides a similar rate level and a
11 smooth transition to customers moving from Schedule 7 to
12 Schedule 9 Secondary Service level..14
13 Q. Please describe the rate design proposal for
Schedule 9 Secondary Service level.
15 A.The rate design proposal for Schedule 9
16 Secondary Service level is included on page two of
17 Exhibi t No. 74. I am proposing the Service Charge be
18 increased from $12.50 to $15.00 per month. I am also
19 proposing the Basic Charge be increased from $0.67 to
20 $0.80 per kW, the summer Demand Charge be increased from
21 $3.85 to $4.80 per kW, and the non-summer Demand Charge
22 be increased from $3.19 to $3.85 per kW. The current
23 summer Energy Charge of 7.3018 ç for the first 2,000 kWh
24 and the current summer Energy Charge of 3. 1285ç per kWh.25 for all other. usage are increased to 7.997 6ç and 3.42 66ç
per kWh, respectively.
819 NEMNICH, DI 12
Idaho Power Company
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.
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1 The non-summer Energy Charge of 6. 5143ç for the first
2 2,000 kWh and of 2. 7905ç per kWh for all other usage are
3 increased to 7.1351ç and 3.0565ç per kWh, respectively.
4 Q.How did you arrive at these proposed charges?
5 A.For all rate components, I am proposing rates
6 that represent a uniform seven percent movement towards
7 the costs to serve that rate component. The costs to
8 serve each rate component are indicated on page three of
9 Mr. Tatum's Exhibit No. 67. To calculate each rate
10 component amount, I first considered the percentage of
11 overall revenue requirement identified by demand, energy,
12 basic, and customer components for Schedule 9 Secondary
13 Service level resulting from the Company's preferred
14 class cost-of~service study. These percentages
15 established the target revenue requirement for each
16 component. Second, I determined the percentage of
17 overall revenue recovered by component which is currently
18 provided by the existing base rates. The difference, or
19 gap, between the target and the actual percentage was
20 then determined for each component. I then adj usted the
21 current percentage of overall revenue by component by
22 approximately. seven percent of the gap to establish my
23 targets for this proceeding. Customer, demand, basic,
24 and energy related charges were then
25
820 NEMNICH, DI 13
Idaho Power Company
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20
1 established to achieve these new targets.
2 Q. What is the revenue requirement to be recovered
3 from Large General Service customers taking service under
4 Schedule 9 Secondary Service level?
5 A.The annual revenue requirement for all Schedule
6 9 customers, as shown on page 4 of Mr. Tatum's Exhibit
7 No. 70, is $175,488,062. Of this amount, the target
8 revenue requirement for Schedule 9 Secondary Service is
9 $158,806,499.
10 Q.What is the impact of this rate design on
11 Schedule 9 Secondary Service level customers?
12 A.Pages two and three of Exhibit No. 75 show the
13 billing comparison between the Schedule 9 Secondary
14 Service level existing rates and proposed rates for
15 typical billing levels. As can be seen from this
16 exhibi t, for each Demand level, the higher load factor
17 customers will see a lower overall increase as compared
18 to low load factor customers.
19 OVERVIEW OF SCHEDULE 9 AN 19 RELATIONSHIPS
Q.How are Schedule 9 and Schedule 19
21 interrelated?'
22 A.Currently, both Schedule 9 and Schedule 19
23 provide service at Secondary, Primary, and Transmission
24 Service levels. As customers' loads change, they can
25
821 NEMNICH, DI 14
Idaho Power Company
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1 transfer between Schedule 9 and Schedule 19 while
2 continuing to take service at the same service level.
3 Both Schedule 9 and Schedule 19 have a summer and
4 non-summer Demand Charge and a Basic Charge. In
5 addition, Schedule 19 has an On-Peak Demand Charge in the
6 summer. The Billing Demand is the average kW supplied
7 during the 15-consecuti ve-minute period of maximum use
8 during the billing period, adj usted for Power Factor.
9 The On-Peak Billing Demand for Schedule 19 customers is
10 the average kW supplied during the 15-consecuti ve-minute
11 period of maximum use during the June, July, and August
12 billing periods for the on-peak time period. The Basic
13 Load Capacity is the average of the two greatest monthly
14 Billing Demands established during the 12-month period
15 which includes and ends with the current billing period.
16 Q.What is the current relationship between prices
1 7 on Schedule 9 and Schedule 19?
18 A.The Service Charge and the Basic Charge are the
19 same wi thin service levels for both Schedule 9 and
20 Schedule 19. For example, the Basic Charge for Primary
21 Service level is $0.95 per kW per month for both Schedule
22 9 and Schedule 19; for Secondary Service level, the Basic
23 Charge is $0.67 per kW per month for both Schedule 9 and
24 Schedule 19. Likewise, the summer Demand Charge of $3.80
25
822 NEMNICH, DI 15
Idaho Power Company
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1 per kW for Schedule 9 Primary Service level is the same
2 as the sum of the summer Demand Charge of $3.36 per kW
3 and the summer On-Peak Demand Charge of $.044 per kW for
4 Schedule 19 Primary Service level. Generally, Secondary
5 and Transmission Service level Demand Charge structures
6 mirror the Primary Service level Demand Charge
7 structures.
8 Q.Why has this relationship been established?
9 A.This relationship was established to be
10 reflecti ve of cost and to facilitate customer transitions
11 from Schedule 9 to Schedule 19 and vice versa.
12 Q.Do your rate design proposals for Schedule 9
13 and Schedule 19 customers maintain this pricing
14 relationship between schedules?
15 A.For the most part, yes. The rate design
16 proposals for Schedule 9 and Schedule 19 for both Primary
17 Service level and Transmission Service level maintain the
18 relationship between the Service Charge, the Basic
19 Charge, and the Demand Charges on each of the schedules.
20 The relationship between Schedule 9 and Schedule 19 for
21 these two service levels is most important since almost
22 all customer transitions between these two schedules
23 occur within the Primary and Transmission Service levels.
24 The relationship between Schedule 9 Secondary
25 Service level and Schedule 19 Secondary Service level is
823 NEMNICH, DI 16
Idaho Power Company
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14
1 much less important. Rarely does a customer transition
2 from Schedule 9 Secondary to Schedule 19 Secondary. In
3 fact, there has been only one customer taking service
4 under Schedule 19 Secondary Service level since the
5 service levels were established in 1995. It is much more
6 common for a Schedule 9 Secondary Service level customer
7 to transition to Schedule 9 Primary Service level prior
8 to transferring to Schedule 19.
9 Q.Does a similar relationship as that between the
10 Service, Demand, and Basic Charges for Schedule 9 and
11 Schedule 19 exist for the Energy Charges on these two
12 schedules?
13 A. No. The implementation of time-of-use rates
for Schedule 19 has made any direct relationship between
15 the Energy Charges more challenging. In general,
16 however, the Energy Charges for Schedule 9 Primary and
17 Transmission Service level have been slightly higher than
18 the corresponding Energy Charges for Schedule 19.
19 The Energy Charges have been established to
20 achieve the required revenue for the respective customer
21 classes given the values established for the Service,
22 Basic, and Demand Charges.
23
24
25
824 NEMNICH, DI 17
Idaho Power Company
.
.
.
1 LAGE GENERA SERVICE, SCHEDULE 9 PRIMAY & TRASMISSION
2 Q. What is the present rate structure for Schedule
3 9, Primary and Transmission Service?
4 A.All customers taking service under Schedule 9,
5 Primary and Transmission Service Levels, pay seasonal
6 Energy Charges, seasonal Demand Charges, a Basic Charge,
7 and a Service Charge. Customers may also pay a
8 Facilities Charge.
9 Q.Please describe the rate design proposal for
10 Schedule 9 customers receiving service at the Primary and
11 Transmission Service levels.
12
13
14
A.I am proposing seasonal time-of-use rates to be
implemented on a mandatory basis for all customers taking
service under Schedule 9 at Primary and Transmission
15 Service levels. Under this proposal, the basic
16 time-of-use rate structure for Schedule 9 Primary and
17 Transmission Service levels will be the same as the
18 time-of-use structure currently in place for customers
19 taking service at similar service levels under Schedule
20 19. This includes On-Peak, Mid-Peak, and Off-Peak energy
21 prices that would be in effect during the three summer
22 months from June 1 through August 31. During all other
23 months, Mid-Peak and Off-Peak energy prices would be in
24 effect.
25
825 NEMNICH, DI 18
Idaho Power Company
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.
1 In addition to energy rates, I am also
2 proposing to add a summer On-Peak Demand Charge. This
3 On-Peak Demand charge mirrors the existing On-Peak Demand
4 charge that is currently in place for Schedule 19
5 customers. The rate design proposals for Schedule 9
6 Primary and Transmission Service level are included on
7 pages three and four of Exhibit No. 74.
8 Q.Why are you proposing time-of-use rates for
9 Schedule 9, Primary and Transmission service?
10 A.Energy is more costly during the summer months
11 and it is more costly during certain hours of the day.
12 Schedule 9 customers currently have the metering in place
13 to accommodate hourly pricing. The implementation of
14 time-of-use rates will provide the economic signal that
15 energy is more costly during both the peak hours of the
16 day and the peak months of the year. It is anticipated
17 that time-of-use rates will encourage reduced consumption
18 or energy shifting during both the summer months as well
19 as during the daily peak hours.
20 Q.Did you gather any direct customer information
21 to help design this rate structure?
22 A.Yes. Idaho Power held a meeting on May 8,
23 2008, for customers taking service on Schedule 9 Primary
24 or Transmission Service levels. Five customers attended
25 as
826 NEMNICH, DI 19
Idaho Power Company
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1 well as a consultant for Kroeger, Inc., along with staff
2 from the Idaho Public Utili ties Commission and Idaho
3 Power Company. Several of the customers attending also
4 had facilities taking service under Schedule 19. The
5 purpose of the meeting was to discuss changing the rate
6 structure for Schedule 9 Primary and Transmission Service
7 levels from flat seasonal Energy Charges to time-of-use
8 seasonal Energy Charges. The addition of a summer
9 On-Peak Demand Charge was also discussed. Customer
10 feedback on all issues was solicited.
11 Q.What is your proposal for the Service Charge
12 and Basic Charge for Schedule 9 Primary and Transmission
13 Service level customers?
14 A. I am proposing that the Service Charge be
15 increased from $210.00 per month to $250.00 per month. I
16 am proposing that the Basic Charge be increased from $.95
17 per kW per month of Basic Load Capacity to $1.00 per kW
18 per month.
19
20
Q.How did you arrive at these rates?
A.As was discussed earlier, the Service Charge
21 and Basic Charge for both Schedule 9 Primary and
22 Transmission Service levels and Schedule 19 Primary and
23 Transmission Service levels are set to be equal in order
24 to facilitate ease of transition between rate schedules
25 for
827 NEMNICH, DI 20
Idaho Power Company
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1 customers. The cost-of-service results show customer
2 unit costs to be $245.87 and $313.33 for Schedule 9
3 Primary Service and Schedule 19 Primary Service,
4 respecti vely. These are shown on pages four and five of
5 Mr. Tatum's Exhibit No. 67. The proposed value of
6 $250.00 for Service Charge represents a reasonable
7 movement towards these unit costs.
8 Q.Please describe the Company's proposal for
9 Demand Charges for Schedule 9 Primary and Transmission
10 level customers.
11 A.For Schedule 9, Primary and Transmission
12 customers the Company is proposing to mirror the rate
13 design currently in place for Schedule 19 customers.
14 During the three summer months, the Company is proposing
15 to implement a two-tiered Demand Charge for monthly peak
16 demand. The proposed Demand Charge for Billing Demand,
17 which is the average kW supplied during the 15-minute
18 period of maximum demand during the billing period, is
19 $3.95 per kW for Primary Service and $3.84 for
20 Transmission Service. An additional charge of $0. 75 is
21 proposed for each kW of On-Peak Billing Demand, which is
22 the average kW supplied during the 15-minute period of
23 maximum demand during the billing period for the On-Peak
24 hours. For customers whose peak demand during the
25 billing period
828 NEMNICH, DI 21
Idaho Power Company
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1 occurs during the On-Peak period, the Billing Demand and
2 the On-Peak Billing Demand will be the same. However,
3 for customers whose peak demand occurs during the
4 Mid-Peak or Off-Peak period, the Billing Demand will be
5 greater than the On-Peak Billing Demand. During the
6 non-summer months, only Billing Demand will apply. There
7 is no On-Peak Billing Demand during the non-summer
8 months. The proposed Demand Charges for the non-summer
9 months are $3.65 per kW for Primary Service and $3.55 per
10 kW for Transmission Service.
11 Q.How did you determine the Demand Charges?
12 A.My overall goal was to move summer and
13 non-summer Demand Charges closer to cost of service while
14 at the same time maintaining relationships among
15 schedules and service levels.
16 To calculate the Demand Charges, I first
17 examined the existing differential between summer and
18 non-summer Demand Charges which is slightly less than 20
19 percent. From pages four and five of Exhibit No. 67, the
20 cost-of-service results show differentials between summer
21 and non-summer demand to be 57 percent for Schedule 9
22 Primary and 62 percent for Schedule 19 Primary. In order
23 to move towards alignment with cost-of service, my
24 proposal is to move 25 percent closer to the
25 cost-of-service results.
829 NEMNICH, Dr 22
Idaho Power Company
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14
1 This results in an overall proposed differential of
2 approximately 29 percent between summer and non-summer
3 Demand Charges.
4 The summer demand unit costs for Schedule 9
5 Primary and Schedule 19 Primary are $6.51 and $7.75,
6 respecti vely, as indicated on pages four and five of Mr.
7 Tatum's Exhibit No. 67. I set the total summer demand
8 amount at $4.70 per kW per month, which represents 72
9 percent of Schedule 9 Primary unit cost to serve and 61
10 percent of the Schedule 19 Primary unit cost to serve.
11 This total summer demand amount is separated to two
12 amounts; the On-Peak Demand Charge and the summer Demand
13 Charge.
I set the summer On-Peak Demand Charge at $0.75
15 per kW per month, which is 16 percent of the total summer
16 demand amount at the Primary Service level. This is
17 slightly higher than the current 12 percent. I increased
18 the percent in order to send a stronger price signal
19 during the Company's peak time periods. The summer
20 On-Peak Demand Charge is set to the same amount for
21 Schedule 9 Primary and Transmission levels as well as
22 Schedule 19 customers at all Service levels.
23 The summer Demand Charge for Schedule 9 Primary
24 Service level. is $3.95 per kW per month, which is the
25 total summer demand amount of $4. 70 less the summer
830 NEMNICH, DI 23
Idaho Power Company
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lOn-Peak Demand Charge of $0.75.
2 The non-summer demand unit costs for Schedule 9
3 Primary and Schedule 19 Primary are $4.13 and $4.77,
4 respecti vely, as indicated on pages four and five of Mr.
5 Tatum's Exhibit No. 67. I set the non-summer Schedule 9
6 Primary Service level Demand Charge at $3.65 per kW per
7 month, which represents 91 percent of Schedule 9 Primary
8 unit cost to serve and 79 percent of the Schedule 19
9 Primary unit cost to serve.
10 From Primary Service level, the summer and
11 non-summer Demand Charges, as well as the summer On-Peak
12 Demand Charge, were spread to the Transmission Service
13 level maintaining traditional relationships.
14 Q. Is the Company proposing to apply the current
15 Schedule 19 time-of-use block definitions to the new rate
16 design proposal for Schedule 9?
17
18
A.Yes.
Q.What are the time-of-use block definitions that
19 the Company is proposing for the Energy Charges?
20 A.During the three summer months, the Company is
21 proposing three time-of-use blocks. The On-Peak block is
22 defined as 1 p~m. to 9 p.m. Monday through Friday except
23 holidays. The Mid-Peak block is defined as 7: 00 a. m. to
24 1:00 p.m. and 9:00 p.m. to 11 p.m. Monday through Friday
25
831 NEMNICH, DI 24
Idaho Power Company
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21
1 and 7:00 a.m. to 11:00 p.m. Saturday and Sunday except
2 holidays. The Off-Peak block is defined as 11: 00 p.m. to
3 7: 00 a .m. every day Monday through Saturday and all hours
4 on holidays. During the non-summer months, the Company
5 is proposing just two time-of use blocks. The Mid-Peak
6 block during the non-summer months is defined as 7: 00
7 a. m. to 11: 00 p. m. Monday through Saturday except
8 holidays. The Off-Peak block is defined as 11:00 p.m. to
9 7: 00 a. m. Monday through Saturday and all hours on Sunday
10 and holidays. All times are in Mountain Time.
11 Q.What are the specific proposed Energy Charges
12 for Schedule 9 by service level?
13 A. The Energy Charges for Schedule 9 Primary and
14 Transmission customers by time period for each season
15 are:
16 Time
Period Service Level
Primary Transmission
17
18 Summer
19 On-Peak 3.3509ç 3.2560ç
Mid-Peak 3.0463ç 2.9704ç
Off-Peak 2.8468ç 2.7795ç
22 Non-Summer
23
24
25
Mid-Peak 2.6591ç 2.5987ç
Off-Peak 2.5496ç 2.5024ç
832 NEMNICH, DI 25
Idaho Power Company
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1 Q.What were your goals in developing these Energy
2 Charges?
3 A.The first goal was to utilize the same seasonal
4 energy rate differentials used in existing rates and
5 apply it to the proposed Off-Peak time blocks. This
6 differential is approximately 12 percent. My second goal
7 was to apply the time block differentials used in the
8 existing Schedule 19 time-of-use rates to the proposed
9 Schedule 9 Primary and Transmission time-of-use rates.
10 My third goal was to recover the residual revenue
11 requirement given the proposed Service, Basic, and Demand
12 Charges.
13 Q. Why did you use the current Schedule 19
14 time-of-use rate differentials for Schedule 9?
15 A.Many of our Schedule 9 customers also have
16 Schedule 19 accounts so they may have some familiarity
17 operating with this rate structure. Furthermore, these
18 differentials, set at approximately 7 percent between the
19 summer Off-Peak and summer Mid-Peak Energy Charges,
20 approximately 10 percent between the summer Mid-Peak and
21 summer On-Peak Energy Charges, and approximately 4
22 percent between the non-summer Off-Peak and non-summer
23 Mid-Peak Energy Charges, are not very large but do
24 provide an introductory level of time differentiated
25 rates. Customers have the opportunity to become familiarwi th time variant
833 NEMNICH, DI 26
Idaho Power Company
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1 pricing gradually, see how their usage patterns impact
2 their bills, and plan accordingly.
3 Q.How did you calculate the specific time-of-use
4 Energy Charges?
5 A.For Schedule 9 customers taking service at the
6 Primary Service level, the summer Off-Peak Energy Charge
7 was set at 2. 8468ç, which is close to the current summer
8 Energy Charge. The non-summer Off-Peak Energy Charge was
9 set at 2.54 96ç, which is close to the current non-summer
10 Energy Charge. Therefore, electricity used during
11 Off-Peak hours will see virtually no rate increase for
12 this rate component. This gives a strong price signal to
13 those customers who can primarily use electricity during
14 Off-Peak time blocks.
15 The summer and non-summer Mid-Peak Energy
16 charges were calculated by applying the differentials of
17 approximately 7 percent and approximately 4 percent,
18 respectively, to the Off-Peak Energy Charge. The summer
19 On-Peak Energy Charge was calculated by applying the
20 approximately 10 percent differential to the summer
21 Mid-Peak Energy Charge.
22 The Energy Charges for the Schedule 9 customers
23 taking service at the Transmission level were calculated
24 in the same process. I have provided a comparison of
25 current
834 NEMNICH, DI 27
Idaho Power Company
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1 and proposed rates together with seasonal and time-of-use
2 differentials in my work papers.
3 Q.Why are you proposing that these time-of-use
4 rates for Schedule 9 Primary and Transmission levels be
5 mandatory?
6 A.These time-of-use rates more accurately reflect
7 the costs to serve our customers and therefore provide a
8 better overall pricing signal. By providing time-of-use
9 rates to all customers, not just those who might benefit
10 from being on time-of-use rates, we are providing
11 incentives to' customers to conserve and/or shift load.
12 If customers respond to this signal by conserving or
13 shifting load, the resulting energy use pattern lowers
14 overall costs for all customers.
15 Q.Are' you proposing a "phase-in" period for
16 time-of-use rates similar to what was adopted when
17 time-of-use was implemented for Schedule 19?
18 A.No. I propose implementing a customer
19 communication. and education plan that provides customers
20 with information on the possible impact of time-of-use
21 rates on their bills. Examples of energy conservation or
22 load shifting ideas may be also provided at that time.
23 By working with customers before the rates go
24 into effect they can plan and make purchasing decisions
25 and
835 NEMNICH, DI 28
Idaho Power Company
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1 determine how best to react to the new structure. In
2 turn, by providing customer support up front, Idaho Power
3 can avoid the costs of manual bill processing associated
4 with shadow bills that occurred during the Schedule 19
5 time-of-use rate implementation.
6 Q.What is the revenue requirement to be recovered
7 from Schedule 9 Large General Service customers taking
8 service at the Primary and Transmission levels?
9 A.The annual revenue requirement for Schedule 9
10 customers as shown on page four of Mr. Tatum's Exhibit
11 No. 70 is $175,488,062. Of this amount the revenue
12 requirement target for Schedule 9 Primary and
13 Transmission is $16,681,613.
14 Q. What is the billing impact of this rate design
15 proposal on the customers receiving service under
16 Schedule 9 Primary and Transmission Service levels?
17 A.Page four of Exhibit No. 75 shows the billing
18 comparison between the existing rates and proposed rates
19 for Schedule 9 Primary Service level and Schedule 9
20 Transmission Service level. These comparisons are based
21 on actual billing data for 2007. Approximately 53
22 percent of the customers receive an increase in their
23 annual bills less than or equal to 7 percent.
24 Approximately 40 percent of the customers receive an
25 increase of between 7 percent
836 NEMNICH, DI 29
Idaho Power Company
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1 and 9 percent and approximately 6 percent of the
2 customers receive an increase greater than 9 percent. No
3 customers received an increase greater than 16 percent.
4 LAGE POWER SERVICE, SCHEDUL 19
5 Q.What is the present rate structure for Schedule
6 19?
7 A.Service under Schedule 19, just like service
8 under Schedule 9, is provided under Secondary, Primary,
9 and Transmission Service levels. All customers taking
10 service under Schedule 19 pay seasonal time-of-use Energy
11 Charges, seasonal Demand Charges, a summer On-Peak Demand
12 Charge, a Basic Charge, and a Service Charge. Customers
13 taking Primary or Transmission Service may also pay a
14 Facili ties Charge. In addition, Schedule 19 includes a
15 1,000 kW minimum Billing Demand and Basic Load Capacity.
Q.What is the rate design proposal for Schedule
17 19?
18 A.The rate design proposal for Schedule 19 is
19 shown on pages five through seven of Exhibit No. 74.
20 Increases are proposed for all rate components on
21 Schedule 19. There are two primary changes to the rate
22 design proposed for Schedule 19 customers. First, the
23 differentials. between Off-Peak, Mid-Peak, and On-Peak
24 Energy Charges during the summer season and the
25
837 NEMNICH, DI 30
Idaho Power Company
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1 differential between Off-Peak and Mid-Peak Energy Charges
2 during non-summer season have been increased. And,
3 second, more emphasis has been placed on the Demand,
4 Basic, and Service Charge components.
5 Q.What are the proposed changes for the Service
6 Charge?
7 A.The proposed Service Charge for both Schedule
8 19 Primary and Transmission Service levels is $250.00 per
9 month. The cost-of-service result of the Service Charge
10 for Schedule 19 is $313.33 and is shown on page five of
11 Mr. Tatum's Exhibit No. 67. The proposed Service Charge
12 of $250 represents approximately 80 percent of the
13 cost-of-service results.
14 The proposed Service Charge for Schedule 19
15 Secondary Service level is $15.00 per month, which
16 maintains the alignment between Secondary Service levels
17 between Schedule 19 and Schedule 9.
18 Q.What are the proposed changes for the proposed
19 Basic Charge for Schedule 19?
20 A.For the Primary Service level, the Basic Charge
21 is $1.00 per kW per month. This amount is approximately
22 90 percent of the cost-of-service result of $1.12 as
23 shown on page five of Mr. Tatum's Exhibit No. 67. To
24 calculate Basic Charges for the Secondary and
25
838 NEMNICH, DI 31
Idaho Power Company
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1 Transmission levels, historic relationships between the
2 three levels were calculated and maintained. The Basic
3 Charge for Secondary Service level was also modified to
4 align with Schedule 9 Secondary Service. The proposed
5 Basic Charges for Schedule 19 Secondary Service is $0.80
6 per kW per month and for Transmission Service is $0.53
7 per kW per month.
8 Q.Please describe your proposal for Demand
9 Charges.
10 A.The proposed summer On-Peak Demand Charge is
11 $0. 75 kW for all service levels. The proposed summer
12 Demand Charges are $4.08, $3.95, and $3.84 per kW and the
13 proposed non-summer Demand Charges are $3. 75, $3.65, and
$3.55 per kW for the Secondary, Primary, and Transmission
15 Service levels , respectively. These Charges were
16 calculated to maintain the relationships between
17 Schedules and Service levels described earlier. For
18 Schedule 19 Secondary Service level, the summer and
19 non-summer Demand Charges were modified slightly from
20 tradi tional alignment with Schedule 9 Secondary Service
21 level. These charges were modified in order to maintain
22 the proposed Energy Charge differentials while at the
23 same time recover the residual revenue requirement.
24
25
839 NEMNICH, DI 32
Idaho Power Company
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15
1 Q.What are the specific proposed Energy Charges
2 by service level for Schedule 19 customers?
3 A.The Proposed Schedule 19 Energy Charges by
4 service level and time period for each season are:
5 Time
Period Service LevelSecondary Primary Transmission6
7 Summer
8 On-Peak 4.7846ç 3.9735ç 3.9148ç
9 Mid-Peak 3.6650ç 3.0266ç 2.9970ç
10 Off-Peak 3.1870ç 2.6313ç 2.6049ç
11 Non-Summer
12 Mid-Peak 3.3790ç 2.8025ç 2.7687ç
13 Off-Peak 2.9379ç 2.4368ç 2.4085ç
Q. How. were these Energy Charges derived?
A.The overall approach for calculating the Energy
16 Charges was to keep the Off-Peak Energy Charge as low as
17 possible while increasing the differentials for Mid-Peak
18 and On-Peak Energy Charges and at the same time meeting
19 the revenue requirements for this schedule as specified
20 by Mr. Tatum's cost-of-service study in Exhibit No. 70.
21 In order to calculate new Off-Peak Energy Charges for the
22 summer and non-summer seasons, the current rates were
23 increased by approximately 7.5 percent. This is
24 approximately half of the total overall increase of 15
25
840 NEMNICH, DI 33
Idaho Power Company
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18
1 percent for Schedule 19 customers. This gives a strong
2 price signal to those customers who can primarily use
3 electrici ty during Off-Peak hours.
4 Then I calculated the new Mid-Peak and Off-Peak
5 Energy Charges in an i terati ve process resulting in new
6 differentials. The resulting differential between
7 Off-Peak and Mid-Peak Energy Charges for both summer and
8 non-summer is approximately 15 percent. The resulting
9 differential between Mid-Peak and On-Peak is
10 approximately 31 percent. The overall summer total rate
11 differential between On-Peak Energy Charge and Off-Peak
12 Energy charge is approximately 51 percent.
13 I have included details on the comparison of
14 rate component and differentials for Schedule 19 and
15 Schedule 9 Secondary Primary and Transmission Service
16 levels in my work papers.
17 Q.Do you think these levels are reasonable?
A.Yes. I reviewed time-of-use rate structures of
19 the other utili ties and found that a total overall
20 differential of 51 percent is wi thin a typical range.
21 The proposed Schedule 9 Primary Service level summer
22 On-Peak Energy Charge of 3. 9735ç cents is just over half
23 of the average summer marginal cost.
24
25
841 NEMNICH, DI 34
Idaho Power Company
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1 Q.Why are you proposing to increase the rate
2 differentials?
3 A.When time-of-use rates were implemented for
4 Schedule 19 customers four years ago, the differentials
5 between On-Peak, Mid-Peak, and Off-Peak Energy Charges
6 were set at an "introductory" level. By increasing the
7 rate differentials, a stronger price signal is sent that
8 will provide a stronger incentive to conserve or to shift
9 the time of energy usage to a less costly time period.
10 This stronger price signal provides higher benefits to
11 those customers who modify operations or purchase
12 equipment that uses less energy. Overall, this rate
13 structure reflects a better cost recovery mechanism.
14 Q.What is the revenue requirement to be recovered
15 from Large Power Service customers taking service under
16 Schedule 19?
17 A.The annual revenue requirement for Schedule 19
18 customers as shown on page four of Mr. Tatum's Exhibit
19 No. 70 is $80r811,772.
20 Q.What is the impact of the rate design on Large
21 Power Service customers?
22 A.Page five of Exhibit No. 75 shows the billing
23 comparison between the existing rates and the proposed
24 rates for Schedule 19 including all service
25
842 NEMNICH, DI 35
Idaho Power Company
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1 levels. These comparisons are based on actual billing
2 data for 2007. Approximately 40 percent of the customers
3 recei ve an increase in their annual bills less than 15
4 percent, which is the overall increase for the Schedule
5 19 customers. Approximately 31 percent of the customers
6 recei ve an increase of between 15 percent and 15.5
7 percent and approximately 29 percent of the customers
8 recei ve an increase greater than 15.5 percent.
9 SPECIAL CONTRACT CUSTOMERS
10 Q.What are your rate design proposals for the
11 Special Contract customers?
12 A.I am proposing to maintain the current rate
13 structures for the Special Contract customers of Micron,
14 the J. R. Simplot Company, and the Department of Energy.
15 Accordingly, the existing rates for the Special Contract
16 customers are simply increased uniformly by 15 percent to
17 recover the revenue requirement as shown on page 4 of Mr.
18 Tatum's Exhibit No. 70. The rates for Micron, the J. R.
19 Simplot Company, and the Department of Energy are shown
20 on pages 8, 9, and 10 of Exhibit No. 74, respectively.
21 STANBY AN ALTERNATE DISTRIBUTION SERVICE
22 Q.Are any customers currently taking service
23 under Schedule 45, Standby Service?
24
25
843 NEMNICH, DI 36
Idaho Power Company
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1 A.Yes. One customer is currently taking Schedule
2 45 service.
3 Q.Are any revisions to Schedule 45 being
4 proposed?
5 A.Yes. The Schedule 45 charges are being revised
6 to reflect the updated cost information resulting from
7 the 3CP /12CP cost-of-service study. The updated charges
8 have been derived using the same methodology used to
9 derive the charges approved by the Commission in the
10 Company's last four general rate cases, Case No.
11 IPC-E-94-5, Case No. IPC-E-03-13, Case No. IPC-E-05-28,
12 and Case No. IPC-E-07-08. No other changes are being
13 made to Schedule 45.
14 Q. What are the proposed charges for Schedule 45?
15 A.The proposed Standby Reservation Charge for
16 each kW of Available Standby Capacity during the summer
17 months is increased from $1.67 per kW to $1.83 per kW for
18 Primary Service level and from $0.39 per kW to $0.51 per
19 kW for Transmission Service level. During the non-summer
20 months, the proposed Standby Reservation Charge is
21 increased from $1.54 per kW to $1.66 per kW for Primary
22 Service level and from $0.26 per kW to $0.34 per kW for
23 Transmission Service level. The proposed Standby Demand
24
25
844 NEMNICH, DI 37
Idaho Power Company
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14
1 Charge of Standby Billing Demand consumed in the summer
2 is increased from $4.60 per kW to $5.62 per kW for
3 Primary Service level and from $4.34 per kW to $5.31 per
4 kW for Transmission Service level. During the non-summer
5 months, the proposed Standby Billing Demand Charge per kW
6 is increased from $4.29 per kW to $4.66 per kW for
7 Primary Service level and from $4.06 per kW to $4.40 per
8 kW for Transmission Service level. No changes are
9 proposed for the Excess Demand Charge.
10 Q.Are any customers currently taking service
11 under Schedule 46, Alternate Distribution Service?
12 A.Yes. There are four customers currently taking
13 service under Schedule 46.
Q. Are you proposing any changes to Schedule 46,
15 Alternate Distribution Service?
16 A. The Schedule 46 Capacity Charge is proposed to
17 increase from. $1.28 per kW to $1.47 per kW to reflect the
18 current cost of providing Alternate Distribution Service.
19 The $1.47 amount is derived by summing the Distribution
20 demand revenue requirement for Substations, Primary
21 Lines, and Primary Transformers for Schedule 19 shown on
22 page five of Mr. Tatum's Exhibit No. 67 ($1,898,021;
23 $3,461,958; and $229,799, respectively) and dividing this
24 sum by the total billed kW of 4,238,815.
25
845 NEMNICH, DI 38
Idaho Power Company
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1 This methodology is the same as that used to derive the
2 charges approved by the Commission in the Company's last
3 four general rate cases.
4 MISCELLAOUS SPECIAL CONTRACT, SCHEDUL 31
5 Q.What is the miscellaneous special contract
6 under which the Company is providing service?
7 A.The Company has entered into a contract with
8 the Amalgamated Sugar Company to provide customized
9 standby service. The Company's initial contract with the
10 Amalgamated Sugar Company to provide standby service was
11 entered into on April 6, 1998. Standby Service is
12 currently being provided to the Amalgamated Sugar Company
13 under the provisions of a revised Standby Electric
14 Service Agreement dated December 7, 2005. This agreement
15 has been, as was the initial agreement, approved by the
16 Commission.
17 Q.Are you proposing any changes to the standby
18 charges under the Standby Electric Service Agreement with
19 the Amalgamated Sugar Company?
20 A.Yes. I am revising the charges to reflect the
21 updated cost information resulting from the 3CP /12CP
22 cost-of-service study. The methodology used to update
23 the charges is the same methodology used to establish the
24 currently approved charges.
25
846 NEMNICH, DI 39
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11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 I have included details on the derivation of
2 the updated charges in my work papers.
3 Q.Does this conclude your testimony?
4 A.Yes, it does.
5
6
7
8
9
847 NEMNICH, DI 40
Idaho Power Company
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1
2 open hearing.)
(The following proceedings were had in
4 for cross-examination.
MR. WALKER: And the witness is available3
5
6 do you have questions?
COMMISSIONER SMITH: Thank you. Mr. Ward,
17
18
7
8 you.
9
10
11
12
13
14
15 just a couple.
16
MR. WARD: I have no questions. Thank
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: I have none. Thank you.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Thank you, Madam Chair,
CROSS-EXAMINATION
19 BY MR. RI CHARDSON :
20
21
22
Q
A
Q
Good morning.
Good morning.
Now, in this docket, Idaho Power, you're
23 sponsoring testimony to raise the charge per kW of
24 on-peak billing demand for the industrial class by over
25 70 percent; correct?
CSB REPORTING
[phone]
848 NEMNICH (X)
Idaho Power Company
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1 A That is correct.
2 Q And one of the reasons you're doing this
3 is because time of use rates have proven to be a failure
4 so far in terms of motivating Schedule 19 customers to
5 modify their usage patterns; isn't that true?
6 A The overall purpose of the time of use
7 rate design is to align rates with cost of service and to
8 provide an energy efficiency signal, so these time of use
9 rates do align with our cost of service and in that way,
10 they are a success.
11 Q But what good is success in a vacuum?
12 Isn't one of the purposes of setting rates to send the
13 proper price signals? We heard earlier from the
14 president of this Company it was to do anything we can do
15 to reduce demand and on peak and here you're increasing
16 the on-peak demand charge by over 70 percent and the goal
17 is to do nothing more than just send the right signal?
18 A The purpose to align our rates with the
19 cost of service, the unit costs that are given to me by
20 the cost of service, is to send those cost signals to our
21 customers so that they may respond to these rates. Now,
22 the time of use rates that have been in effect previously
23 were a very small differential and, therefore, it could
24 possibly be that our customers did not respond to that
25 small differential.
CSB REPORTING-
[phone]
849 NEMNICH (X)
Idaho Power Company
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1 Q If I'm a factory that runs 100 percent of
2 the time, I think Mr. Ward used that analogy earlier,
3 yesterday, I use energy 24/7, 365 days, if that's true,
4 then the time of use rates, I would be indifferent to the
5 time of use rates, wouldn't I?
6 A If you had a 100 percent load factor, ran
7 completely all the time, you should be indifferent to
8 time of use rates.
9 Q And isn't there a continuum between one
10 percent load factor and 100 percent load factor where
11 time of use rates become less and less relevant or more
12 and more relevant? For example, if I ran my factory at
13 99.5 percent of the time, I would be pretty indifferent
14 to time of use rates, wouldn't I?
15 A I suppose so. I think that there are
16 things customers could do to respond if they wanted to
17 and if the economic signal that they were sent was such
18 that it would cause them to do.
19 Q Yeah, but that wasn't my hypothetical. If
20 I ran 99.5 percent of the time, I pretty much don't care
21 what the time of use rates are, do I?
22 A Well, you have that point five percent
23 that you might want to respond to the time of use rates
24 if the economic signal is strong enough to you.
25 Q And let's assume I have -- were you here
CSB REPORTING
[phone]
850 NEMNICH (X)
Idaho Power Company
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18
1 when time of use rates were first addressed by this
2 Commission for the industrial class?
3 A In 2004 I was employed by the Company, but
4 I was not in the rate department.
5 Q Were you in the Hearing Room at that
6 time?
7 A No, I was not.
8 Q Okay; so you don't recall that the
9 industrial customers sponsored a witness who is the
10 manager of Lamb Weston's American Falls factory?
11 A I was not here at that time.
12 Q So you don't recall that he testified to
13 the effect that time of use rates are not of any use to
14 the potato processing industry because they run their
15 factories based upon when the product has to be
16 processed?
17 A I did not hear his testimony.
Q And would you think that's a logical
19 statement that if I'm running a potato factory, I need to
20 run the freezers when I've got the French fries in the
21 freezers, I need to run the processing lines when the
22 product is available and it's very difficult for a
23 facility like a potato processing factory to take
24 advantage of time of use rates?
25 A I could not substantiate that that is
CSB REPORTING
[phone]
851 NEMNICH (X)
Idaho Power Company
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1 necessarily correct for all food processing companies. I
2 believe that it would be how those individual companies
3 want to respond in their cost structure to those rates.
4 Q Did you prepare Response No. 45 to Staff's
5 Fourth Production Request? Does that ring a bell with
6 you? That was regarding the analysis of how the
7 industrial class has responded to time of use rates.
8 A Forty-five, just a minute.
9 MR. KLINE: Do you have it, Darlene? I
10 can get it if you don't.
11 THE WITNESS: Let me check. Yes, I do
12 have that.
13 Q BY MR. RICHARDSON: And you prepared
14 that?
15 A I prepared the response, correct.
16 Q And it's on yellow paper, so I can't hand
17 it out to the Hearing Room because it's a confidential
18 response, but would you agree that in that response it
19 indicates that you do an analysis of the different
20 subsets of Schedule 19 based upon the type of facility it
21 is; correct?
22 A The study that was submitted in response
23 to 45 was one that Idaho Power did when they compared
24 2004 usage to 2005 and 2006 and they separated the
25 customers into general sic code categories, correct.
CSB REPORTING
[phone]
852 NEMNICH (X)
Idaho Power Company
.
.
.
1 Q sic code being?
Standard industrial classification code.
So you would have a subgroup of Schedule
4 19 that were manufacturing and a subgroup that were
2 A
5 municipal and government and a subgroup that were
3 Q
Just general, yeah.
Like that?
It was not a high level, correct.
Right, and in that study for those three
11 years, you compared the percentage of consumption in each
6 medical?
7 A
12 subgroup that was on peak, mid peak and off peak;
8 Q
Correct.
And you compared each of those subgroups
16 for each of those time periods over the three years;
9 A
10 Q
13 correct?
14 A
15 Q
17 correct?
18
19
A
Q
Correct.
So, for example, subgroup X would have 33
20 percent of their consumption on peak in 2004 and then you
21 would look at what their percentage on peak in 2005 was
22 and you would look at their consumption in 2006 for the
23 same time period; correct?
24
25
A
Q
Correct.
And for -- and I counted there were eight
CSB REPORTING
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853 NEMNICH (X)
Idaho Power Company
.
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1 different sic subgroups. Does that ring a bell with
2 you?
3 A Generally, yes.
4 Q Okay, and of those eight subgroups, I
5 looked at the comparison for each of those three time
6 periods for each of the three years and I saw no instance
7 in which the usage changed by over one percent. Does
8 that ring a bell with you?
9 A I believe that we concluded that the
10 change from different time blocks was not significant.
11 Q Yeah, I would say less than one percent
12 would not be significant. Is that a number that is
13 familiar to you?
14 A i did not calculate the one percent,
15 sir.
16 Q So if a solution isn't working, shouldn't
17 we look for a different solution?
18 A Well, I'd have to differ with you in
19 saying that it's not working. As I mentioned, my overall
20 goals in this, in my overall rate design, my goals as
21 stated in page 3 is to establish prices which primarily
22 reflect the costs of services provided, and these time of
23 use rates both those in 2004 and those that I am
24 proposing today do that as our overall goal. Secondary,.25 our second goal is to promote energy efficiency and to
CSB REPORTING-
[phone]
854 NEMNICH (X)
Idaho Power Company
.
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1 encourage customers to shift or shave energy. These
2 rates could be encouraging customers to look at reducing
3 their overall usage in the middle of the summer, and in
4 terms of shaving, that has not been a significant
5 result.
6 Q So who is your audience when you're
7 sending this price signal?
8 A The price signal -- could you ask your
9 question again?
10 Q Generically, when you're setting a price
11 signal, who are you signaling to?
12 A Whichever customers are getting the price
13 signal, the rates.
14 Q So this 70 percent rate increase in demand
15 charge for the industrial class, you're trying to send a
16 signal to the industrial class; correct?
17
18
A Correct.
Q And if that industrial class isn't
19 recei ving the signal, do you think you're achieving your
20 goal?
21 A I don't think that they're not receiving
22 the signal. They might not be responding to the signal
23 at the level it was set initially, that that differential
24 and the time of use was just a small differential and
25 they did not respond to that significantly.
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855 NEMNICH (X)
Idaho Power Company
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20
1 Q So a year-and-a-half from now when you're
2 asked the same production request that you were asked in
3 No. 45 and if you find similarly flat changes or no
4 changes in consumption pattern, do we go for 140 percent
5 increase or do we realize that perhaps there's a
6 different solution?
7 A I believe that the time of use rates,
8 sending the signals to the customers as accurately as
9 they are costing the Company is one of the best ways we
10 can provide signals to our customers so that they can
11 respond however they feel appropriate. Now, in the
12 overall, the desire is that the customers will respond
13 and lower their usage at those high price times. That in
14 turn would lower our costs and in the long run costs
15 would be lower for everyone.
16 Q And assume for me that you have a customer
17 class that is incapable of changing their consumption
18 patterns, is it still your goal to send them a price
19 signal?
A I do not know any customer class that is
21 incapable of changing their usage patterns.
22 Q Of course, we could shut down. That would
23 be one usage pattern change, wouldn't it?
24
25
A Sure.
MR. RICHARDSON: That's all I have,
CSB REPORTING
[phone]
856 NEMNICH (X)
Idaho Power Company
1 Madam Chair..2 COMMISSIONER SMITH:Thank you,Mr.
3 Richardson.Mr.Bruder,do you have questions?
4 MR.BRUDER:No questions.Thank you.
5 COMMISSIONER SMITH:Mr.Price.
6 MR.PRICE:No questions.
7 COMMISSIONER SMITH:From the Commission.
8 COMMISSIONER REDFORD:No.
9 COMMISSIONER SMITH:Nor i.Do you have
10 any redirect,Mr.Walker?
11 MR.WALKER:No.
12 COMMISSIONER SMITH:Thank you very much.13 for your time.
14 THE WITNESS:Thank you.
15 (The witness left the stand. )
16 MR.WALKER:Idaho Power calls as its next
17 witness Jeannette Bowman.
18
19
20
21
22
23
24.25
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857 NEMNICH (X)
Idaho Power Company
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1 JEANNETTE BOWMAN,
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. WALKER:
9 Q Could you please state your name and spell
10 your last name for the record?
11 A Jeannette Bowman, B-o-w-m-a-n.
12 Q And by whom are you employed and in what
13 capacity?
14 A I'm employed by Idaho Power Company as a
15 senior pricing analyst.
16 Q And are you the same Jeannette Bowman that
17 filed direct testimony in this matter on June 27th?
18
19
A I am.
Q And did you prepare Exhibit Nos. 76
20 through 80?
21
22
A I did.
MR. WALKER: And, Madam Chairman, I
23 believe Ms. Bowman's testimony contains the same sentence
24 deletion that's previously been referred to. It appears
25 on page 4, line 10 through 12, the sentence beginning
CSB REPORTING
[phone]
858 BOWMAN (Di)
Idaho Power Company
.1 with "since" and ending with "case."
2 Q BY MR. WALKER: Do you have any other
3 changes or corrections to your testimony?
4 A No, I do not.
If I were to ask you these same questions
6 that are set out in your prefiled testimony, would your
5 Q
7 answers be the same here today?
8 A Yes, they would.
MR. WALKER: I would move that the
10 prefiled testimony of Jeannette Bowman be spread upon the
9
11 record as if read and that her exhibits, No. 76 through
12 80, be marked for identification..13
14 is so ordered.
COMMISSIONER SMITH : Without obj ection, it
15 (The following prefiled direct testimony
16 of Ms. Jeannette Bowman is spread upon the record.)
18
19
20
21
22
23
24.25
17
CSB REPORTING
[phone]
859 BOWMAN (Di)
Idaho Power Company
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1 Q.Please state your name and business address.
2 A.My name is Jeannette Bowman. My business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company as a
6 Senior Pricing Analyst.
7 Q.Please describe your educational background and
8 work experience.
9 A.In 1973, I graduated from the College of Idaho
10 earning a Bachelor of Arts degree in Social Studies and
11 Mathematics. I have also done graduate work at Boise
12 State Uni versi ty. In addition, I have attended electric
13
14
utili ty ratemaking courses offered through New Mexico
State Uni versi ty' s Center for Public Utili ties as well as
15 various advanced rate courses presented by the Edison
16 Electric Institute. From 1973 to 1981, I taught
17 secondary school mathematics and social studies courses.
18 In 1981, I joined Accounting Systems in Boise where my
19 duties primarily involved implementing accounting
20 software systems. In August 1982, I accepted a position
21 at Idaho Power as a Rate Analyst. In July 1986, I was
22 promoted to Senior Rate Analyst, now designated as Senior
23 Pricing Analyst. My duties as a Senior Pricing Analyst
24 include gathering,
25
860 BOWMAN, DI 1
Idaho Power Company
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1 analyzing, and coordinating data from various departments
2 throughout the Company required for development of
3 jurisdictional separation studies, class cost-of-service
4 studies, and rate design as well as other analyses as may
5 be required. In addition, I assist in the development of
6 the Company's tariffs.
7 Q.What is the scope of your testimony in this
8 proceeding?
9 A.Under the direction of Mr. Gale, Vice President
10 of Regulatory Affairs, my testimony addresses proposed
11 changes to the Company's Idaho Schedule 24 - Agricultural
12 Irrigation Service, as well as all Idaho lighting and
13 non-metered retail tariff schedules. I will also address
14 the proposed changes to Schedule 89 - Unit Avoided Energy
15 Cost for Cogeneration and Small Power Production.
16 Q.Have you prepared or supervised the preparation
17 of certain exhibits relating to your rate design
18 testimony?
19 A.Yes, I have prepared or supervised the
20 preparation of the following exhibits relating to rate
21 design:
22
23
24
25
861 BOWMAN, DI 2
Idaho Power Company
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1 Exhibit Description
2 Exhibi t No. 76 Calculation of Proposed Rates for
Schedules 15, 24, 39, 40, 41, and 42.
3
Exhibit No. 77 Billing Comparisons of Proposed Rates
for Schedule 24, Agricultural
Irrigation Service.
4
5
Exhibit No. 78 Summary of Revenue Impact
6
Exhibit No. 79 Proposed Revised Tariff Sheets in
Legislati ve Format7
8 Exhibit No. 80 Proposed Revised Tariff Sheets
9 RATE DESIGN
10 Q.What are your overall obj ecti ves in arriving at
11 the proposed rate designs for the various service
12 schedules identified in your testimony?
13 A. As discussed in Mr. Gale's testimony, the first
14 obj ecti ve is to establish prices which primarily reflect
15 the costs of the services provided. As part of the
16 Company's last several general rate cases, this obj ecti ve
17 has been met in demand-metered schedules by emphasizing
18 increases in the demand and customer components and the
19 inclusion of fewer non-energy-related costs in the energy
20 charges. Mr. Gale's testimony also discusses a second
21 obj ecti ve of having the cost-based rate proposals be
22 designed to also encourage increased energy efficiency.
23 Additionally, as noted by Mr. Gale, as well as
24 Ms. Waites and Ms. Nemnich, the rates I will describe as
25
862 BOWMAN, DI 3
Idaho Power Company
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1 the present rate structure are the rates filed in Case
2 No. IPC-E-08-01 related to the Danskin Combustion
3 Turbine. The actual rates approved by the Commission in
4 Case No. IPC-E-08-01 (Order No. 30559) vary slightly from
5 those originally filed. In Order No. 30559, the
6 Commission excluded a relatively small part of the
7 investment from inclusion in rates ($422,000). The
8 Company has not included this small impact in the General
9 Rate Case filing because of the time impact associated
10 with reprocessing all the analyses and studies.
11 SCHEDULE 24 - AGRICULTUR IRRIGATION SERVICE
12 Q.What is the current rate structure for Schedule
13 24?
14 A.Service under Schedule 24 is classified as
15 being either "in-season" or "out-of-season." The
16 in-season for each customer begins with the customer's
17 meter reading for the May billing period and ends with
18 the customer' ~ meter reading for the September billing
19 period. The out-of-season encompasses all other billing
20 periods.
21 Wi thin the in-season, customers pay both an
22 Energy Charge and a Demand Charge for the metered usage.
23 During the out-of-season, customers pay an Energy Charge
24 only.
25
863 BOWMAN, DI 4
Idaho Power Company
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1 For the in-season, customers pay a monthly Service Charge
2 of $15.00. The monthly Service Charge during the
3 out-of-season is only $3.00 to encourage customers to
4 continue service throughout the out-of-season period.
5 Both Secondary Service and Transmission Service
6 levels are available under Schedule 24, although no
7 customers are currently taking Transmission Service.
8 Q.Please describe the rate design proposal for
9 Schedule 24.
10 A.Consistent with my overall obj ecti ves, I
11 propose to move the individual rate components closer to
12 the costs indicated by Mr. Tatum's 3CP /12CP Class
13 Cost-of-Service study as shown on page six of Exhibit No.
14 67. My rate design proposal on page two of Exhibit No.
15 76 also targets the capped 15 percent average revenue
16 increase indicated on page four of Mr. Tatum's Exhibit
17 No. 70.
18 In addition, I am proposing a load-factor
19 pricing mechanism for in-season energy sales to
20 irrigation customers. Out-of-season energy sales will
21 not be impacted by the proposed load-factor energy rate
22 design.
23 Q.Please explain what is meant by "load factor."
24 A.A load factor is the ratio of the
25 kilowatt-hours supplied during a designated period to the
peak or
864 BOWMAN, DI 5
Idaho Power Company
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1 maximum load in kilowatts ("kW") occurring in that same
2 period. It is computed by dividing the number of the
3 monthly billed kilowatt-hours by the product of the
4 billed kW and the number of hours in the billing month.
5 To attain efficiency goals, it is beneficial to maximize
6 the kilowatt-hour usage for each kW of billed demand.
7 The higher the load factor, the higher the energy
8 efficiency.
9 Q.Can you provide various examples of how load
10 factors are established?
11 A.Yes. If a customer has 1 kW of billed demand
12 and utilizes 720 kilowatt-hours of energy in a typical
13 30-day month, the resulting load factor is 100 percent:
14 720 kilowatt-hours / 720 (1 kW x 24 hours x 30 days). If
15 another customer has the same 1 kW billed demand but only
16 uses 360 kilowatt-hours during the 30-day month, the
17 customer would have a 50 percent (360/720) load factor.
18 Q.Why is a customer's load factor meaningful or
19 important?
20 A.A customer's load factor is a measure of how
21 fully electric facilities are being utilized. For
22 example, assume one customer has the infrastructure
23 required to provide service to a 100-horsepower pump that
24 is utilized only 30 percent of the time. A second
25 customer has a 50-horsepower pump that is utilized 60
percent of the time.
865 BOWMAN, DI 6
Idaho Power Company
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1 Even though each customer may have the same
2 kilowatt-hours energy charges over a month's time, the
3 demand charges for the smaller pump will be
4 proportionally less. In addition, the smaller pump will
5 have a load factor sufficient to benefit from reduced
6 energy rates.
7 Furthermore, right-sized equipment also assists
8 in minimizing the Company's peak demand if the device is
9 being utilized during the Company's highest demand
10 periods.
11 Q.Why would an energy rate design which is
12 condi tional on a customer's load factor be preferable to
13 a uniform energy rate?
14 A. Currently, a uniform energy rate is applied to
15 all in-season energy sales. Efficiency is neither
16 rewarded nor discouraged by such an energy pricing
17 mechanism. Unrecognized efficiencies of the higher
18 load-factor customers result in the subsidization of the
19 lesser efficient lower load-factor customers.
20 Implementation of the proposed load-factor pricing
21 mechanism will ameliorate the cross-subsidization between
22 these two types of customers.
23 Q.How is the load-factor pricing rate mechanism
24 structured?
25 A.Instead of applying a single uniform energy
866 BOWMAN, DI 7
Idaho Power Company
1 rate to all in-season energy sales,the load-factor.2 pricing
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
867 BOWMAN, DI 7a
Idaho Power Company
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16
1 mechanism divides the energy sales into two groups: one
2 energy rate for all kilowatt-hours up to a certain
3 load-factor threshold and a second energy rate for all
4 kilowatt-hours above that level.
5 Q.What is the typical load factor of the
6 Company's Idaho irrigation customers?
7 A.Using 2007 data for Idaho irrigation customers
8 taking service during the in-season months (June
9 September), the "average" and "median" in-season load
10 factors were 45.4 percent and 45.6 percent, respectively.
11 The "average" and "median" out-of-season load factors
12 were 19.3 percent and 18.6 percent, respectively.
13 Q. For, the proposed load-factor pricing rate
14 structure, what load factor served as your benchmark for
15 determining the kilowatt-hour tiers in your rate design?
A.My proposed rate design targets bill neutrality
17 for customers attaining the "median" load factor of 45.6
18 percent (328 kilowatt-hours per kW) in an in-season
19 month. Those with a monthly load factor greater than
20 that level will benefit from lower bill charges than if
21 all kilowatt-hours are charged a single, uniform energy
22 rate. Conversely, customers with a load factor below
23 45.6 percent in an in-season month will experience
24 increased bill charges compared to a single uniform
25 energy rate. Again,
868 BOWMAN, DI 8
Idaho Power Company
.
.
1 load-factor pricing is not being recommended for
2 out-of-season kilowatt-hour usage.
3 Q.In order to accomplish your expressed goal of
4 revenue neutrality at 328 kilowatt-hours, how large is
5 the first tier of your proposed energy rate design?
6 A.The. first energy tier in the energy rate design
7 will be for the first 164 kilowatt-hours per kW. The
8 second tier will be for all additional kilowatt-hours per
9 kW. My .workpapers include a sheet illustrating the
10 billing comparisons between single-rate energy pricing
11 and a load factor pricing rate design for customers with
12 monthly load factors between 0-100 percent.
13 Q. How large is the proposed price differential
14 between the first energy rate tier (first 164
15 kilowatt-hours per kW) and the second tier (all other
16 kilowatt-hours per kW)?
17 A.I am proposing to make only a three percent
18 price differential between the two energy tiers. This
19 small differential will minimize any sizable economic
20 impacts of the proposed rate design while customers are
21 becoming more knowledgeable about the pricing structure.
22 Q.Does a load-factor energy pricing rate design
23 interfere with, or become counter-productive to, the
24 goals of either the Company's Irrigation Efficiency.25 Rewards
869 BOWMAN, DI 9
Idaho Power Company
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.
.
1 Program or the Irrigation Peak Rewards Program?
2 A. No. Participants in the Irrigation Efficiency
3 Rewards Program receive rewards to improve the energy
4 efficiency of their existing irrigation systems or their
5 installation choices for new systems. The right-sizing
6 of equipment encouraged by this Program should enhance
7 the customer's load factor. Therefore, load-factor
8 energy pricing has the potential to provide a second set
9 of benefits to the participants in the Irrigation
10 Efficiency Rewards Program.
11 The Irrigation Peak Rewards Program provides
12 economic credits to customers who allow the Company to
13 turn off specific irrigation equipment on a regular,
14 pre-scheduled basis. Compared to the Irrigation
15 Efficiency Rewards Program, energy efficiency goals are
16 not as directly related to this Company Program.
17 However, whenever participating customers maintain a
18 monthly in-season load factor above the 45.6 percent
19 threshold, they will also receive a second additional
20 benefi t of lower energy billings resulting from
21 load-factor energy pricing. Participants in the Program
22 generally shift their usage to another time period.
23 Therefore load-factor energy pricing should not make any
24 significant changes to their monthly load factor. As a
25 resul t, participation levels in the
870 BOWMAN, DI 10
Idaho Power Company
.
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20
1 Program should not be negatively affected by the proposed
2 load-factor pricing rate design.
3 Q.What goals are addressed with the introduction
4 of load-factor energy pricing for in-season usage?
5 A.As mentioned, the Company has the goals of
6 establishing prices which reflect the costs of the
7 services provided and establishing rate designs which
8 encourage the wise and efficient use of energy.
9 Load-factor energy pricing supports both of these goals
10 because it incents customers to right-size their
11 equipment and utilize service in an efficient manner.
12 Q.Will all irrigation customers be able to
13 immediately make adjustments that will allow them to
14 benefit from load-factor energy pricing?
15 A.Perhaps not. The right-sizing of irrigation
16 equipment and/or changes in operations would probably
17 occur gradually over time. However, load-factor energy
18 pricing will encourage efficient choices when equipment
19 and operational decisions are being made.
Q.Have you had an opportunity to discuss your
21 proposed load-factor energy rate design with any
22 irrigation customers or their representatives?
23
24.25
871 BOWMAN, DI 11
Idaho Power Company
.
.
.
1 A.Yes. Idaho Power has discussed the load-factor
2 energy pricing mechanism wi th representatives of the
3 Idaho Irrigation Pumpers Association and sought their
4 input. In addition, at an irrigation forum on June 11,
5 2008, the load-factor energy pricing proposal was
6 presented to various irrigation customers, an Idaho
7 Commission Staff member, and, once again, representatives
8 of the Idaho Irrigation Pumpers Association.
9 Q.Please describe the rate design proposal for
10 Schedule 24.
11 A.The Unit Cost results detailed on page six of
12 Mr. Tatum's Exhibit No. 67 indicate the current Service
13 Charge, Demand Charge, and Energy Charge rate components
14 are not in alignment with costs. I propose to move the
15 indi vidual rate components closer to the costs indicated
16 by the cost-of-service study.
17 Q.What approach did you take in determining the
18 amount of increase for each rate component?
19 A.I first considered the percentage of overall
20 revenue requirement identified by demand, energy, and
21 customer component for irrigation service resulting from
22 the 3CP /12CP Class Cost-of-Service study discussed in Mr.
23 Tatum's testimony. These percentages established the
24 target for each component. Second, I determined the
25
872 BOWMAN, DI 12
Idaho Power Company
.
.
.24
25
1 percentage of overall revenue by component currently
2 provided by the existing base rates. The difference, or
3 gap, between the target and the actual percentage was
4 then determined for each component. I then adj usted the
5 current percentage of overall revenue by component by
6 approximately seven percent of the gap to establish my
7 targets for this proceeding. Customer-, demand-, and
8 energy-related charges were then established to achieve
9 these new targets. I have included details of these
10 calculations in my workpapers.
11 Q..How were the rates for Transmission Service
12 determined?
13 A. Once the component rates for Secondary Service
14 were determined, the charges for Transmission Service
15 were established to maintain the same relationship
16 between service levels as currently exists.
17 Q.What is the revenue requirement to be recovered
18 from Schedule 24?
19 A.The. total annual revenue to be recovered from
20 customers taking service under Schedule 24, as shown on
21 page four of Mr. Tatum's Exhibit No. 70, is $88,602,410.
22 Q.What is the proposed Service Charge for
23 Schedule 24?
A.The proposed Service Charge for Secondary
Service during the in-season increases from $15.00 to
873 BOWMAN, DI 13
Idaho Power Company
.
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1 $20.00 per month. The proposed Service Charge for
2 Transmission Service during the in-season is $250 per
3 month. This amount is the same charge proposed for
4 Schedule 9 and Schedule 19 Transmission Service. For
5 both Secondary and Transmission Service, the Service
6 Charge during the out-of-season remains at $3.00 per
7 month.
8 Q.What is the proposed Demand Charge for Schedule
9 24?
10 A.The proposed Demand Charge for Secondary
11 Service increases from $4.67 to $5.67 per kW per month.
12 The proposed Demand Charge for Transmission Service
13 increases from $4.39 to $5.33 per kW per month. The
14 Demand Charge is billed to Schedule 24 customers during
15 the in-season only.
16 Q.What are the proposed Energy Charges for
1 7 Schedule 24?
18 A.The proposed in-season Energy Charges for
19 Secondary Service increase from 3. 6409ç per kilowatt-hour
20 to 4.1430ç per kilowatt-hour for the first 164
21 kilowatt-hours per kilowatt, and to 4. 0206ç per
22 kilowatt-hour' for all other energy usage. The proposed
23 out-of-season Energy Charges increase from 4. 6347ç per
24 kilowatt-hour to 5. 4654ç per kilowatt-hour.
25
874 BOWMAN, DI 14
Idaho Power Company
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19
1 The proposed in-season Energy Charges for
2 Transmission Service increase from 3.4 635ç per
3 kilowatt-hour to 3. 9411ç per kilowatt-hour for the first
4 164 kilowatt-hours per kilowatt, and to 3.8247ç per
5 kilowatt-hour for all other energy usage. The proposed
6 out-of-season Energy Charges increase from 4. 4088ç per
7 kilowatt-hour to 5.1990ç per kilowatt-hour.
8 Q.What is the impact of the rate design on
9 Schedule 24 irrigation service customers?
10 A.Exhibi t No. 77 shows the impact on customers'
11 bills of the proposed rate designs for Schedule 24.
12 Approximately 33 percent of the customers taking service
13 under Schedule 24 receive an increase in their annual
14 bills of less than 15 percent, the total overall capped
15 percentage increase proposed for the class as a whole.
16 Another 44 percent of the customers receive an increase
17 of just 2 percent above the overall class proposed
18 increase of 15 percent.
Q.What are the usage characteristics of the
20 Schedule 24 customers receiving increases less than and
21 greater than 15 percent?
22 A.Because the rate design increases the Demand
23 Charge by a greater percentage than it increases the
24 Energy Charges, the higher a customer's load factor, the
25 more
875 BOWMAN, DI 15
Idaho Power Company
.
.
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1 beneficial the rate structure tends to be in terms of the
2 overall impact to the annual billing. The proposed
3 load-factor energy pricing mechanism has a similar
4 affect. As can be seen from Exhibit No. 77, customers
5 wi th the highest percentage increase in annual bills have
6 the lowest average load factors.
7 LIGHTING & NON-METERED SCHEDULES
8 Q.What are the Company's lighting and non-metered
9 service schedules?
10 A.The Company's lighting and non-metered
11 schedules are Dusk-to-Dawn Customer Lighting, Street
12 Lighting Service Supplemental Seasonal or Variable
13 Energy, Unmetered General Service, Street Lighting
14 Service, and Traffic Control Signal Lighting Service,
15 Schedules 15, 39, 40, 41, and 42, respectively.
16 Q.What is the present rate structure for
17 Dusk-to-Dawn Customer Lighting on Schedule 15?
18 A.Customers taking service under Schedule 15 are
19 charged on a per lamp basis. Lamps currently served
20 under Schedule 15 include 100-, 200-, and 400-watt high
21 pressure sodium vapor area lighting, 200- and 400-watt
22 high pressure sodium vapor flood lighting, and 400- and
23 1,000-watt metal halide flood lighting.
24
25
876 BOWMAN, DI 16
Idaho Power Company
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.
.
1 Q.What is the revenue requirement to be recovered
2 from customers taking service under Schedule 15?
3 A.The annual revenue requirement for Schedule 15
4 customers as shown on page four of Mr. Tatum's Exhibit
5 No. 70 is $1,029,764.
6 Q.Please describe the rate design proposal for
7 Schedule 15.
8 A.The rate design proposal for Schedule 15 is
9 included on page one of Exhibit No. 76. It includes the
10 total energy usage and proposed effective rate for each
11 lamp size option. The proposed class revenue increase of
12 2.51 percent shown on page four of Mr. Tatum's Exhibit
13
14
No. 70 is applied uniformly.
Q. Are you proposing any other changes to Schedule
15 15?
16 A.No rate design changes are being proposed.
17 However, the Company is seeking to properly track energy
18 usage by correcting the designated energy usage per
19 lighting unit. Currently, the energy portion of service
20 under Schedule 15 is being tracked solely on the lamp
21 usage. To properly determine energy usage, it requires
22 basing it on the combined usage of both the lamp and its
23 ballast since both are integral to the lighting service.
24 One of my workpapers illustrates the combined energy
25 usages
877 BOWMAN, DI 17
Idaho Power Company
.
.
.
20
1 of each lamp and ballast option.
2 Q.Will the requested monthly base rate charges
3 per lighting unit be impacted in this filing if both the
4 lamp and ballast energy usages are combined?
5 A.No. The monthly per unit base rate lamp
6 charges proposed in this filing are being computed solely
7 on a uniform increase of 2.51 percent. Requested
8 recogni tion of combined lamp/ballast monthly energy usage
9 per lighting unit will have no impact to the proposed
10 base rates. However, if adopted, any other charge based
11 on kilowatt-hour usage (e.g. the Power Cost Adjustment)
12 will result in minor billing changes.
13 Q. Does the Company currently have any lighting
14 services where the energy charges are based on both the
15 lamp and ballast usages?
16 A.Yes. The energy portion of all the Company's
17 Schedule 41, Street Lighting options currently includes
18 charges for the combined energy usage of both the lamp
19 and ballast.
Q.Are- you proposing any other changes to Schedule
21 15?
22
23
A.No, I am not.
Q.What is the present rate structure for
24 Unmetered General Service under Schedule 40?
25
878 BOWMAN, DI 18
Idaho Power Company
.
.
.
1 A.Customers taking service under Schedule 40 are
2 unmetered but have energy loads and periods of operation
3 which are fixed. The customer's computed usage is
4 charged a flat Energy Charge. Demand- and
5 customer-related costs are also recovered through the
6 Energy Charge. The minimum bill for service under
7 Schedule 40 is $1.50 per month.
8 Q.What is the revenue requirement to be recovered
9 from customers taking service under Schedule 40?
10 A.The annual revenue requirement for Schedule 40
11 customers as shown on page four of Mr. Tatum's Exhibit
12 No. 70 is $990,791.
13 Q. Please describe the rate design proposal for
14 Schedule 40.
15 A.The rate design proposal for Schedule 40 is
16 included on page five of Exhibit No. 76. It targets the
17 proposed class revenue increase of 2.51 percent as shown
18 on page four of Mr. Tatum's Exhibit No. 70. The Energy
19 Charge remains flat and increases from 5. 764 ç per
20 kilowatt-hour' to 5. 909ç per kilowatt-hour.
21 Q.Are any other changes being proposed to
22 Schedule 40?
23
24
25
A.No.
879 BOWMAN, DI 19
Idaho Power Company
1.Q. What is the present rate structure for Street
2 Lighting Service, Schedule 41?
3 A.Charges for Street Lighting Service are based
4 on a per-lamp (including ballast) or per-pole basis.
5 Street Lighting is divided into two types:(1 )
6 Company-Owned and (2) Customer-Owned. Both metered and
7 non-metered service is provided for Customer-Owned
8 lighting; only non-metered service is provided for
9 Company-Owned lighting. Schedule 41 does not allow new
10 service for incandescent, mercury vapor, or fluorescent
11 fixtures.
12 Q.Are you proposing any changes to the rate.13 structure for Schedule 41?
14 A. No. However, I am proposing clarification of
15 the "Accelerated Replacement of Existing Services" text
16 for Company-Owned systems. In order to exercise the
17 accelerated replacement option, the Customer must make
18 payments prior to the work being performed. Because
19 prepayment is required, it is inconsistent to base the
20 charges on "actual labor, time, and mileage costs."
21 Therefore the. proposed tariff text has been modified to
22 state the charges will be based on the Company's
23 "designed cost estimate" which includes labor, time, and
24 mileage..25 Q. What is the revenue requirement to be recovered
from customers taking service under Schedule 41?
880 BOWMAN, DI 20
Idaho Power Company
.
.
.
19
1 A.The annual revenue requirement for Schedule 41
2 customers as shown on page four of Mr. Tatum's Exhibit
3 No. 70 is $2,372,448.
4 Q.Please describe the rate design proposal for
5 Schedule 41.
6 A.The rate design proposal for Schedule 41 is
7 included on pages six through nine of Exhibit No. 76.
8 Each per-lamp charge for both non-metered and metered
9 service increases by the overall 2.51 percent increment
10 proposed on page four of Mr. Tatum's Exhibit No. 70 for
11 Schedule 41. In addition, the per- kilowatt-hour charge
12 for metered service also increases by 2.51 percent. The
13 monthly meter charge of $8.45 remains unchanged. To
14 encourage the retention of metered lighting systems, I
15 propose to keep this charge at its current level.
16 Q.What is the present rate structure for Schedule
17 39, Street Lighting Service Supplemental Seasonal or
18 Variable Energy?
A.Customers taking service under Schedule 39 pay
20 a flat Energy Charge based on estimated variable or
21 seasonal usage until the street lighting service is
22 converted to a metered service or the potential for
23 variable usage has been removed. The current Energy
24 Charge is the same as the current Energy Charge for
25 Schedule 40,
881 BOWMAN, DI 21
Idaho Power Company
.
.
.
20
1 Unmetered General Service.
2 Q.Please describe the rate design proposal for
3 Schedule 39.
4 A.The rate design proposal for Schedule 39 is
5 included on page four of Exhibit No. 76. The Energy
6 Charge increases from 5. 764ç to 5. 909ç per kilowatt-hour
7 in order to match the Energy Charge proposed for Schedule
8 40, Unmetered General Service.
9 Q.What is the present rate structure for Traffic
10 Control Signal Lighting Service, Schedule 42?
11 A.Customers taking service under Schedule 42 pay
12 a flat Energy Charge for each kilowatt-hour of estimated
13 energy use for non-metered systems and for each
14 kilowatt-hour of actual usage for metered systems. For
15 non-metered systems, usage is estimated based on the
16 number and size of lamps burning simultaneously in each
17 signal and the average number of hours per day the signal
18 is operated. . There is no minimum charge under Schedule
19 42.
Q.What is the revenue requirement to be recovered
21 from customers taking service under Schedule 42?
22 A.The annual revenue requirement for Schedule 42
23 customers as shown on page four of Mr. Tatum's Exhibit
24 No. 70 is $178,483.
25
882 BOWMAN, DI 22
Idaho Power Company
.
.
1 Q. Please describe the rate design proposal for
2 Schedule 42.
3 A.The rate design proposal for Schedule 42 is
4 included on page ten of Exhibit No. 76. It targets the
5 proposed capped class revenue increase of 15 percent
6 shown on page four of Mr. Tatum's Exhibit No. 70. The
7 Energy Charge increases from 3.688 9ç per kilowatt-hour to
8 4. 2422ç per kilowatt-hour.
9 Q.Is the Company proposing any other changes to
10 Schedule 42?
11 A.No.
12 MISCELLAOUS
13 Q. Are you proposing any changes not directly
14 related to the Company's retail rate design?
15 A.Yes. I am proposing a change to Schedule 89,
16 Unit Avoided Cost for Cogeneration and Small Power
17 Production, to comply with previous Commission Orders.
18 Q.Please describe the proposed change to Schedule
19 89.
20 A.Based on previous Commission Orders, the
21 pricing under Schedule 89 is to be adjusted during the
22 course of every Idaho Power general rate proceeding.
23 Using the methodology previously ordered by the
24 Commission, I have adjusted the unit-avoided energy cost.25 utilizing
883 BOWMAN, DI 23
Idaho Power Company
.
.
20
21
22
23
24.25
1 updated variable operation and maintenance costs and
2 variable fuel costs for the Valmy plant. The proposed
3 monthly rate payments increase from 2. 727ç to 2. 976ç per
4 kWh for all kWh. I have included details of this
5 adjustment in my workpapers.
6 Q.Are you sponsoring any other Exhibits not
7 already mentioned in your testimony?
8 A.Yes. Exhibit No. 78 is a summary of the
9 revenue impacts of this filing on all the Company's
10 retail rate classes. It illustrates the current and
11 proposed effective revenues of each customer class as
12 well as the requested percentage revenue increases. This
13 Exhibi t is a summary of the information provided by Mr.
14 Tatum, Ms. Waites, Ms. Nemnich, and myself.
15 Exhibi t No. 79 contains all the proposed
16 additions/deletions/modifications to the Company's
17 current tariff sheets illustrated in legislative format.
18 Exhibit No. 80 contains the Company's proposed revised
19 tariff sheets in final form.
Q.Does this conclude your testimony?
A.Yes, it does.
884 BOWMAN, DI 24
Idaho Power Company
.
.
.
1
2 open hearing.)
(The following proceedings were had in
MR. WALKER: The witness is available for
4 cross-examination.
3
5 COMMISSIONER SMITH: Okay, Mr. Bruder, do
6 you have any questions?
18
19
20
21
7
8
9
10
11
12
13
14
15
16
17
MR. BRUDER: I have none.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No, Madam Chair.
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: No cross, thank you.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Ward.
MR. WARD: No questions.
COMMISSIONER SMITH: Mr. Price.
MR. PRICE: No questions.
COMMISSIONER REDFORD: No questions.
EXAMINATION
22 BY COMMISSIONER SMITH:
23
24
25
Q
A
Q
Well, I guess that just leaves me.
Well, good.
Starting on page 4, you talk about the
CSB REPORTING
[phone]
885 BOWMAN (Com)
Idaho Power Company
.
.
20
1 agricul tural irrigation service.
2 A Yes.
3 Q And I think one of the things I wondered
4 through the years is why didn't we divide the irrigation
5 class into more than just one big lump because there's
6 such a variety of uses in terms of how they use it and
7 when they use it and how much they use, so is this what
8 your load factor is trying to get at is dividing this
9 group up a littler finer?
10 A No, load factor pricing would be the same
11 whether or not you were a small use customer or a large
12 use customer. The principle is the same regardless.
13 Q Okay; so we're still not getting at my
14 thought?
15 A Not with load factor pricing, no.
16 Q It i S probably unfair to you, but do you
17 have any thoughts on whether the irrigation class should
18 be subdivided into different groups?
19 A Not today.
COMMISSIONER SMITH: Okay, I'll ask
21 Mr. Gale. I recall I've asked this question before.
22 There was probably a satisfactory answer which has now
23 slipped my mind. I take it you have no redirect.
24.25
MR. WALKER: That is correct.
COMMISSIONER SMITH: Thank you very much,
CSB REPORTING
[phone]
886 BOWMAN (Com)
Idaho Power Company
.
.
19
1 Ms. Bowman.
2 (The witness left the stand.)
3 MR. WALKER: Madam Chair, could Ms.
4 Bowman, Nemnich and Waites, may they be excused?
5 COMMISSIONER SMITH: They may, if there's
6 no obj ection. They are excused.
7 MR. WALKER: Thank you.
8 COMMISSIONER SMITH: Now we'll re-call Mr.
9 Said, please.
10
11 GREGORY W. SAID,
12 produced as a witness at the instance of the Idaho Power
13 Company, having been previously duly sworn, resumed the
14 stand and was further examined and testified as follows:
15
16 EXAMINATION
17
18 BY COMMISSIONER REDFORD:
Q The questions I have are regarding your
20 rebuttal testimony at page 7 and 8. It's already been
21 stated by, I believe, some witnesses from Idaho Power
22 that the wind integration costs were left out of all the
23 calculations. I'm just wondering if by your testimony as
24 you provided, are you now requesting that they be.25 included?
CSB REPORTING
[phone]
887 SAID (Com)
Idaho Power Company
.
.
1 A I have not proposed that they be included.
2 I think that the original recommendation that I made is
3 still my recommendation. The only point here was to
4 point out that we did forget it and I'm not changing the
5 Company's request.
6 Q Okay. How many wind producers does Idaho
7 Power have?
8 A I was looking at Exhibit 48 hoping that
9 that would provide the answer. We have 105 PURPA
10 projects, but I'm not sure exactly how many of those are
11 wind. We do have one large wind project that's
12 approximately 100 megawatts.
13 Q And it doesn't fall wi thin PURPA rates?
14 A That's correct, and then we have a number
15 of small PURPA wind contracts as well.
16 Q And you enter into contracts with those
17 PURPA wind generators?
18 A That's correct.
19 Q And correct me if I'm wrong, included in
20 those contracts is a wind integration cost.
21 A I believe that the standard contract for
22 the PURPA proj ects envisions that they would be paid an
23 avoided cost that is then reduced by a wind integration
24 cost amount..25 Q Are you aware that the FERC standard of
CSB REPORTING'
[phone]
888 SAID (Com)
Idaho Power Company
.
.
.
1 accounts doesn't include when you calculate integration
2 costs, you're not to use avoided costs in any manner?
3 A I believe that the quantification of the
4 wind integration costs was not derived using an avoided
5 cost methodology.
6 Q But I don't think you quite answered my
7 question. Aren't these wind producers required to pay an
8 integration cost?
9 A I think it's reflected in the price that
10 they are paid as a reduction to their avoided cost.
11 Q So for the PURPA rate providers,
12 regardless of where it fits, they are being charged and
13 there's a recognition of integration costs?
14 A I believe that's true, yes.
15 Q And I believe you have one wind producer
16 that is not entitled to PURPA rates.
17 A That's correct.
18 Q Yet, you say that -- the Company also
19 stated that including wind integration costs would add
20 nearly 3.5 million to the normalized power supply
21 expense. I don't know where that comes from unless it's
22 3.5 million for the one producer that is producing over
23 100 megawatts.
24 A Well, in the computer modeling that's used
25 to figure out the total costs of providing service, the
CSB REPORTING
[phone]
889 SAID (Com)
Idaho Power Company
.
.
.
1 wind integration-related costs are not captured in the
2 detail that's provided under the AURORA model, so if
3 you're trying to identify the true costs associated with
4 the provision of power, those would necessarily be added.
5 I think your question comes back to if they're not paid
6 through the contracts, are they truly added or should
7 they truly be added.
8 Q Yes.
9 A And that's something I haven't thought
10 about. That may be true.
11 Q Well, it seems to me you can't have it
12 both ways. If you have calculated the integration costs
13 and you've charged those PURPA rate customers for that,
14 you can't double up on it by then taking the total
15 integrated costs, whatever they are and however you
16 calculated them, and, in effect, double or add those
17 back.
18 A I think the problem that kind of comes
19 down the road' is that when you're looking at the actual
20 power supply costs that occur after the fact, wind
21 integration costs are basically derived by determining
22 the additional generation expenses that may be incurred
23 in order to make up for those times when the wind
24 generation may not be there, so from a standpoint of
25 comparing the actual costs that would show up in your
CSB REPORTING
[phone]
890 SAID (Com)
Idaho Power Company
.
.
.
1 fuel, purchased power and surplus sales account, there
2 will be costs on an actual basis that will show up at
3 that point in time and would be reflected in the power
4 cost adjustment, so if the base doesn't reflect those
5 costs, you would have a bigger difference that would show
6 up and flow through the power cost adjustment.
7 Q How do you calculate the integration
8 costs?
9 A The integration costs were done as part of
10 the workshops. I don't know the modeling that was used,
11 but they looked at the hourly generation that would be
12 provided by the wind resources and looked to those hours
13 when the generation might falloff due to the wind
14 patterns and that would necessarily be replaced by firing
15 up a gas-fired or other resources that might be available
16 to substitute for the wind generation that didn't exist
17 in those hours.
18 Q Well, isn't that the very thing that the
19 contracts are supposed to capture, what the wind
20 integration costs are?
21 MR. KLINE: Mr. Commissioner, I don't want
22 to interrupt, but there is a fact that we need to present
23 to make sure that we don't go too much farther down this
24 and add additional confusion. The current PURPA
25 contracts for. wind developers do not include a reduction
CSB REPORTING
[phone]
891 SAID (Com)
Idaho Power Company
.
.
.
1 in their rates for wind integration costs. It's only the
2 future contracts where their prices will be reduced to
3 cover those wind integration costs, so the existing
4 contracts don't cover that wind integration cost and I
5 think that's the source of the $3.5 million, is it not,
6 Mr. Said?
7 THE WITNESS: That would be true. It's
8 only the proj ects that are currently on line.
9 COMMISSIONER REDFORD: Well, Mr. Kline,
10 I've reviewed and discussed on numerous occasions the
11 wind integration costs and I believe, and I may be wrong,
12 but that was a topic of discussion and in your workshops
13 you agreed that the wind integration costs would be X.
14 MR. KLINE: That's correct.
15 COMMISSIONER REDFORD: But now we see in
16 addi tion to X, we see $3.5 million for wind
17 integration.
18 MR. KLINE: But X is only applicable to
19 new contracts, not the ones that Mr. Said used to compute
20 the $3.5 million.
21 BY COMMISSIONER REDFORD: Is there anyQ
22 document anywhere in the Company that breaks out this
23 $3.5 million wind integration cost?
24 No. As I stated in my original testimony,A
25 I did not include wind integration costs and those were
CSB REPORTING
[phone]
892 SAID (Com)
Idaho Power Company
.
.
.
1 only quantified in response to a Staff production
2 request, but essentially, they are the rate that was
3 determined for future PURPA contracts applied to the
4 generation that exists in the current case as a means to
5 quantify it.
6 Q Future from when?
7 From the point in time that the windA
8 integration costs were initiated, so as Mr. Kline pointed
9 out, if it only applies to future contracts, there is
10 still a cost, a similar cost, of integrating wind that's
11 already on the system that has not been reflected.
12 And so what you're saying is that hadQ
13 those contracts all contained the wind integration
14 element, that would equal $3.5 million?
15 No, I'm saying that if yes, I thinkA
16 that is correct. If those amounts if those proj ects
17 did have that rate, it would have been 3.5 million.
18 If you have no breakdown or schedule as toQ
19 what the wind integration costs were, how can you sit
20 there and tell me that the $3.5 million amount equals
21 those costs? I mean, don't you have something where
22 you -- let's assume that there's a day that the wind is
23 not blowing and you have to use an alternative power
24 source, that's the purpose for the integration cost,
25 isn't it?
CSB REPORTING
[phone]
893 SAID (Com)
Idaho Power Company
.1 A Yes.
2 Q But if you don't have any actual data that
3 demonstrates on that day what the costs were, how can you
4 possibly tell us that you have an accurate figure as far
5 as wind integration is concerned?
6 A Well, I used the rate that was approved by
7 the Commission, first of all, and it's not a rate that's
8 determined for every single hour or every single
9 condi tion, nor is it intended to be reflective of the
10 costs in any specific hour. It's really intended to be
11 an annual representation of a rate.
12 Q This is just a -- the 3.5 is just a plug.13 number, isn't it?
14 A No, it's not. The calculation of the
15 number is by taking the Commission-approved wind
16 integration cost rate times the megawatt production of
17 wind that's existing today.
18 Q Well, I think it's fortunate for the
19 Company that they didn't include it even if it was a
20 mistake, because it seems to me that if you're asking,
21 were going to ask, for this amount to be included in this
22 rate case, I don't think you have supplied the
23 information that we need.
24 A I agree we didn't include it in our case..25 All I meant to point out was that the Staff found out
CSB REPORTING
[phone]
894 SAID (Com)
Idaho Power Company
.1 that we didn't and they didn't include it.
2 Q Just one last question; so there really
3 isn't a cost attributable to al ternati ve power. You just
4 take the approved Commission rates and guess that the
5 downtime from the wind integration is X number of hours
6 and then use the rate to calculate what the integration
7 costs would be for a particular period?
8 A The assumption that underlies that
9 methodology is that the cost of integrating a megawatt of
10 new wind is the same cost that it would have been to
11 integrate a megawatt of existing wind.
12 Q Say that again, please..13 A So from the standpoint that the Commission
14 determined that the wind integration cost associated with
15 integrating one megawatt of new wind generation was a
16 certain rate, the assumption that I used is that that
17 rate that would be appropriate for the next megawatt of
18 generation is also appropriate for the previous megawatt
19 of generation wind added.
20 Q So there's no actual calculation of wind
21 integration on a particular day as to using your
22 alternative source of energy?
23 A I believe it was done on an annual basis,
24 not an hourly basis. There were hourly computations that.25 helped derive that annual figure, but I believe it's
CSB REPORTING
[phone]
895 SAID (Com)
Idaho Power Company
.1 based on wind operation over a longer period of time than
2 a single hour.
COMMISSIONER REDFORD: I guess I have no
4 further questions. Thank you, Mr. Said.
3
5 COMMISSIONER SMITH: Do you have any
6 redirect, Mr. Kline?
10
.
7
8
9 Said.
11
12
MR. KLINE: No.
COMMISSIONER SMITH: Okay, thank you, Mr.
THE WITNESS: Thank you.
(The witness left the stand.)
COMMISSIONER SMITH: Mr. Bruder, I believe
13 we're now ready for Dr. Goins.
14 MR. BRUDER: Thank you very much. The
15 U. S. Department of Energy calls Dr. Dennis W. Goins.
. 25
16
17
18
19
20
21
22
23
24
CSB REPORTING
[phone]
896 SAID (Com)
Idaho Power Company
1 DR. DENNIS W. GOINS,.2 produced as a witness at the instance of the U. S.
3 Department of Energy, having been first duly sworn, was
4 examined and testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MR. BRUDER:
9 Q Would you please state your name for the
10 record?
11 A My name is Dennis Goins.
12 Q And by whom and in what capacity are you.13 employed, Dr. Goins?
14 A I operate an economic management
15 consultant firm called Potomac Management Group.
16 Q I show you now a document titled direct
17 testimony and exhibits of Dr. Dennis Goins. This
18 consists of 2j pages of text and 14 pages of exhibits.
19 The exhibits are numbered DOE Exhibits 607, 608 and 609.
20 These materials indicate that you prefiled them on
21 October 24th of this year. Are you the same Dr. Dennis
22 Goins who prefiled these materials on that date?
23 A Yes, the direct. It also included
24 Exhibits 610 and 611..25 Q Excuse me, 610 and 611, thank you. I show
CSB REPORTING
[phone]
897 GOINS (Di)
DOE
1 you a document now that is titled rebuttal testimony of.2 Dr. Dennis Goins. This consists of 17 pages of testimony
3 and it indicates that you prefiled it with this
4 Commission on December 3rd of this year; is that
5 correct?
6 A Yes.
7 Q And were all of these materials prepared
8 by you or under your direction?
9 A They were.
10 Q Do you have at this time any changes or
11 corrections to any of these materials?
12 A I have two, both of which are in the.13 rebuttal. At page 1, line 7, the date should be "October
14 24," not "October 28," and at page 7 of the rebuttal, in
15 the footnote, the second line, the word "as" should be
16 stricken.
17 Q With those changes, Dr. Goins, if I were
18 to ask you all of the same questions that are set out in
19 these testimonies, would all of your responses be the
20 same as those responses that those materials show?
21 A They would.
22 MR. BRUDER: Madam Chairman, I ask that
23 these materials be spread upon the record as if they had
24 been put forward from the stand today. I ask that the.25 exhibits marked here, Exhibits 607 through 611, be marked
CSB REPORTING
[phone]
898 GOINS (Di)
DOE
.
10
.
.
1 for identification and with that, I would tender this
2 witness for cross-examination.
3 COMMISSIONER SMITH: If there is no
4 obj ection, we will spread the prefiled direct and
5 rebuttal testimony of Dr. Goins upon the record as if
6 read and identify Exhibits 607 through 611.
7 (The following prefiled direct and
8 rebuttal testimony of Dr. Dennis Goins is spread upon the
9 record.)
11
12
13
14
15
16
17
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19
20
21
22
23
24
25
CSB REPORTING
[phone]
899 GOINS (Di)
DOE
.
.
1 INTRODUCTION AN QUALIFICATIONS
2 Q.PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
3 ADDRESS.
4 A.My name is Dennis W. Goins. I operate Potomac
5 Management Group, an economic and management consulting
6 firm. My business address is 5801 Westchester Street,
7 Alexandria, Virginia 22310.
8 Q.PLEASE DESCRIBE YOUR EDUCATIONAL AND PROFESSIONAL
9 BACKGROUND.
10 A.I received a Ph. D. degree in economics and a Master
11 of Economics degree from North Carolina State Uni versi ty.
12 I also earned a B.A. degree with honors in economics from
13 Wake Forest University. From 1974 through 1977 I worked
14 as a staff economist at the North Carolina Utili ties
15 Commission (NCUC). During my tenure at the NCUC, I
16 testified in numerous cases involving electric, gas, and
17 telephone utili ties on such issues as cost of service,
18 rate design, intercorporate transactions, and load
19 forecasting. While at the NCUC, I also served as a
20 member of the Ratemaking Task Force in the national
21 Electric Utility Rate Design Study sponsored by the
22 Electric Power Research Institute (EPRI) and the National
23 Association of Regulatory Utility Commissioners (NARUC).
24 Since 1978 I have worked as an economic and.25 management consultant to firms and organizations in the
900 Goins - Di 1
DOE
.
.
15 /
16
17
18
19
20
21
22
23
24.25
1 private and public sectors. My assignments focus
2 primarily on market structure, policy, planning, and
3 pricing issues involving firms that operate in energy
4 markets. For example, I have conducted detailed analyses
5 of product pricing, cost of service, rate design, and
6 interutili ty planning, operations, and pricing; prepared
7 analyses related to utility mergers, transmission access
8 and pricing, and the emergence of competi ti ve markets;
9 evaluated and developed
10
11 /
12
13 /
14
901 Goins - Di 1a
DOE
.1 regulatory incentive mechanisms applicable to utility
2 operations; and assisted clients in analyzing and
3 negotiating interchange agreements and power and fuel
4 supply contracts. I have also assisted clients on
5 electric power market restructuring issues in Arkansas,
6 New Jersey, New York, South Carolina, Texas, and
7 Virginia.
8 I have submitted testimony and affidavits and
9 provided technical assistance in more than 100
10 proceedings before state and federal agencies as an
11 expert in competitive market issues, regulatory policy,
12 utili ty planning and operating practices, cost of.13
14
service, and rate design. These agencies include the
Federal Energy Regulatory Commission (FERC), the
15 Government Accountability Office, the First Judicial
16 District Court of Montana, the Circuit Court of Kanawha
17 County, West Virginia, and regulatory agencies in
18 Alabama, Arizona, Arkansas, Colorado, Florida, Georgia,
19 Idaho, Illinois, Kentucky, Louisiana, Maine, Maryland,
20 Massachusetts, Minnesota, Mississippi, New Jersey, New
21 York, North Carolina, Ohio, Oklahoma, South Carolina,
22 Texas, Utah, Vermont, Virginia, and the District of
23 Columbia. Additional details of my educational and
24 professional background are presented in the Appendix..25 I have also participated in several cases before
902 Goins - Di 2
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20
21
22
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1 this Commission involving Idaho Power Company (IPC).
2 These cases include Docket Nos. IPC-E-03-13, IPC-E-04-23,
3 IPC-E-05-28, and IPC-E-07-08.
4 Q.ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS
5 PROCEEDING?
6 A.I am testifying on behalf of the U. S. Department of
7 Energy (DOE) representing the Federal Executive Agencies
8 (FEA), which is comprised of all Federal facilities
9 served by Idaho Power Company (IPC). Two of the larger
10 FEA facilities are the Department of Energy's Idaho
11 National Laboratory (DOE) and Mountain Home
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903 Goins - Di 2a
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1 Air Force Base. IPC serves DOE under a special contract,
2 and serves the bulk of Mountain Home AFB' s load under
3 Schedule 19 Large Power Service.
4 Q.WHAT ASSIGNMENT WERE YOU GIVEN WHEN YOU WERE
5 RETAINED?
6 A.I was asked to undertake two primary tasks:
7 1.Review IPC' s proposed cost-of-service
8 analyses (including pro forma adjustments)
9 and related rates.
10 2.Identify any maj or deficiencies in the
11 cost analyses and proposed rates and
12 suggest recommended changes.
13 Q. WHAT SPECIFIC INFORMATION DID YOU REVIEW IN
14 CONDUCTING YOUR EVALUATION?
15 A.I reviewed IPC' s application, testimony, exhibits,
16 and responses to requests for information related to cost
17 of service, revenue spread, and rate design issues. I
18 also reviewed documents found on web sites operated by
19 the Commission and by IPC.
20 CONCLUSIONS
21 Q.WHAT CONCLUSIONS HAVE YOU REACHED?
22 A.On the basis of my review and evaluation, I have
23 concluded the following:
24 1.IPC's Cost of Service. IPC has proposed
25 increasing base revenues by approximately
904 Goins - Di 3
DOE
1 $ 66.6 million (9.89 percent).In developing.2 proposed rates for its retail electric
3 services,IPC first conducted three (3 )
4 cost-of-service (COS)studies for the test year
5 ending December 31,2008.In these cost
6 analyses,IPC allocated and/or directly
7 assigned its costs to functional
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905 Goins -Di 3a
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1 segments of its retail electric business. The
2 return component of IPC' s costs reflects a
3 requested 8.55 percent return on its retail
4 jurisdictional rate base (using an 11.25
5 percent return on common equity). IPC calls
6 the three cost studies the:
7 *Base Case, which is supposedly similar to
8 the COS methodology IPC presented in Case
9 No. IPC-E-03-13. In the Base Case, IPC
10 classified 59.38 percent of its fixed
11 costs associated with steam (FERC accounts
12 310-316) and hydro (FERC accounts 330-336)
13 production plant as energy-related costs,
14 and the remainder-40. 62 percent-as
15 demand-related costs. The 59.38 percent
16 classification is equal to the IPC
17 jurisdictional load factor. IPC allocated
18 its demand-related production costs to
19 customer classes using a marginal-
20 cost-weighted average of each
21 class' contribution to IPC' s 12 monthly
22 coincident peaks. That is, IPC used a
23 version of the weighted 12CP (W12CP)
24 allocation method. In its final order in
25 Case No. IPC-E-03-13, the Commission found
906 Goins - Di 4
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11
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23
1 that the W12CP methodology reflected a
2 reasonable approximation of class cost
3 responsibility.
4 *Modified Base Case, which is the Base Case
5 wi th two modifications. First, IPC
6 classified purchased power expenses (FERC
7 account 555) i as demand and energy costs
8 in the same manner as hydro and steam
9 production plant costs are classified-that
10 is, 40.62 percent as demand-related costs
and 59.38 percent as energy-related costs.
(In the Base Case, IPC classified almost
all of its purchased power costs as
energy-related costs.)Second, energy
cost allocators E10S and
24 i This account include sub-accounts 555. i (power purchases) and 555.2
(purchases from cogeneration and small power producers-or CSPPs) ..25
907 Goins - Di 4a
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1 E10NS were derived using the average of
2 each class' normalized kWh sales and its
3 marginal-cost-weighted normalized kWh
4 sales.
5 *3CP /12CP, which is the Modified Base Case
6 wi th production plant split into two
7 categories that I call baseload capaci ty2
8 and peaking capacity. IPC assigned all
9 steam (FERC accounts 310-316) and hydro
10 (FERC accounts 330-336) production plant
11 to the baseload capacity category, and
12 combustion turbine (CT) plant costs (FERC
13 accounts 340-346) to the peaking capacity
14 category. IPC allocated plant costs
15 assigned as peaking capacity on the basis
16 of each class' average coincident peak in
17 June, July, and August (that is, a 3CP
18 allocation method). Like the Modified
19 Base Case, hydro and steam production
20 plant costs were allocated using a 12CP
21 allocator. However, the allocation
22 factors were not weighted by IPC' s
23 marginal-costs-that is, IPC used an
24 unweighted 12CP allocator.
25 IPC's preferred cost-of-service
908 Goins - Di 5
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23
1 methodology is the 3CP/12CP method.
2 According to IPC, the 3CP/12CP method best
3 reflects factors driving IPC' s need for
4 capaci ty to meet growing summer demands as well
5 as year-round demands.
6 2.Cost-of-Service Problems. In this case, IPC
7 recommends a production cost allocation method
8 that the Commission has never approved. Prior
9 to this case, the Commission's last addressed
10 the allocation of demand-related production
11 costs in Case No. IPC-E-03-13, in which it
12 approved the W12CP method-a method that the
13 Commission had endorsed in several preceding
14 cases. In the current case, IPC recommends a
15 seriously
.24 2 Includes capacity designed to serve both baseload and intermediate
load requirements.
25
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1 flawed 3CP /12CP allocation method. In
2 particular, the IPC' s 3CP /12CP cost-of-service
3 study (COSS):
4 *Departs from Commission precedent.
5 *Improperly classifies steam and hydro
6 production plant costs and Account 555
7 purchased power expenses as demand- and
8 energy-related costs.
9 *Improperly splits Account 555 costs into
10 baseload and peaking categories. I
11 discuss this in more detail later.
12 *Fails to track costs accurately. For
13 example, IPC's 3CP/12CP cost study does
14 not reflect the concentration of purchased
15 power costs in the summer peak months,
16 thereby understating costs assigned to
17 summer peak usage. That is, costs that
18 should be allocated primarily to classes
19 wi th heavy summer electricity usage are
20 instead allocated to classes with high
21 load factor usage in non-summer, off-peak
22 months (for example, special contract and
23 Schedule 19 customers). As a result, low
24 load factor classes with high summer
25 demands are able to avoid responsibility
910 Goins - Di 6
DOE
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for a large share of purchased power costs
they cause IPC to incur.
*Fails to allocate steam and hydro
production plant costs; fuel costs, and
revenues from off-system sales (Account
447) in a manner that properly aligns
class cost responsibility with class loads
that underlie these costs and revenues.
For example, most of IPC' s off-system
sales revenue is produced in non-summer,
non-peak months when significant excess
baseload capacity (steam and hydro.capaci ty) is available. Higher load
factor classes are allocated most of IPC' s
.
911 Goins - Di 6a
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1 baseload production costs, and therefore
2 should also be allocated most of its
3 off-system sales revenues. Yet IPC
4 allocates off-system sales revenue on the
5 basis of marginal-cost-weighted energy
6 usage. As a result, lower load factor
7 classes with heavy energy usage in peak
8 months are allocated too large a share of
9 off-system sales revenues-thereby
10 understating their test-year cost
11 responsibility.
12 3.Revenue Spread. IPC spread its proposed
13 revenue increase among rate classes using the
14 following 4-step sequential approach:
15 *Identify sales revenue increases (or
16 decreases) necessary to match total
17 revenue from each class with IPC's
18 estimated cost of serving the class as
19 determined in IPC' s 3CP /12CP cost study.
20 *Set a 15-percent limit on rate increases
21 to Special Contracts customers and
22 Schedules 19 Large Power Service, 24
23 Irrigation Service, and 42 Traffic Control
24 Lighting.
25 *Hold revenues from Schedules 15, 40, and
912 Goins - Di 7
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.1
2
3
4
5
6
7
8
9 Q.
41 at test-year levels under present rates
instead of decreasing revenues as
indicated by the COSS results-that is,
gi ve no initial increase to this class.
*Spread the revenue shortfall caused by the
15-percent cap on class increases across
all non-capped rate schedules.
RECOMMNDATIONS
WHAT DO YOU RECOMMEND ON THE BASIS OF THESE
10 CONCLUSIONS?
12.13
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24.25
11 A.I recommend the following:
/
913 Goins - Di 7a
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1 Rej ect IPC' s 3CP /12CP cost-of-service study.
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1.
The study is seriously and probably fatally
flawed because it fails to align cost
allocation with cost responsibility.
2.Rej ect IPC' s classification of steam and hydro
production plant costs as demand- and
energy-related costs. Instead, all steam and
hydro production plant costs should be
classified as demand-related costs. IPC' s
proposed classification scheme suffers from at
least two arbitrary assumptions. First, the
classification scheme arbitrarily assumes that
IPC's system load factor somehow identifies the
portion of generation plant costs that is
supposedly energy-related. IPC has provided no
empirical analysis to justify or support its
choice of system load factor to classify
production plant costs. 4 Second, like most
capi tal substitution arguments, 5 the
classification scheme implicitly assumes that
if all production plant costs were classified
as demand-related costs, higher load factor
customers would receive a disproportionate
share of the cheap energy benefits of baseload
and intermediate capacity without paying a
914 Goins - Di 8
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20
21
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24.25
1 proportionate share of the higher capital costs
2 of such capacity-particularly if demand-related
3 capaci ty costs are allocated on the basis of
4 peak demands . Neither assumption is
5 intui ti vely obvious or empirically supportable.
6
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12
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16
17 3 Throughout my testimony I focus on IPC's 3CP/12CP cost study since
IPC recommends this study. However, IPC' s Base Case and Modified
Base Case cost studies suffer from deficiencies comparable to those I
describe regarding the 3CP/12CP cost study. As a result, neither the
Base Case nor the Modified Base Case studies should be used for
setting IPC' s rates in this case.
4 IPC with Timothy Tatum (direct testimony at 29: 7-10) says that the
load factor methodology used to classify steam and hydro production
plant reflects "the methodology preferred by the Commission in prior
general rate proceedings."
5 With respect to system planning analyses that focus on choosing a
mix of generation plant that meets expected demand at least cost,
capi tal substi tution refers generally to trade-offs between
production plant with relatively high capital costs but low energy
costs (for example, basload generating units) and production plant
with relatively low capital costs but high energy costs (for example,
combustion turbines).
18
19
915 Goins - Di 8a
DOE
1 3.If the Commission allows IPC to classify steam.2 and hydro plant costs into demand and energy
3 cost components, then system load factor should
4 not be used to determine the energy cost
5 component. Instead, as an al ternati ve, I
6 recommend classifying 57.10 percent of these
7 plant costs as demand and 42.90 percent as
8 energy.(I describe how these percentages are
9 deri ved later in my testimony.) Wi th respect
10 to the classification of hydro plant, IPC uses
11 hydro plant not only to meet baseload demands,
12 but also to serve peak loads. This operating.13 flexibility is not reflected in a
14 classification scheme based on system load
15 factor.
16 4.Rej ect IPC' s classification of Account 555
17 purchased power costs. Instead, they should be
18 classified using the same alternative
19 classification scheme I propose for classifying
20 steam and hydro plant costs (that is, 57.10
21 percent demand and 42.90 percent energy.)
22 5.Rej ect IPC' s proposed assignment of all
23 demand-related hydro plant costs to the
24 baseload capacity category. This assignment.25 ignores the role that hydro plant plays in
916 Goins - Di 9
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18
19
20
21
1 meeting IPC' s summer peak demands. Instead, I
2 recommend assigning 50 percent of demand-
3 related hydro costs to the baseload plant
4 category (which is allocated on the basis
5 of 12CP demands) and 50 percent to the peaking
6 category (which is allocated on the basis of
7 3CP demands). My recommended alternative
8 classification scheme falls between the
9 100-percent demand classification scheme IPC
10 uses for peaking CTs and the approximately 40
11 percent demand/60 percent energy scheme it uses
12 to classify baseload steam generating costs. 6
13
14 /
15
16 /
17
22 6 A reasonable argument could also be made that under IPC' s 3CP/12CP
methodology, some portion of steam production plant should be
23 designated as peaking capacity and allocated on the basis of 3CP
demands. I do not address this issue in my direct testimony.
24.25
917 Goins - Di 9a
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1 Rej ect IPC' s proposed assignment of
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6.
demand-related purchased power costs to
baseload and peaking capacity categories on the
basis of how it assigns production plant to
these categories. IPC' s approach assigns far
too little of Account 555 costs to the peaking
cat~gory. Instead, I recommend using the same
50/50 demand and energy split for
demand-related Account 555 costs that I
recommend for assigning demand-related hydro
plant costs.
7 Rej ect IPC' s marginal-cost-weighted allocation
of energy costs in its 3CP /12CP study.
Instead, an unweighted energy cost allocation
should be used to ensure that higher load
factor classes are assigned a higher percentage
of the lower fuel costs associated with
baseload capacity.
8.Require IPC to allocate demand-related
production costs using a weighted 12CP method.
I present results from two W12CP cost studies
that I performed in Exhibit Nos. 610 and 611.
9.Rej ect IPC' s proposed revenue spread, which is
based on its 3CP /12CP cost study results.
Instead, I recommend that results from my
918 Goins - Di 10
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24.25
1 Exhibi t No. 611 be used as a starting point in
2 developing a revenue spread for any rate change
3 the Commission approves in this case. At this
4 point, I have not developed a proposed revenue
5 spread for all classes based on results from my
6 W12CP cost study. However, results from my
7 W12CP cost study-combined with the total
8 unreliability of results from IPC' s costs
9 studies-support an across-the-board revenue
10 spread. Moreover, in addition to my
11 recommended W12CP cost study, other studies
that I prepared clearly show that IPC' s
proposed 15 percent increases for DOE and
Schedule 19 are excessive. IPC' s proposed
increases for these customers are about 1.5
919 Goins - Di lOa
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1 times the system average increase of 9.89
2 percent. My analyses indicate that increases
3 to DOE and Schedule 19 should be limited to the
4 system average increase and under no
5 circumstance should exceed 1.10 times the
6 system average increase.
7 10. Require IPC to retain the services of a
8 reputable outside firm to examine, evaluate,
9 and recommend necessary changes to its
10 cost-of-service model. More than 5 years have
11 passed since the Commission ordered IPC in Case
12 No. IPC-E-03-13 to work with stakeholders to
13 address cost-of-service issues. The issues
14 have not been resolved. Large customers such
15 as DOE and Mountain Home AFB no longer have
16 confidence that IPC' s cost studies properly
17 reflect class cost responsibility. While my
18 recommended changes mitigate some of the more
19 obvious problems in IPC' s cost analyses, they
20 do not resolve a fundamental problem.
21 Specifically, classes driving the need for
22 additional capacity to meet summer peak demands
23 are not being assigned a fair share of the
24 costs of meeting those demands.
25
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24.25
1 COST OF SERVICE
2 Q.DID IPC ESTIMATE ITS COST OF SERVING DIFFERENT
3 CUSTOMER CLASSES?
4 A.Yes. IPC conducted three detailed cost-of-service
5 studies using data (adjusted in many cases) for the test
6 year ending December 31, 2008. In these cost analyses,
7 IPC classified and then allocated and/or directly
8 assigned its costs to functional segments of its retail
9 electric business. The return component of IPC' s costs
10 reflects a requested 8.55 percent return on its Idaho
11 retail jurisdictional rate base (using an 11.25 percent
12 return on common equity) .
13
14 /
921 Goins - Di 11a
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17
1 Q.DOES YOUR TESTIMONY ADDRESS EACH OF IPC' S COST
2 STUDIES?
3 A.No. My testimony focuses on IPC' s preferred
4 3CP /12CP cost-of-service study. However, most of my
5 cri ticisms of IPC' s 3CP /12CP cost study would also be
6 applicable to IPC' s Base Case and Modified Base Case cost
7 studies that I described earlier.
8 Q.HAS THE COMMISSION EVER APPROVED IPC' S 3CP/12CP
9 METHOD FOR ALLOCATING DEMAND-RELATED PRODUCTION COSTS?
10 A.No. Prior to this case, the Commission's last
11 addressed the allocation of demand-related production
12 costs in Case No. IPC-E-03-13, in which it approved the
13 W12CP method-a method that the Commission had also
14 endorsed in several preceding cases.
15 Q.IN ITS 3CP /12CP COST STUDY, HOW DID IPC ALLOCATE
16 DEMAND-RELATED PRODUCTION AND PURCHASED POWER COSTS?
A.In its 3CP /12CP cost study, IPC allocated
18 demand-related steam and hydro production plant and
19 Account 555 purchased power costs categorized as baseload
20 capaci ty on the basis of each class' unweighted 12
21 monthly coincident peak demands (12CP). IPC allocated
22 demand-related CT plant and purchased power costs
23 categorized as peaking capacity on the basis of each
24 class' unweighted monthly coincident peak demands in the.25 3 summer months June-August (3CP).
922 Goins - Di 12
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1 Q.HOW DID IPC ALLOCATE ENERGY-RELATED COSTS?.2 A.In its 3CP /12CP cost study,IPC used the average of
3 marginal-cost-weighted and unweighted summer and
4 non-summer ratios to derive the summer and non-summer
5 energy allocation factors (E10S and E10NS) .
6
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24.25
923 Goins -Di 12a
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1 Q.PLEASE DESCRIBE HOW IPC CLASSIFIED PRODUCTION PLANT
2 AND PURCHASED POWER COSTS.
3 A.In its 3CP /12CP cost study, 7 IPC classified steam
4 (FERC Accounts 310-316) and hydro (FERC Accounts 330-336)
5 production plant costs and purchased power costs (FERC
6 Account 555) as demand- and energy-related costs. IPC
7 set the energy-related component of these costs equal to
8 the Idaho jurisdictional load factor (59.38 percent),
9 with the residual-40.62 percent or (1 - load
10 factor) -classified as demand-related costs. IPC
11 classified 100 percent of its investment in combustion
12 turbines (FERC Accounts 340-346) as demand related costs.
13 Q. DO YOU AGREE WITH IPC' S CLASSIFICATION OF PRODUCTION
14 PLANT AND PURCHASED POWER COSTS?
15 A.I agree with the classification of CT costs, but
16 disagree with IPC' classification of steam and hydro
17 production plant costs and purchased power expenses. For
18 example, according to the NARUC cost allocation manual
19 and contrary to IPC' s classification, all hydro plant
20 costs and most hydro operation and maintenance expenses
21 should be classified as demand-related costs. 8 In
22 general, IPC' s classification of steam and hydro
23 production plant and purchased power costs rests on
24 questionable assumptions, the validity of which is
25 nei ther intui ti vely obvious nor empirically demonstrable.
924 Goins - Di 13
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19
20
21
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23
24.25
1 More specifically, IPC' s steam and hydro classification
2 scheme rests on the following arbitrary assumptions:
3 1.Higher load factor customers receive a
4 disproportionate share of the cheaper energy
5 benefits of baseload and intermediate capacity
6 wi thout paying a proportionate share of the
7 higher capital costs of such capaci ty-
8
9 /
10
11 /
12
13 /
14
15
16
17
18
7 IPC also used the same classification scheme in its Base Case and
Modified Base Case cost studies.
8 National Association of Regulatory Utility Commissioners, Electric
Utility Cost Allocation Manual, Washington, DC, January 1992, at
35-38. (NARUC cost manual)
925 Goins - Di 13a
DOE
1.particularly if demand-related capacity costs
2 are allocated on the basis of peak demands.
3 2.System load factor somehow identifies the
4 portion of generation plant costs that are
5 supposedly energy-related costs.
6 Regarding the first assumption, baseload and
7 intermediate plants are planned and designed to operate
8 during more than peak demand periods, and higher load
9 factor customers use energy from such plants in non-peak
10 periods. However, whether higher load factor customers
11 benefit disproportionately from cheaper baseload and
12 intermediate plant energy is an empirical question that.13 IPC has not addressed in this case. Moreover, in
14 addressing this question, the method used to allocate
15 energy-related costs must be considered. For example, if
16 production plant costs are classified as energy-related
17 costs and energy costs are allocated on the basis of
18 average energy use, then low load factor customers will
19 likely receive the benefits of cheaper base load and
20 intermediate energy without paying a fair share of the
21 capi tal costs for these plants.
22 Regarding the second assumption, using IPC' s
23 system load factor to identify the portion of production
24 plant costs to classify as energy-related costs is.25 totally arbitrary. System load factor is an indicator of
926 Goins - Di 14
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.
20
21
22
23
24.25
1 the relative use of supply resources (production plant)
2 over time, and provides neither an economic nor
3 engineering rationale for classifying production plant
4 costs.
5 Q.IF THE COMMISSION REQUIRES THAT SOME PART OF STEAM
6 AND HYDRO PLANT COSTS BE CLASSIFIED AS ENERGY COSTS, HOW
7 SHOULD THE ENERGY-RELATED COMPONENT BE IDENTIFIED?
8 A.Let me reiterate-in my opinion, all production plant
9 costs should be classified as demand-related costs.
10 Nonetheless, if part of IPC' s production plant costs is
11
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18
19
927 Goins - Di 14a
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25
1 classified as energy-related costs, I recommend setting
2 the percentage of such plant costs classified as
3 energy-related costs equal to the ratio of IPC' s weighted
4 energy aiiocators in non-capacity deficit months-that is,
5 all months other than May - September and December-to the
6 weighted 12-month allocator. This approach provides at
7 least some intui ti ve linkage between the energy cost of
8 production plant and high load factor energy use.
9 Q.WHAT is THE RESULT OF USING THIS APPROACH?
10 A.Under this approach, 42.90 percent of IPC' s steam
11 and hydro production plant costs would be classified as
12 energy-related costs. This percentage is derived as
13 follows:
14 *In IPC's Exhibit No. 59, page 5, sum the
15 weighted retail jurisdiction energy factors for
16 the six non-capacity deficit months-that is,
17 all months other than May - September and
December. This value is 468,444,966.
*Divide 468,444,966 by 1,092,008,268-the sum of
weighted retail jurisdiction energy use for all
12 months. The resulting value is 42.90
percent. The remaining 57.10 percent of costs
should be classified as demand.
Q.DOES THIS ALTERNATIVE CLASSIFICATION SCHEME BETTER
REFLECT DRIVERS UNDERLYING I PC'S NEED FOR STEAM AND HYDRO
928 Goins - Di 15
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24.25
1 PRODUCTION PLANT?
2 A.Yes. As I noted earlier, steam and hydro generation
3 plant investments are primarily undertaken to meet
4 demand, and a classification scheme that results in
5 allocating nearly 60 percent of these costs on the basis
6 of energy simply makes no economic or engineering sense.
7 This problem is particularly acute for hydro plant.
8
9 /
10
11 /
12
13 /
14
929 Goins - Di 15a
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.
.
1 IPC has publicly stated that it often manages its hydro
2 plant to serve peak hours-not simply to meet baseload
3 demand. 9 This operating flexibility is not reflected in
4 a classification scheme based on system load factor. My
5 recommended al ternati ve demand-energy classification
6 scheme is reasonable because it recognizes why IPC adds
7 capaci ty and how it uses that capacity. Moreover, my
8 al ternati ve classification yields logical results that
9 happen to fall between the 100-percent demand
10 classification scheme IPC uses for peaking CTs and the
11 approximately 40 percent demand/60 percent energy scheme
12 it uses to classify baseload steam generating costs.
13 Q. SHOULD YOUR ALTERNATIVE CLASSIFICATION SCHEME ALSO
14 APPLY TO IPC' S PURCHASED POWER COSTS?
15 A.Yes. In this case, IPC finally recognized that its
16 purchased power costs have a significant demand-related
17 component. However, IPC used its system load factor
18 method to classify Account 555 costs as demand- and
19 energy-related costs. I disagree with this method, and
20 recommend that my alternative method be used to classify
21 purchased power costs. As a result, 57.10 percent of
22 Account 555 costs should be classified as demand, and
23 42.90 percent should be classified as energy.
24
25
Q.DID IPC ASSIGN ANY HYDRO PLANT COSTS TO THE PEAKING
CAPACITY CATEGORY?
930 Goins - Di 16
DOE
.
.
.
18
19
20
21
22
23
24
25
1 A.No.IPC assigned all demand-related hydro plant
2 costs to the base load capacity category. This assignment
3 ignores hydro's role in meeting IPC' s summer peak demands
4 and understates cost-responsibility for summer peak
5 usage. To address this problem, I recommend assigning 50
6 percent of demand-related hydro costs to
7
8 /
9
10 /
11
12 /
13
14
15
16
17
9 For example, see the direct testimony of IPC's witness Timothy
Tatum in Docket No. E-07-08 at 12: 24-25. In his testimony in the
current case, witness Tatum inexplicably omits any reference to hydro
as a peaking resource. See the direct testimony of witness Tatum at
24:4-7.
931 Goins - Di 16a
DOE
.
.
.
1 the baseload plant category (which is allocated on the
2 basis of 12CP demands) and 50 percent to the peaking
3 category (which is allocated on the basis of 3CP
4 demands) .
5 Q.DID IPC PROPERLY SPLIT PURCHASED POWER COSTS INTO
6 BASELOAD AND PEAKING CAPACITY CATEGORIES?
7 A.No. IPC assigned demand-related purchased power
8 costs to baseload and peaking capacity categories on the
9 basis of how it assigns production plant to these
10 categories. This approach ignores the simple fact that
11 nearly half of IPC' s Account 555 purchases occur in the
12 summer peak months June-August. IPC' s approach assigns
13 far too little of Account 555 costs to the peaking
14 category. Instead, I recommend using the same 50/50
15 demand and energy split for demand-related Account 555
16 costs that I recommend for assigning demand-related hydro
17 plant costs.
18 Q.WOULD YOUR RECOMMENDED CHANGES SIGNIFICANTLY AFFECT
19 HOW IPC' S PRODUCTION AND PURCHASED POWER COSTS WERE
20 ALLOCATED TO CUSTOMER CLASSES?
21 A.Yes . Exhibit No. 607 summarizes these differences.
22 As shown in this exhibit, my recommended changes would
23 justifiably reduce the portion of production plant and
24 purchased power costs classified as energy and shift more
25 costs to the peaking category.
932 Goins - Di 17
DOE
.
.
.
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Q.HAVE YOU PERFORMED A COST STUDY THAT INCORPORATES
2 YOUR RECOMMENDED CHANGES?
3 A.Yes. I modified IPC' s 3CP /12CP cost study to
4 reflect the recommended changes shown in Exhibit No. 607.
5 In general, results from this study indicate
6 significantly lower cost responsibilities for Schedule 19
7 and special contract
8
9 /
10
/
933 Goins - Di 17a
DOE
.
.13
14
1 customers.(See Exhibit No. 608.) For example, my
2 analysis indicates that a 15. 71 percent revenue increase
3 (about $916,000) is required to bring DOE to cost of
4 service. In contrast, IPC's 3CP/12CP analysis (Exhibit
5 No. 66) indicates that a 25.37 percent increase ($1.48
6 million) is required. This huge disparity shows why
7 properly classifying IPC' s hydro plant costs and
8 purchased power costs is critical.
9 Q.WHY ARE YOU CONCERNED SINCE IPC' S PROPOSED INCREASE
10 FOR DOE-15 PERCENT-IS ALMOST IDENTICAL TO THE INCREASE
11 SUGGESTED BY YOUR MODIFIED 3CP/12CP ANALYSIS?
12 A.My concern is that even with the changes I have
discussed, IPC' s 3CP /12CP cost study still significantly
overstates cost responsibility for higher load factor
15 customers. My recommended changes mitigate-but do not
16 fix-fundamental flaws in IPC's 3CP/12CP cost study. For
17 example, in addition to the problems I have cited, IPC's
18 costing approach
19
20
21
22
23
24.25
*Double counts average demands by combining a
3CP and 12CP allocation approach for
demand-related production costs. IPC' s
3CP /12CP methodology is similar to peak and
average allocation methods described in the
NARUC cost manual. In typical peak and average
cost studies, all demand-related production
934 Goins - Di 18
DOE
.
10
11
12 /.13
14
15
16 /
17
18
19
20
21
22
23
24.25
1 costs are allocated on the basis of a single
2 measure of peak demand (for example, a single
3 CP or a single measure of several CPs).
4 However, in IPC' s 3CP /12CP cost study, IPC has
5 allocated only production costs assigned to the
6 peaking category on the basis of the 3CP
7 demands that are driving IPC' s need for
8 capaci ty. The bulk of demand-related
9 production costs are allocated across all peak
and non-peak months on
/
935 Goins - Di 18a
DOE
.
.
.
1 the basis of 12 CPs, thereby diluting the
2 influence of the principal system peaks that
3 dri ve the need for capacity. Moreover, IPC' s
4 allocation of capacity cost responsibility is
5 further diluted by classifying almost 60
6 percent of its fixed production plant costs as
7 energy. The end result of this convoluted
8 process is an assignment of production costs
9 that has no relationship to why and how IPC
10 incurs costs to serve peak demands.
11 *Fails to reflect the concentration of purchased
12 power costs in the summer peak months, thereby
13 understating costs assigned to summer peak
14 usage. As a result, costs that should be
15 allocated to lower load factor classes with
16 heavy summer usage are instead allocated to
17 higher load factor classes (for example,
18 special contract and Schedule 19 customers).
19 Even my recommended 50/50 split of Account 555
20 costs into baseload and peaking capacity
21 categories is only an indirect correction for
22 this problem. Moreover, the impact of my
23 proposed modification is muted because nearly
24 43 percent of purchased power costs are
25 allocated on annual energy in my analysis,
936 Goins - Di 19
DOE
.1
2
3
4
5
6
7
8
9
10
11
12
13
14
15 /
16
17 /
18
19 /
20
21
22
23
24
25
resulting in a likely understatement of
purchased power costs that should be assigned
to the summer peaking period.
*Fails to align cost responsibili ty with the
allocation of steam and hydro production plant
costs; fuel costs, and revenues from off-system
sales (Account 447). I discussed this problem
earlier regarding the allocation of off-system
sales revenue. A similar problem exists with
the allocation of fuel costs under IPC' s
3CP/12CP methodology. For example, higher load
factor classes are allocated a higher.percentage
.
937 Goins - Di 19a
DOE
.
.
.
1 of fixed production costs without being
2 allocated a similar higher percentage of the
3 fuel-cost savings associated with these plants.
4 Q.HAVE YOU ANALYZED HOW THESE FLAWS AFFECT THE
5 ALLOCATION OF COSTS?
6 A.Yes. I ran IPC' s 3CP /12CP cost study again, but
7 made only one change. Instead of assigning production
8 costs to peaking and baseload categories, I simply
9 allocated all demand-related production costs on the
10 basis of a 3CP allocator. I used IPC' s classification
11 scheme to identify demand- and energy-related production
12 and purchased power costs. This approach is consistent
13 wi th a typical peak and average cost study. 10 The
14 resul ts were dramatic for selected customers compared to
15 IPC's 3CP /12CP study.(See Exhibit No. 609.) For
16 example, the required rate increases for DOE and Schedule
17 19 fell to 10.82 percent and 11.40 percent, respectively,
18 compared to 25.37 percent and 15.87 percent in IPC' s
19 study.
20
21
Q.DID YOU PERFORM A WEIGHTED 12CP COST STUDY?
A.Yes. Since the W12CP demand-related cost allocation
22 methodology is the last methodology formally approved by
23 the Commission, I decided to conduct a W12CP cost
24 analysis. In my W12CP analysis, I used
25 marginal-cost-weighted loads to allocate demand-related
938 Goins - Di 20
DOE
.
.
.
20
21
22
23
24
25
1 production and transmission costs, and
2 marginal-cost-weighted energy to allocate energy-related
3 costs. I developed this factor without averaging
4 weighted and unweighted loads and energy as IPC did in
5 its Base Case study. I ran two versions of the W12CP
6 model. In the first version, I used IPC' s load factor
7 method to identify demand- and energy-related fixed
8 production costs. Results from this study indicate that
9 rate increases for Schedule 19 and DOE should be around
10 11.75 percent-far below results shown in IPC' s
11
12 /
13
14 /
15
16 /
17
18
19
10 I am not recommending a peak and average allocation method. I
present this peak and average analysis only to highlight the serious
problems in IPC' s 3CP /12CP cost study.
939 Goins - Di 20a
DOE
.
.
1 3CP /12CP cost study and well below the 15 percent capped
2 increase that IPC recommends.(See Exhibit No. 610.)
3 Resul ts from the second version included my recommended
4 al ternati ve method for identifying demand- and
5 energy-related fixed production costs. Results from this
6 second study indicate that rate increases for Schedule 19
7 and DOE should be below 8 percent-less than IPC' s
8 proposed system average increase.(See Exhibit No. 611.)
9 Q.is IPC'S 3CP/12CP METHODOLOGY REASONABLE?
10 A.No. In my direct testimony in IPC' s 2007 rate case
11 (Case No. IPC-E-07-08), I noted that although the
12 methodology is not widely used, it appeared to be
13 reasonable, even though I preferred allocation methods
14 that were more straightforward. However, in this case,
15 after examining IPC' s 3CP /12CP cost methodology and
16 underlying costs more closely, I have concluded that
17 IPC' s 3CP/12CP COSS is seriously and probably fatally
18 flawed. The 3CP/12CP methodology as applied by IPC
19 simply does not track cost of service, resulting in too
20 few costs assigned to summer peak months and too many
21 costs assigned to higher load factor customers. As a
22 resul t, its results should not be relied on to determine
23 class revenue increases.
24.25
Q.SHOULD THE COMMISSION REQUIRE IPC TO ADDRESS
PROBLEMS WITH ITS COST ANALYSES NOW INSTEAD OF WAITING
940 Goins - Di 21
DOE
.
.
17
18
19
20
21
22
23
24.25
1 FOR FUTURE CASES?
2 A.Yes. Stakeholders have waited more than 5 years
3 since the Commission ordered IPC to work with
4 stakeholders to address cost-of-service issues. The
5 issues have not been resolved. Large customers such as
6 DOE and Mountain Home AFB no longer have confidence that
7 IPC' s cost studies properly reflect class cost
8
9 /
10
11 /
12
13 /
14
15
16
941 Goins - Di 21a
DOE
.
.
.
1 responsibili ty. While my recommended changes mitigate
2 some of the more obvious problems with IPC' s cost
3 analyses, they do not resolve a fundamental problem.
4 Specifically, classes driving the need for additional
5 capacity to meet summer peak demands are not being
6 assigned a fair share of the costs of meeting those
7 demands. As a result, I recommend that the Commission
8 require IPC to retain the services of a reputable outside
9 firm to examine, evaluate, and recommend necessary
10 changes to its cost-of-service model. Interested
11 stakeholders should be allowed to participate in this
12 process, or at least be regularly briefed on IPC' s
13 progress in improving its costing analyses.
14 REVENU SPRE
15 Q.HOW DID IPC SPREAD ITS PROPOSED REVENUE INCREASE
16 AMONG CUSTOMER CLASSES?
17 A.As I described earlier, IPC used a 4-step sequential
18 approach to spread its proposed revenue increase among
19 rate classes. This approach-which is linked to results
20 from IPC' s 3CP /12CP cost study-is presented in IPC
21 Exhibit No. 70.
22 Q.DO YOU AGREE WITH IPC' S PROPOSED REVENUE SPREAD?
23 A.No. As I just noted, correcting some of the obvious
24 flaws in IPC's never-before-approved 3CP/12CP cost study
25 significantly, alters the class cost responsibilities on
942 Goins - Di 22
DOE
.
.
.
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
1 which IPC based its proposed revenue spread. I do not
2 consider resnl ts from any of IPC' s cost studies reliable,
3 and do not believe they should be used to spread any
4 revenue increase that IPC receives in this case. As a
5 resul t, an across-the-board increase for all classes
6 would be reasonable. If the Commission wants to use
7 resul ts from a cost study as a starting point in
8 spreading any revenue increase that IPC receives, then I
9 recommend using results from my W12CP study shown in
10 Exhibit No. 611. If the Commission rejects an
11 across-the-board revenue
12
943 Goins - Di 22a
DOE
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.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1
.spread, I recommend that any increase applied to Schedule
2 19 and DOE be limited to the system average increase, and
3 under no circumstances should they be more than 1.10
4 times the system average increase. I base this
5 recommendation on results from my cost analyses.
6 Q.DOES THIS COMPLETE YOUR DIRECT TESTIMONY?
7 A.Yes.
8
9
944 Goins - Di 23
DOE
.
.
.
1 INTRODUCTION
2 Q.PLEASE STATE YOUR NAME, OCCUPATION, AND
3 BUSINESS ADDRESS.
4 A.My name is Dennis W. Goins. I operate Potomac
5 Management Group, an economic and management consulting
6 firm. My business address is 5801 Westchester Street,
7 Alexandria, Virginia 22310.
8 Q.DID YOU FILE DIRECT TESTIMONY IN THIS CASE ON
9 OCTOBER 28, 2008?
10 A.Yes.
11 Q.ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS
12 PROCEEDING?
13 A. I am testifying on behalf of the U. s.
14 Department of Energy (DOE) representing the Federal
15 Executive Agencies (FEA), which is comprised of all
16 Federal facilities served by Idaho Power Company (IPC).
17 Two of the larger FEA facilities are the Department of
18 Energy's Idaho National Laboratory (DOE) and Mountain
19 Home Air Force Base. IPC serves DOE under a special
20 contract, and serves the bulk of Mountain Home AFB' s load
21 under Schedule 19 Large Power Service.
22
23
Q.WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY?
A.The purpose of my rebuttal testimony is to
24 respond to certain conclusions and recommendations made
25 in direct testimony filed by Anthony Yankel on behalf of
945 Goins - Reb 1
DOE
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.
.
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 the Idaho Irrigation Pumpers Association, Inc. (IIPA) and
2 Kei th Hessing on behalf of the Staff of the Idaho Public
3 Utilities Commission. In particular, I will respond to:
4 1.IIPA witness Yankel' s attempt to recognize
5 the impact of load growth in IPC' s
6 cost-of-service analysis. As I discuss
7 later, witness Yankel' s effort
8
9 /
/
946 Goins - Reb 1a
DOE
.
.
.
21
22
23
24
25
1 is essentially a roundabout way to argue
2 for vintage pricing of IPC' s assets-that
3 is, assigning entitlement to older,
4 lower-cost assets to existing loads and
5 then charging new loads for the higher
6 marginal cost of capacity additions.
7 Vintage pricing is both arbitrary and
8 economically inefficient, and should be
9 rej ected. Witness Yankel' s vintage
10 pricing adjustments to IPC' s
11 cost-of-service methodology suffer from
12 the same deficiencies and should be
13 rejected.
14 2.Staff witness Hessing's uncritical
15 adoption of IPC' s 3CP /12CP cost-of-service
16 methodology. He relies on results from
17 IPC's cost study to develop his
18 recommended revenue spread based on the
19 Staff's proposed revenue requirement.
20 However, the cost study on which he relies
ignores numerous deficiencies in IPC' s
costing methodology that I identified in
my direct testimony. Because witness
Hessing relies on an improper and
unreasonable allocation of IPC' s costs,
947 Goins - Reb 2
DOE
.
.
18 /
19
20
21
22
23
24.25
1 his recommended revenue spread does not
2 properly track IPC' s actual cost of
3 serving retail customers in Idaho. His
4 recommended higher-than-average rate
5 increases for higher load factor1 classes
6 and special contract customers should be
7 rejected.
8 IIPA WITNSS YANKEL
9 Q.PLEASE DESCRIBE WITNESS YANKEL' S PRIMARY
10 CRITICISM OF IPC' S COST-OF-SERVICE METHODOLOGY.
11 A.Wi tness Yankel presents data showing that loads
12 for the irrigation class have grown very little in the
13 past 25 years relative to load growth for other classes.
14 He
15
16 /
17
1 Load factor refers to the ratio of a customer's average demand to
peak demand during a specified period. For example, if a customer
uses 2,190 kWh per month, the customer's average demand is 3 kW in a
typical month (2,190 kWh divided by 730 hours per month). If the
customers maximum monthly peak demand is 10 kW, the customer's
monthly load factor is 30 percent (3 kW divided by 10 kW). We
generally classify low load factor customers as those with load
factors below the system average load factor, and high load factors
customers as those with load factors above the system average load
factor. ipe' s annual system load factor typically falls between 55
and 60 percent.
948 Goins - Reb 2a
DOE
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.
.
19
20
21
22
1 also shows that during this 25-year period, IPC' s
2 plant-in-service has more than doubled to meet load
3 growth, leading to significant rate increases to pay for
4 the additional costs of IPC' s expanding asset base. He
5 then concludes that customers whose load growth caused
6 the need for additional capacity should pay for the
7 resul ting higher cost of service. According to witness
8 Yankel, because irrigation loads have grown little in 25
9 years, irrigation customers should bear little if any of
10 the higher cost of new capacity (generation,
11 transmission, and distribution) to meet load growth. He
12 cri ticizes IPC' s costing methodology because, in his
13 opinion:
14 ...the Company's cost of service study
15 inappropriately allocates a significant portion
16 of this growth to the Irrigation class. Gi ven
17 the obvious fact that growth and the cost of
18 growth are not being fueled by the Irrigators,
the allocation of significant portions of the
cost of this growth to the Irrigators is on its
face counter-intuitive.2
Q.HOW DOES WITNESS YANKEL PROPOSE TO FIX THIS
23 ALLEGED PROBLEM?
24
25
A.He proposes modifying IPC' s cost-of-service
methodology to address what he calls backward-iooking
949 Goins - Reb 3
DOE
1 costs and forward-looking costs.His direct testimony.2 addresses his proposed solution using these two cost
3 concepts:
4
5 /
6
7 /
8
9 /
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24 2 See the direct testimony of IIPA witness Anthony J. Yankel at
9:9-12..25
950 Goins - Reb 3a
DOE
.
.
.
1 The simplest way to correct the Company's Base
2 Case study would be to continue to define
3 "backward-looking" costs base on test year
4 usage levels and "forward-looking costs" at the
5 anticipated increase in usage levels in the
6 Company IRP. The "backward-looking costs"
7 would simply be costs as they exist today and
8 allocated on the basis of today' s energy or
9 12-CP as is presently done in the Company's
10 "base" cost of service study. The "forward
11 looking costs" would be developed using the
12 same weighting factors used by the Company
13 associated with the cost of the anticipated
14 growth, but would be allocated on the basis of
15 only the growth that is anticipated from each
16 rate schedule over a future ten year period.
17 The relative share of historic costs and
18 anticipated costs related to growth would then
19 be averaged using the Company's existing
20 procedures in order to develop a composite
21 allocation factor for use in spreading test
22 year costs for allocation purposes. In this
23 manner, the methodology would be exactly the
24 same as the Company's Base Case, but the
25 marginal costs would be tied to the
951 Goins - Reb 4
DOE
.
.
20
21
22
23
1 marginal/new usage and not to the present level
2 (status quo) of usage.3 (Emphasis in
3 original. )
4 Q.DOES IPC' S COSTING METHODOLOGY FAIL TO ASSIGN
5 COSTS PROPERLY TO REFLECT FACTORS DRIVING ITS NEED FOR
6 NEW CAPACITY?
7 A.Yes. However, witness Yankel does not
8 correctly identify deficiencies in IPC' s costing
9 methodology that cause the problem with respect to the
10 allocation of production costs, nor does he propose a
11 reasonable and proper solution. I agree
12
13 /
14
15 /
16
17 /
18
19
24 3 Ibid. at 19:13 - 20:2..25
952 Goins - Reb 4a
DOE
.
.
.
1 wi th him that IPC' s recommended costing methodology is
2 seriously deficient. But I disagree regarding how to fix
3 IPC' s methodology.
4 Q.is WITNESS YANKEL' S CRITICISM OF IPC' S COST
5 STUDY BASED ON A VALID PREMISE?
6 A.No. Witness Yankel implicitly assumes that if
7 a class has little or no load growth, then it also should
8 have little if any growth in costs assigned to it. This
9 assumption ignores a fundamental tenet of cost of
10 service-namely, costs should be assigned using allocation
11 factors that reasonably link costs and cost-drivers.
12 Consider IPC' s production costs. As I noted in my direct
13 testimony, the key driver underlying IPC' s need for new
14 production resources (both new capacity and expensive
15 purchased power) is peak demand in summer months. As a
16 resul t, a reasonable cost-of-service methodology should
17 ensure that the allocation of these higher summer-related
18 costs should be linked to summer peak demands. That is,
19 customer classes that use electricity primarily in summer
20 peak months-regardless whether their loads have grown or
21 remained stable in the past 25 years-should expect to see
22 significantly higher rates as IPC adds production
23 resources. Instead, as my direct testimony shows, IPC' s
24 classification and allocation of production costs focuses
25 on year-round average demands and energy usage, not
953 Goins - Reb 5
DOE
.1 summer peak demands. Not surprisingly-albeit
2 incorrectly, IPC' s costing methodology implies huge rate
3 increases for high load factor classes, yet little if any
4 increase for most lower load factor classes that
5 contribute heavily to summer peak demands relative to
6 their demands in off-peak months.
7 Q.DOES ALL LOAD GROWTH CAUSE IPC TO ADD CAPACITY?
8 A.No. In trying to link load growth to cost
9 assignment, witness Yankel ignores the link between the
10 timing of electric loads and IPC' s need for new
11 production
12.13
14
15 /
16
17 /
18
19
20
21
22
23
24.25
Ii
/
954 Goins - Reb 5a
DOE
.1 resources. For example, demands in peak periods drive
2 capacity requirements, while load growth in off-peak
3 hours may have little if any effect on IPC' s need for new
4 production capacity. In criticizing IPC' s costing
5 methodology , witness Yankel never mentions that the bulk
6 of the irrigation class' annual kWh usage and highest
7 class peaks occur in peak hours in peak summer months.
8 In fact, to the extent that IPC' s costing methodology
9 understates production costs attributable to summer peak
10 demands, costs assigned to the irrigation class are
11 understated-not overstated at witness Yankel contends.
12 This result was confirmed in the cost-of-service analyses.13 presented in my direct testimony, which indicated that
14 the rate increase for the irrigation class should be
15 significantly greater than the increase proposed by IPC.
16 Q.is WITNESS YANKEL' S PROPOSED FIX WORSE THAN THE
17 ALLEGED PROBLEM IT is DESIGNED TO CURE?
18 A.Yes. His proposed fix uses an average of
19 growth-adjusted forward-looking costs and historical
20 backward-looking costs to allocate test-year costs. This
21 scheme is nothing more than a variant of vintage pricing,
22 which attempts to insulate classes wi th little or no load
23 growth from any cost responsibility for new capacity-even
24 if their peak demands coincide with other demands that.25 are driving the need for new capacity. Instead of
955 Goins - Reb 6
DOE
.
10 /
11
12 /.13
14
15
16
17
18
19
20
21
22
23
24.25
1 resorting to vintage pricing, the cure for the alleged
2 problem that witness Yankel describes is twofold:
3 .Properly classify and allocate production costs
4 to emphasize summer peak demands as the driving
5 force behind IPC' s recent and planned
6 production resource additions.
7
8 /
9
956 Goins - Reb 6a
DOE
.
.14
1 .Shift load to off-peak periods to avoid
2 contributing to system peak demands. Simply
3 stated, cost responsibility assigned to
4 irrigators in any properly designed
5 cost-of-service study will decline as
6 irrigators shift more load to off-peak hours.
7 Q.is VINTAGE PRICING ECONOMICALLY EFFICIENT?
8 A.No. Vintage pricing assumes specific customers
9 have entitlement to lower cost assets simply by virtue of
10 when they became market participants. Under witness
11 Yankel' s scheme, the higher marginal cost of new capacity
12 addi tions is assigned primarily to classes with
13 significant load growth, while no-growth classes are
primarily assigned much lower historical embedded costs.
15 Charging some customers prices based on marginal capacity
16 costs while charging other customers using the same
17 capaci ty prices based on historical embedded costs is
18 both economically inefficient and discriminatory.
19 Moreover, vintage pricing encourages no-growth classes to
20 use more energy in high-cost peak periods. Under witness
21 Yankel' s scheme, irrigation customers would be encouraged
22 to use more energy in summer peak periods, even while IPC
23 is promoting its Peak Rewards program to encourage
24 irrigation customers to shift loads to off-peak hours..25 Q.HAS VINTAGE PRICING BEEN LARGELY DISCREDITED?
957 Goins - Reb 7
DOE
.
.
20
21
22
1 A.Yes. Vintage pricing has generally been
2 recognized as bad regulatory policy. 4 For example, in a
3 1993 report in which it discussed whether new or existing
4 customers should be primarily responsible for the cost of
5 transmission capacity additions, the National Regulatory
6 Research Institute (NRRI) stated:
7
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
23 4 I do not consider direct cost assignments (for example, directly
charging customers for the incremental cost of interconnection
24 upgrades that a utility does not normally provide) a form of vintage
pricing..25
958 Goins - Reb 7a
DOE
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
1 ...In most cases, transmission line upgrades
2 are likely to be constructed not only to
3 serve the current applicant, but also to
4 serve proj ected future applicants, and to
5 provide more reliable service to existing
6 wholesale, retail, and transmission
7 customers. FERC might choose to protect
8 existing wholesale, retail, and
9 transmission customers at all costs. This
would result in a system of vintage
pricing, with existing customers paying a
depreciated embedded cost of old plant and new
customers paying the full incremental cost of
new plant. One outcome of such pricing is that
the old customers would benefit, enj oying
increased reliability and the opportunity to
increase their own wholesale or retail
purchases or transmission service without
paying any part of the cos t of service of the
new plant.Such vintage pricing makes for bad
economics,whether or not practicable or
feasible.5 (Emphasis added. )
Q.DID WITNESS YANKEL CONDUCT A COST STUDY THAT
24 INCORPORATED HIS PROPOSED FIX?
25 A.Yes~ He prepared a cost study that included
959 Goins - Reb 8
DOE
.
.
.
16
17 /
18
19 /
20
21
1 growth-adj usted allocation factors for generation and
2 transmission costs but not distribution costs. 6 As
3 expected, his study generally implies rate increases
4 similar to those proposed by IPC except for the
5 irrigation class.
6 Q.DO YOU AGREE WITH THE RESULTS FROM HIS COST
7 STUDY?
8 A.No. Even if one agreed with the premise of
9 wi tness Yankel' s growth-adj usted cost study, one could
10 not agree with his study's results because of a serious
11 error he introduced in his analysis. Specifically, in
12 developing his growth-adj usted allocation factors,
13 wi tness Yankel used annual class energy growth instead of
14
15 /
22 5 Kenneth W. Costello et al., A Synopsis of the Energy Policy Act of
1992: New Tasks for State Public Utility Commissions, The National
23 Regulatory Research Institute, Columbus, Ohio, June 1993 at 31.
6 See Yankel direct testimony at Exhibit No. 302.
24
25
960 Goins - Reb 8a
DOE
.
.
.
15
1 summer peak demand growth-the primary driver underlying
2 IPC's need for additional production resources.
3 Moreover, he did not to correct the classification and
4 allocation errors embodied in IPC' s costing methodology,
5 thereby ensuring that his results did not reflect proper
6 links between customer demands and cost allocation. The
7 Commission should reject his growth-adjusted
8 cost-of-service study and associated revenue spread.
9 Q.SHOULD A COST STUDY ATTEMPT TO ADDRESS THE
10 IMPACT OF LOAD GROWTH ON RISING COSTS?
11 A.Yes. But such attempts should be direct,
12 transparent, and economically rational. Assigning asset
13 entitlements to specific customers or classes through
14 vintage pricing is not a proper mechanism to address load
growth in a cost study.(Neither is the convoluted
16 blending of average and marginal cost concepts as occurs
17 in IPC' s 3CP /12CP cost study.) Instead, in an embedded
18 cost analysis, load growth can be properly addressed by
19 linking as closely as possible allocation factors to cost
20 drivers. For example, if summer peak demands are
21 principal drivers behind rising production costs, then
22 fixed production cost should be classified as
23 demand-related costs and allocated using schemes that
24 emphasize summer peak demands-not energy usage (think
25 IPC's 3CP /12CP methodology) .
961 Goins - Reb 9
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1 STAFF WITNESS HESSING.2 Q.DOES STAFF RECOMMEND IPC'S PROPOSED 3CP/12CP
3 COST-OF-SERVICE METHODOLOGY?
4 A.Yes.Staff witness Hessing recommends that the
5 Commission adopt IPC's 3CP /12CP methodology7.
6
7 /
8
9 /
10
11 /
12
13.14
15
16
17
18
19
20
21
22
23
24 7 See the direct testimony of Staff witness Keith Hessing at 8: 25 _
9: 1..25
962 Goins - Reb 9a
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.
.
.
1 Q.WHAT is THE COMMON THEME BETWEEN COST-OF-
2 SERVICE POSITIONS TAKEN BY WITNESSES YANKEL AND HESSING?
3 A.Both witnesses-consistent with IPC' s witness
4 Tatum-recommend disproportionate allocations of
5 production-related costs to loads occurring in non-summer
6 months and off-peak hours. Their recommendation is
7 premised on support ( either explicit or implicit) for
8 effectively allocating steam and hydro production-related
9 costs away from the summer on-peak loads though a
10 combination of classification and allocation techniques
11 that improperly focus on energy usage. While witness
12 Yankel ' s position is understandable-the irrigation class
13 benefi ts from disproportionate cost allocations to
14 off-peak loads-I do not understand why Staff supports a
15 costing methodology that fails to emphasize summer peak
16 demands as the principal driver behind IPC's rising
17 production costs. Moreover, the costing methodologies
18 advocated by IIPA and Staff put a completely unreasonable
19 emphasis on energy usage as a principal cost driver.
20 Q.HOW DOES THIS OVER-EMPHASIS ON ENERGY OCCUR?
21 A.The problem starts with IPC's (and Staff's) use
22 of load factor to classify steam and hydro production
23 plant. Under this load factor classification scheme, IPC
24 (and Staff) classify almost 60 percent of these fixed
25 costs as energy-related costs. No witness in this case
963 Goins - Reb 10
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.
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11 /
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15 /
16
17
18
19
20
21
22
23
24
25
1 has provided a valid reason why such a high percentage of
2 IPC's fixed production costs should be classified as
3 variable energy costs. That should surprise nobody since
4 the classification cannot be justified on either economic
5 or engineering grounds. As I noted earlier, load factor
6 is simply the relationship between average and peak
7 demands. While system load factor may influence the
8 types and operation of system production resources, it
9 does not
/
964 Goins - Reb lOa
DOE
.
.
.
1 reflect the driving force underlying the amount of
2 required production resources-namely peak demands. 8
3 IPC' s and Staff's over-emphasis on energy as a
4 cost driver is then exacerbated by the use of 12CP
5 factors in the 3CP /12CP methodology to allocate the 40
6 percent of steam and hydro fixed costs that are
7 classified as demand costs. A 12CP allocation method is
8 a hybrid between strict demand and energy allocation
9 approaches since it diminishes the importance of annual
10 peaks through averaging, thereby indirectly recognizing
11 annual energy usage in assigning cost responsibility for
12 fixed production costs. As a result, the 12CP method
13 shifts cost responsibility to energy-intensive, high load
14 factor customers. More importantly, except for utili ties
15 with similar monthly peaks, the 12CP method largely
16 ignores the role of annual system peaks in driving the
17 need for and operation of production capacity. 9 For
18 example, in IPC' s case, the 12CP approach almost totally
19 ignores the role that hydro plant in particular plays in
20 serving IPC' s summer peak loads. Combining a load factor
21 scheme that improperly classifies 60 percent of IPC' s
22 steam and hydro plant costs as energy costs with an
23 allocation method that mutes the importance of summer
24 peak demands in allocating the remaining demand-related
25 40 percent of these costs results in further unjustified
965 Goins - Reb 11
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.1 shifts of IPC' s production costs to high load factor
2 customers.
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
.
1 7 8 While I support classifying all steam and hydro plant costs as
demand-related costs, in my direct testimony I presented a rational
18 alternative to IPC's (and Staff's) load factor classification scheme.
My alternative classified IPC's steam and hydro plant costs as 57.10
19 percent demand and 42.90 percent energy. I offered this alternative
simply as an option if the Commission decides that some part of IPC' s20 fixed steam and hydro plant costs should be classified as
energy-related costs.
21 9 A 12CP allocation method is sometimes justified as a means of
reflecting the value of production capacity in all months - including
22 months with maximum demands far below the utility's annual system
peak. However, a utility does not plan for and add production
23 capacity to meet the average of its 12 monthly system peaks. Its
capacity additions are driven by its need to meet annual system
24 peaks. Capacity used to meet annual system peaks then becomes
available to meet peak demands in all other months.
25
966 Goins - Reb 11a
DOE
.
.
.
1 Q.DID STAFF PERFORM A COST-OF-SERVICE STUDY USING
2 THE 3CP /12CP METHODOLOGY?
3 A.Yes. The cost-of-service analysis that Staff
4 conducted (see Staff Exhibit No. 130) was based on a
5 lower jurisdictional revenue requirement than IPC
6 proposed.
7 Q.DID STAFF CORRECT ANY OF THE DEFICIENCIES IN
8 IPC' S COST STUDY THAT YOU IDENTIFIED IN YOUR DIRECT
9 TESTIMONY?
10 A.No. Staff witness Hessing made no changes in
11 IPC' s cost study with respect to the classification and
12 allocation of IPC' s retail costs. Staff's
13 cost-of-service study is simply IPC' s cost study with
14 Staff's lower jurisdictional revenue requirement. As a
15 result, Staff1 s cost study suffers from the same fatal
16 flaws as IPC' s cost study-flaws that I discussed in
17 detail in my direct testimony.
18 Q.DID STAFF PROPOSE A REVENUE SPREAD THAT
19 REFLECTS RESULTS FROM ITS COST-OF-SERVICE ANALYSIS?
20 A.Yes. Staff's proposed revenue spread is quite
21 similar to IPC' s proposed spread although the percentage
22 increases are smaller because of Staff's lower revenue
23 requirement. In particular, Staff's proposed revenue
24 spread calls for increases well above the system average
25 increase for higher load factor customers, including
967 Goins - Reb 12
DOE
.
.
.
1 special contract customers.
2 Q.HOW DOES STAFF JUSTIFY ITS RECOMMENDED
3 HIGHER-THAN-AVERAGE RATE INCREASES FOR HIGHER LOAD FACTOR
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
4 CUSTOMERS?
5 A.Staff implies that because average rates
6 (prices) for higher load factor customers (around $30
7 dollars per MWh) are less than IPC' s marginal power
8 supply costs
9
/
968 Goins - Reb 12a
DOE
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.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 (around $60 per MWh according to witness Hessing), above
2 average increases for higher load factor customers should
3 be expected. 10
4 Q.DOES THIS RELATIONSHIP BETWEEN MARGINAL POWER
5 SUPPLY COSTS AND AVERAGE RATES SUPPORT STAFF'S
6 RECOMMENDED REVENUE SPREAD?
7 A.No. Witness Hessing's cost and rate comparison
8 ignores two key factors:
9 .IPC's test-year average fuel and purchased
power expense is less than $18 per
MWh-well below the average price witness
Hessing claims that higher load factor
customer pay and far below his estimated
$ 60 per MWh marginal power supply cost.
Under IPC' s rates, customers are charged
average power supply costs-not marginal
costs. Moreover, marginal power supply
costs are not constant-they may vary
significantly by hour, day, or month. In
many hours of the year, the average price
IPC charges for energy may be
significantly above its marginal cost of
energy.
.In a properly designed cost-of-service
study, high load factor customers should
969 Goins - Reb 13
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.
16
17
18 /
19
20 /
21
22 /
23
24.25
1 receive most of the off-system sales
2 revenue credits resulting from off-peak
3 sales attributable to excess block energy
4 purchases and available system hydro
5 capacity. This does not happen in IPC' s
6 cost study-which Staff recommends-because
7 off-system sales revenue credits are
8 allocated without reference to when such
9 sales occur (primarily off-peak months) .
10 As I pointed out in my direct testimony,
11 because IPC' s costing methodology does not
12 properly link sales revenue credits to
13 off-peak energy usage, a
14 disproportionately small share of the
15 off-system sales revenue credits is
assigned to
10 Ibid. at 11: 2-7 .
970 Goins - Reb 13a
DOE
.
.
1 higher load factor customers and a
2 disproportionately high share is assigned
3 to lower load factor customers whose
4 electrici ty usage occurs primarily in
5 summer peak months. As a result, IPC's
6 cost of serving higher load factor
7 customers is overstated and understated
8 for low load factor classes.
9 Q.HAS THE COMMISSION TRADITIONALLY RELIED ON COST
10 STUDIES THAT ALLOCATE A DISPROPORTIONATE AMOUNT OF IPC' S
11 STEAM AND HYDRO PLANT COSTS TO NON-SUMMER, OFF-PEAK
12 LOADS?
13 A. No. For 25 years the Commission has
14 consistently adopted what is commonly referred to as a
15 weighted 12CP methodology to allocate demand-related
16 steam and hydro production plant costs to rate classes.
17 The weights used to develop class allocation factors are
18 IPC' s monthly marginal generation capacity costs. These
19 weighted 12CP allocation factors emphasize peak demands
20 in summer months when IPC' s marginal generation capacity
21 costs are highest. As a result, weighted 12CP factors
22 allocate substantially more costs to rate classes that
23 use the IPC system during summer peak hours. Because
24 IPC's growing summer peak demands are driving its need.25 for production resources, the Commission should not
971 Goins - Reb 14
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.
.
20
21
22
23
24.25
1 support any cost-of-service methodology that does not
2 emphasize the importance of summer on-peak demands in
3 driving the need for capacity resources-for example, the
4 costing methodologies proposed by witnesses Yankel and
5 Hessing. Instead, the Commission should adopt my
6 recommended classification of production costs and my
7 recommended weighted 12CP methodology, which emphasizes
8 summer peak demands, to allocate IPC' s production costs
9 to rate classes.
10
11 /
12
13 /
14
15 /
16
17
18
19
972 Goins - Reb 14a
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.
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
1 Q.SHOULD THE COMMISSION REJECT STAFF'S
2 RECOMMENDED COST STUDY AND ASSOCIATED REVENUE SPREAD?
3 A.Yes. Staff's cost study is fatally flawed, and
4 its recommended revenue spread-which is derived from the
5 cost study results-does not reasonably track IPC' s cost
6 of serving each customer class.
7 Q.HAVE YOU CHANGED ANY RECOMMENDATIONS IN YOUR
8 DIRECT TESTIMONY AFTER REVIEWING THE TESTIMONY FILED BY
9 WITNESSES YANKEL AND HESSING?
A.No. I still recommend the following:
1.Rej ect IPC' s 3CP /12CP seriously and
probably fatally flawed cost-of-service
study.11
2.Rej ect IPC' s classification of steam and
hydro production plant costs as demand-
and energy-related costs. Instead, all
steam and hydro production plant costs
should be classified as demand-related
costs.
3.If the Commission allows IPC to
classify steam and hydro plant costs into
demand and energy cost components, then
system load factor should not be used to
determine the energy cost component.
Instead, as an al ternati ve, I recommend
973 Goins - Reb 15
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.
.
15 /
16
17
18
19
20
21
1 classifying 57.10 percent of these plant
2 costs as demand and 42.90 percent as
3 energy.(I described how these
4 percentages are derived in my direct
5 testimony. )
6 4.Rej ect IPC' s classification of Account 555
7 purchased power costs.Instead, they
8 should be classified using the same
9 al ternati ve classification
10
11 /
12
13 /
14
22 11 Throughout my direct testimony I focused on IPC's 3CP/12CP cost
study since IPC recommends this study. However, IPC' s Base Case and
23 Modified Base Case cost studies suffer from deficiencies comparable
to those in the 3CP/12CP cost study. As a result, neither the Base
24 Case nor the Modified Base Case studies should be used for setting
IPC's rates in this case.
25
974 Goins - Reb 15a
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.
1 scheme I propose for classifying steam and
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
hydro plant costs (that is, 57.10 percent
demand and
42.90 percent energy.)
5.Rej ect IPC' s proposed assignment of all
demand-related hydro plant costs to the
base load capacity category. Instead, I
recommend assigning 50 percent of
demand-related hydro costs to the base load
plant category (which is allocated on the
basis of 12CP demands) and 50 percent to
the peaking category (which is allocated
on the basis of 3CP demands) .
6.Rej ect IPC' s proposed assignment of
demand-related purchased power costs to
baseload and peaking capacity categories
on the basis of how it assigns production
plant to these categories. Instead, I
recommend using the same 50/50 demand and
energy split for demand-related Account
555 costs that I recommend for assigning
demand-related hydro plant costs.
7 Rej ect IPC' s marginal-cost-weighted
allocation of energy costs in its 3CP /12CP
study. Instead, an unweighted energy cost
975 Goins - Reb 16
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17
18
19
20 /
21
22 /
23
24.25
1 allocation should be used to ensure that
2 higher load factor classes are assigned a
3 higher percentage of the lower fuel costs
4 associated with baseload capacity.
5 8.Require IPC to allocate demand-related
6 production costs using a weighted 12CP
7 method. I presented results from two
8 W12CP cost studies that I performed in
9 Exhibit Nos. 610 and 611.
10 9.Rej ect any revenue spread that is based on
11 3CP /12CP cost study results. Instead,
12 results from my Exhibit No. 611 should be
13 used as a starting point in developing a
14 revenue spread for any rate change the
15 Commission approves in this case. 12 At a
16 minimum, these results support an
across-the-board revenue spread instead of
the higher-than-average increases for
12 This includes, Staff's proposed revenue requirement.
976 Goins - Reb 16a
DOE
1 higher load factor and special contract.2 customers proposed by IPC and Staff.
3 10. Require IPC to retain the services of a
4 reputable outside firm to examine,
5 evaluate, and recommend necessary changes
6 to its cost-of-service model.
7 Q.DOES THIS COMPLETE YOUR REBUTTAL TESTIMONY?
8 A.Yes.
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
977 Goins - Reb 17
DOE
.1
2 open hearing.)
(The following proceedings were had in
COMMISSIONER SMITH: Mr. Ward, do you have
MR. WARD: Just very briefly.
CROSS-EXAMINATION
Dr. Goins, you've reviewed the testimony
11 of the other cost of service witnesses, have you not?
.
3
4 questions?
5
6
7
8
9 BY MR. WARD:
10 Q
Yes.
13 Q And just in very general terms, would you
16 Dr. Reading's?
17 A
12 A
14 say there is a similarity or a common modus operandi
18 Q
15 between your testimony and Dr. Peseau' sand
Yes, I would.
And, of course, you're well aware on the
19 other end of the spectrum we have Mr. Yankel' s testimony
20 and the Company's and Staff's cost of service testimony
21 and there's rather a wide gulf between these results and
22 these approaches, isn't there?
23
24.25
A
Q
It's a huge gulf.
And I ask those questions because I want
to follow up on a suggestion you made in your testimony,
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DOE
.1 both in direct and in rebuttal, and you recommended that
2 the Commission engage or direct Idaho Power to engage an
3 independent third party to examine their system and make
4 some recommendations on cost of service. Do you recall
5 that recommendation?
6 A Yes, I do.
7 Q Now, interestingly enough, in meeting with
8 Idaho Power after the last rate case, Micron made the
9 same recommendation. What I want to follow up on is are
10 there in fact independent third parties that could
11 perform that service for the Commission directly or for
12 Idaho Power?.13
14
A Well, there are. There are consulting
firms that specialize in this issue, but with all
15 consulting firms, those firms sometimes are known by the
16 methods and approaches that they recommend most commonly,
17 but what we have here in Idaho is a situation that in
18 particular over the last five years has developed in
19 which there's a growing gap between the confidence that
20 major ratepayer groups have in the fair and reasonable
21 assignment of costs that occur under Idaho Power's cost
22 studies and those costs are dramatic, and in particular,
23 when I think about in reviewing and participating in the
24 '03 case, the Commission addressed these issues and.25 created a task force and hoped that the parties would try
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1 to come to some resolution of the various issues.
2 Some of the issues in this case are new or
3 at least explored for the first time by a number of
4 parties and fairly in-depth analysis and in particular by
5 the industrial intervenors, I would say, and one of the
6 reasons is that the shift and the rate increases that
7 have occurred since the '03 case, and beginning since the
8 '03 case in particular, have just been enormous.
9 Now, one of the primary principles of
10 ratemaking, cost of service, that Professor Bonbright put
11 forth years and years ago and people have generally tried
12 to follow is that whatever methodology you adopt, you
13 would hope that it not only has all of the theoretical
14 and empirical underpinnings that make ita fair and
15 reasonable approach, but it also is not subj ect to
16 dramatic shifts and changes that may occur because one
17 factor or two factors that are employed wi thin the cost
18 study change.
19 That's not true with the Idaho Power cost
20 of service approach. Those changes have been swift,
21 dramatic and enormous and in particular for schedules 19
22 and the special contracts, so if the Company and the
23 various parties want to reach some agreement, they were
24 unable to reach agreement in the 2004 task force that was
25 created and, to my knowledge, nothing truly meaningful
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1 has been done since that time, there have been two other
2 rate cases prior to this one and of those two, those two
3 were settled and nothing has really changed and we have
4 laid out on the table here a fairly detailed explanation
5 by the critics of the Idaho Power approach and also a
6 fairly detailed response by Idaho Power to those
7 cri ticisms, and to be fair, it's trying to wade through
8 the details, the massive amount of data, the key
9 assumptions, the applications of different methods and
10 trying then to interpret the results of all of those
11 numerous mathematical manipulations, some human
12 manipulations ~ is somewhat problematic and that's why,
13 for example, I recommended two things: One, at least in
14 this case an across-the-board revenue spread because I'm
15 not convinced certainly that either the revenue spread
16 proposed by the Staff or Mr. Yankel or -- well,
17 Mr. Yankel, I wouldn't put him in exactly the same issue,
18 but the Staff and the Company, both of which focus
19 primarily on well above average increases for high load
20 factor classes compared to the results that fallout of
21 what I believe are appropriate and reasonable cost
22 studies that have been produced in this case counter to
23 the Company's proposal.
24 Exactly how do you resolve that? I simply
25 said as an intermediate step an across-the-board spread.
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981 GOINS (X)
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1 People said well, we had across-the-board spreads in the
2 last two cases, we've got to make some meaningful move
3 toward cost of service in this case. My simple question
4 is which cost of service. There is none, so the second
5 step is the one that we were talking about and that is
6 the third party. Now, whether that third party is hired
7 and managed by Idaho Power or by the Staff with monies
8 paid by the Company or by ratepayers, I don't know how
9 that's done physically, but at some point it seems to me
10 that it would behoove the Commission -- they can listen
11 to my arguments and I hope they're convinced by them, but
12 at some point they may want to say we want a third party
13 assessment independent to see if there's any resolution
14 to these issues.
15 Q I want to follow up on a couple of points
16 you touched on in a minute, but what about someone like
17 NRRI who you cite in your testimony on at least one
18 occasion, could a that's the National Regulatory
19 Research Institute -- could a firm like that provide a
20 relatively disinterested look at Idaho Power's system and
21 offer the Commission some options for a cost of service
22 study or possible cost of service study that roughly fits
23 the cost drivers on this system?
24
25
A Well, they could have. I don't know for a
fact that they could under the current way they operate.
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.1 My understanding is NRRI has left the Ohio State campus
2 and that the research arm that focused on research for
3 NARUC members has essentially headquartered in D. C. and
4 is more attuned to government issues.
5 Q Okay, I wasn't aware of that. Following
6 up with one of the themes you touched on early in your
7 testimony and that is the question of stakeholders having
8 confidence that the cost of service results reflect
9 reality or are reliable, and in that connection, do you
10 share in any respect my frustration that in considerable
11 measure the cost of service outputs are the result of an
.13
14
15
12 AURORA model which is proprietary and very expensive and
is a black box to all the rest of us, except the Staff
and the Company, does that trouble you?
A It does. Any time, No.1, any time you
16 have major inputs into a cost study that rely on what we
17 call black box inputs or outputs, you worry about it, and
18 that issue has been raised in cases here I know that I've
19 participated in and there's another issue, too, in
20 addi tion to the black box and it's what I call -- and
21 typically when you're doing a cost of service analysis
22 for any system, whether it's Idaho Power or a system in
23 Texas, Texas is bad example now since it's all
24 competitive, but if you're focusing on a state where you.25 have an integrated utility with a power supply,
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1 transmission system and distribution system, you
2 typically start -- you use a top-down approach and that
3 is you start looking at basic issues related to cost, how
4 one identifies cost, what are primary cost drivers,
5 what's happening to the system, how does this utility
6 operate, do its business.
7 It seems to me -- and then you flow that
8 down until you get to the bottom and that is who pays all
9 these costs from the ratepayer's standpoint. It seems to
10 me that Idaho Power under this methodology that's been
11 adopted has looked at it from a bottom-up approach and
12 that is we'll focus on very specific issues and we'll
13 start trying to tinker with this issue. We'll modify it
14 this year. Maybe we'll change it next year. In a future
15 case maybe we'll do ita little differently. We'll look
16 at another issue. We'll do a little something here, a
17 li ttle something there. They all may be based on what
18 you think are reasonable assumptions, but when you blend
19 them all together in this model and you start, you hit
20 the go button and you start getting results, the results
21 are just ludicrous. You get no reality and I tried to
22 identify some of those in my testimony.
23 For example, starting off with the basic
24 premise that, well, you build base load plant because you
25 get fuel substitutions, cost savings, higher capital
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19
1 costs in exchange for lower energy cost. The basic point
2 of attack then becomes well, how much of those costs do
3 we classify as demand, how much do we classify as energy.
4 You tinker with that, you put it over here in this box
5 and then you adj ust it. How do we look at this second
6 issue, for example, of energy-related costs in terms of
7 the cost of natural gas and other things increase as we
8 meet our peak loads. Well, we go to a marginal cost
9 weighting of energy, shifting that cost into the peak
10 periods. Well, how do we also think about the fact that
11 we're building plant somewhat, at least under the Idaho
12 Power approach, maybe to meet peak loads a little bit, so
13 we start marginal cost weighting those.
14 You do all of those things and they
15 produce counterintui ti ve results, sometimes illogical
16 results, and that's why I'm saying that this bottom-up
17 approach seems to me to have created a product that
18 produces results that are unreliable.
Q Following up on that, and I'm sure you've
20 heard it said the old platitude that ratemaking is an art
21 rather than a science, which always disturbs me a little,
22 but isn't it really true here that what we have in cost
23 allocation studies, cost of service studies is an inexact
24 science, but it nevertheless has to rhyme with the basic
25 scientific method; that is, we observe the facts,
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1 construct a hypothesis or theory to explain the facts and
2 if the hypothesis does not fit or produces a result
3 that's clearly absurd, then you have to rej ect it and
4 start over again?
5 A You not only have to, I mean, you would be
6 crazy not to, because ultimately if you base your prices
7 on those ludicrous results, you will destroy your system.
8 You will in fact create outcomes. It's the unintended
9 consequences that you will get. You'll have issues
10 arising in which your peak pricing is wrong, your
11 development of off peak loads is wrong, is ineffective,
12 your encouragement of people to use electricity more
13 efficiently is wrong, and so it's not just being wrong in
14 doing a computerized modeling approach, it's the results
15 and the applications that have long-term consequences and
16 continuing down this road long term will have bad
17 consequences.
18 MR. WARD: Thank you. That's all I
19 have.
20 COMMISSIONER SMITH: Mr. Richardson, do
21 you have any questions?
22 MR. RICHARDSON: I have no questions,
23 Madam Chair.
24 COMMISSIONER SMITH: Thank you.
25 Mr. Purdy.
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1 MR. PURDY: I have none.
2 COMMISSIONER SMITH: Mr. Olsen.
3 MR. OLSEN: Yes, thank you,
4 Madam Chairman.
5
6 CROSS-EXAINATION
7
8 BY MR. OLSEN:
9 Q Dr. Goins, I just want to follow up on a
10 few things. You've kind of laid some other foundation
11 wi th the responses to Mr. Conley's questions. Just to
12 make sure of this point, you did participate in the '03
13 rate case?
14 A I did.
15 Q Okay, and were you a participant in those
16 workshops in' 04 that dealt with the cost of service
17 issues that are still alive in this case right now?
A We participated in three or four telephone
19 conferences that occurred in that. . I don't think we
20 supplied any direct input into the results. There was
21 only one result that came out of that task force, as I
22 recall.
23 Q Did you provide any input in the final
24 report that the parties provided to the Commission?
25 A I can't remember. I don't remember.
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1 Q I'd like you to turn to your rebuttal
2 testimony, page 2 -- I'm sorry, page 3, and in general,
3 you've outlined the camps, I guess, of the parties that
4 have issues with the cost of service study. We have the
5 high load factor customers, along with your client
6 Department of Energy, and then we have Micron and then
7 the industrials and then the irrigation customers that
8 aren't a high load factor customer, okay, but as the
9 problem is, I guess, couched, there beginning on line 15,
10 the question you have here, you say, "How does Mr. Yankel
11 propose to" -- I'm sorry, let me go one more page overi
12 I'm sorry, page 4, line 19, that question, and you ask
13 the question, "Does IPC' s costing methodology fail to
14 assign costs properly to reflect factors driving its need
15 for new capacity? " And your answer is "Yes," so we
16 looked at the issue generally that our criticisms to the
17 cost of service methodology is that it's not sending the
18 appropriate price signals to the classes that are causing
19 those costs on the system; is that a fair statement of
20 your testimony?
21 A In general, yes. That is the result of
22 the output and the resulting revenue spread and
23 associated rates.
24 Q Okay. Nowi so we all agree on the
25 problem, it's really what the solution is and that's what
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20
21
22
23
1 you've outlined here is that there's many divergent views
2 as to the solution; is that fair?
3 A Yes.
4 Q Now, with respect to the irrigation class
5 and with respect to your cost of service studies, you've
6 come up with your preferred method and in those cost of
7 service runs, is it fair to say that the irrigators are
8 allocated a significant more portion of the costs?
9 A Yes.
10 Q Okay. Now--
11 MR. BRUDER: Excuse me, could I hear the
12 question again?
13 MR. OLSEN: Certainly. I said with
14 respect to his cost of service studies, the irrigators
15 are allocated a significant more portion of the costs in
16 this case.
17 MR. BRUDER: Relative to what?
18 MR. OLSEN: Relative to the costs or the
19 Company's base case.
MR.BRUDER:Okay,thank you.
Q BY MR.OLSEN:And you said yes?
A That's true.
Q Okay.All right.Now,Mr.Yankel has put
24 forth historical data generally showing that the
25 irrigation class as far as in terms of energy and demand
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1 has been relatively flat. Do you recall that?
2 A Yes.
3 Q Do you have any basis to disagree with his
4 analysis in that data?
5 A Oh, I totally disagree with his analysis
6 of the data. I don't disagree with the data.
7 Q Okay, you don't disagree with the data?
8 A To the extent that we may have issues with
9 whether something is normalized or not normalized, that
10 kind of thing, the fact that I will accept that energy
11 use by irrigators as a class has been relatively stable
12 over a long period of time, so has demand in general.
13 Q Okay; so based on that assumption and then
14 we apply either your cost of service methodology or the
15 Company's cost of service methodology, it shows that a
16 relatively stable class as far as growth demand
17 characteristics is getting assigned a pretty large
18 portion of the costs from the cost of service study?
19 A Yes.
Q Okay, is that a logical result given the
21 facts we just. discussed?
22
23
A Yes, it is.
Q Now, you're saying the cost of service
24 study shows that the residential customers, although they.25 recei ved an additional cost assigned to it in the study,
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1 my understanding is that the revenue related to that
2 growth more or less offsets those costs; is that fair to
3 say?
4 A I'm not sure what that means, revenue
5 related to that growth. That term or phrase has been
6 thrown out in this case and at others. It's not a term
7 that I associate with anything. I don't know the basis
8 of it or what it means.
9 Q Well, my understanding is that, you know,
10 that revenues from the additional costs and the sales of
11 energy are then imputed to certain customer classes,
12 isn't that a basic premise of the cost of service
13 methodology?
14 A Well, all revenues and all costs are
15 assigned depending on the method you pick. The question
16 you asked was whether some incremental revenue was equal
17 to essentially some incremental cost. I have no reason
18 to believe that or to -- there's no foundation from my
19 perspective of how you define it or what it means. For
20 example, in my rebuttal testimony to Mr. Hessing, I
21 addressed the same question in terms of a statement he
22 made about residential load growth or energy usage, the
23 revenue from that essentially recovering the marginal
24 cost of service and the fact that the average rate for
25 industrial customers was below that just automatically
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1 meant that the rate for industrial customers ought to go
2 way up. In my rebuttal, that's a factual error that he
3 made in his statements and I simply pointed that out, and
4 so when you talk about incremental growth, incremental
5 revenue the same problem arises.
6 Q Okay, but in general with a cost of
7 service study, revenues are assigned based on the
8 allocators that the cost of service models use?
9 A That's the basic premise.
10 Q Okay, that's the basic premise. Now, you
11 say, back to your earlier testimony, you say that the
12 resul ts for the irrigation class, although let's say
13 assume just based on the data they' re relatively stable
14 as far as customer growth and demand or energy use, but
15 we're getting assigned a large portion of the costs in
16 this case and you say that's a logical result, is that
17 based on the fact that it is a characteristic of the
18 class use of just being on peak in the summertime?
19 A Well, it's two factors: One, almost all
20 of the demand and energy consumption occurs in the summer
21 and it has a low load factor and the combination of those
22 elements means that on any average rate, any costs
23 assigned to it are going to drive that rate up quickly,
24 rapidly. Same issue could arise, for example, looking at.25 the laboratory, the DOE lab's costs. In the last five
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1 years or six years, the loads there have been relatively
2 stable and yet, the costs being assigned to it are
3 enormous in terms of the growth and the progressive cost
4 of service studies filed by Idaho Power.
5 Now, under the logic that you're putting
6 forth here, is that reasonable? Counterintui ti ve? It's
7 simply a result of the application in my opinion of a
8 flawed, I call ita fatally flawed, cost of service study
9 and I've highlighted ad nauseam some of the problems with
10 that and how at least as a Band-aid approach you address
11 them.
12 Q Well, I don't want to belabor the point,
13 but we just have different results by how you approach
14 the problem; isn't that a fair assumption?
15 A Well, if you told me the result you
16 wanted, I could develop a method that would achieve that.
17 For example, if you said we want to load essentially 100
18 percent of any cost increase on to customer classes with
19 load factors in excess of 70 percent, we could come up
20 fairly quickly with a method that would do it. On the
21 other side, if you wanted to shift all of those costs to
22 customer classes with load factors below 30 percent, we
23 could do that. Would they be correct? Reasonable?
24 Prudent? No.
25 The point that we're getting at here is
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1 not whether everybody's opinion is equal, everybody's
2 opinion is not equal. We're trying to link in some
3 meaningful fashion Idaho Power's incurrence of cost to
4 the underlying cost drivers and then trying to link those
5 cost drivers to usage by customer classes, and to the
6 extent you can do that in a reasonable, transparent and
7 straightforward manner, you will produce an outcome that
8 at least people can agree is fair and balanced, but in
9 terms of, again, this bottom-up approach in which we look
10 at this issue, this issue and this issue and we tinker,
11 we tinker, we tinker and we think we're coming up with a
12 reasonable ap~roach, what happens is that the combination
13 of all of those tinkerings has created a methodology
14 which has no relationship to reality in terms of the cost
15 and the cost drivers on Idaho Power's system.
16 Q Okay, and that's precisely one of my
17 points and hopefully, I can get this across with this
18 question. The cost of service study more or less takes a
19 sample for demand and energy use at a given point in
20 time; is that correct?
21
22
A For a test year.
Q For a test year, so this year was a 2007
23 test year; correct?
24
25
A 2008.
Q Well, and forecast for 2008 allocation.
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1 A Correct, forecast.
2 Q Now, looking at all of the class
3 characteristics that make up that test year data, it
4 looks at it on a static basis, does it not?
5 A Yes. Any state that has embedded cost
6 ratemaking uses a historical or uses a test year to
7 account for those normalized proformed accounting
8 costs.
9 Q Doesn't that embedded cost accounting just
10 assume that everybody -- if there's growth on the system,
11 it doesn't distinguish between who's growing and who's
12 not growing; is that correct?
13 A No. It captures what's happened since the
14 last historical measurement that was taken. In this
15 case, for example, in the last rate case, in the '05 or
16 the' 03 situations, it does in fact progressively look
17 at, if you wanted to do the comparisons, you could and
18 see
19 Q But my question was it does not look at
20 how you got there, it just takes a snapshot in time;
21 correct?
22 A No cost study, no embedded cost study, can
23 look at how you got there. It simply looks at the facts,
24 at the data that exists at a point in time. There are.25 elements of how you got there embodied in part, for
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1 example, in using a forecast test year. Certainly to the
2 extent that those loads that were included in the
3 forecast test year are different than the historical 2007
4 loads, that in fact addresses a little bit of how you got
5 there at least from year to year.
18
19
6
7 Madam Chair?
8
9
10
11 Chairman.
12
13
14
15 Walker.
16
17
20 BY MR. WALKER:
21 Q
MR. OLSEN: May I just have a moment,
COMMISSIONER SMITH: Certainly.
(Pause in proceedings.)
MR. OLSEN: No further questions, Madam
COMMISSIONER SMITH: Mr. Price.
MR. PRICE: No questions.
COMMISSIONER SMITH: Thank you. Mr.
MR. WALKER: Thank you.
CROSS-EXAMINATION
Now, the Company's recommended cost of
22 service is called a 3CP /12CP; is that correct? That's
23 the title that's been given to it?
24
25
A
3CP/12CP.
Yes, Mr. Tatum designated it as
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1 Q And we're just talking generally speaking
2 here, the 3CP portion of that, doesn't that 3CP stand for
3 a cost allocation that would actually favor a high load
4 factor customer in that allocation?
5 A If it were done correctly, yes.
6 Q Generally speaking, that's what that's
7 getting at?
8 A Again, this is the problem I'm talking
9 about and from the top-down, the idea seems not only
10 plausible but commendable, that contributions to drivers
11 in the system peak, the 3CP, should reflect that, but
12 from the bottom-up, how you get there, is the problem
13 and, for example, just starting out with the
14 classification of cost, the averaging of the assignment
15 of the cost, the failure of the cost to link up, the
16 assignment of production or purchases and sales revenues,
17 all of those things go into muting and essentially
18 eliminating any what I would call good benefits of using
19 the 3CP approach.
20 Q And I believe you testified here today
21 that you participated in a workshop following the '03
22 case that discussed a lot of these issues; is that
23 correct?
24 A Yes, I was listening on at least three or
25 four telephone conferences that occurred.
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1 Q And, generally speaking, it was these same
2 parties in the discussion, do you recall?
3 A The names and faces were essentially the
4 same.
5 Q And you said that you listened in, but you
6 didn't really give input. That's not because you were
7 precluded somehow from giving whatever input you wanted
8 into that process?
9 A No. What happened was it became very
10 apparent at the beginning that the task force was going
11 nowhere. The stakeholders were essentially fixed in
12 posi tions. The irrigators were raising this issue of
13 growth and how it was reflected. I remember Mr. Yankel
14 gave a PowerPoint in which he mailed to all the telephone
15 participants, a Power Point presentation addressing the
16 normalization of loads, the issue of talking about how
17 reflecti ve of growth. The industrials were talking about
18 the cost drivers and how those were reflected and the
19 Company listened.
20 Q Well, and there was actually a final
21 document generated from that process and filed with the
22 Commission, were you aware of that?
23 A It was a document that essentially said
24 the task force has reached no resolution on major issues.25 except, I think, one. I think that's what Mr. Tatum
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18
19
1 testifies to, I think it's Mr. Tatum, and that was the
2 normalization of loads.
3 Q So it did have a few things that were
4 consensus items that everyone agreed, you know, when the
5 Company goes in for a rate case and files its cost of
6 service, it would contain some things that everybody
7 agreed it would contain?
8 A There was agreement on what I would term
9 one small minor issue.
10 MR. WALKER: Okay. I don't have any more
11 questions.
12 COMMISSIONER SMITH: Thank you,
13 Mr. Walker. Do any of the Commissioners have questions?
14 Commissioners Redford, do you have
15 questions?
16 COMMISSIONER REDFORD: I have none.
EXAMINATION
20 BY COMMISSIONER SMITH:
21 Q I just have one sort of, because it's
22 apparent to me that you work in this field regularly.
23
24
25
A Yes.
Q You've done it a long time.
A Unfortunately. No, I shouldn't say that.
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1 I like what I do.
2 Q And so from sitting in my chair, it's
3 pretty discouraging to see the lack of progress or
4 apparent lack of progress over the years from case to
5 case and I understand the theory that you're trying to
6 link these cost drivers and eventually the right customer
7 classes get to pay the right costs because they're
8 essentially the drivers, but when I look at -- I mean,
9 you don't work for free; right?
10 A I don't. I try not to.
11 Q I think the other expert witnesses out
12 here, they don't work for free either, so I look at the
13 enormous amount of time and money that gets spent in this
14 exercise and have you ever done telephone work?
15 A Yes.
Q I mean
A Not regularly,but I have.
Q There's a real abyss you can fall into
talking about cost studies and cost allocation,so I
16
17
18
19
20 guess the idea that just kind of swirls around in my mind
21 that if the goal, the ultimate goal, is something that
22 everyone recognizes as being fair and equitable, well,
23 that's what commissions do.
24.25
A That's true.
Q So maybe we should just scrap all this and
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.1 the Commission could look at the classes and the totality
2 of the circumstances and just pick a number.
3 A Well, you can do what the law allows you,
4 I'm sure, but as I said before, you've got -- the parties
5 that are before you, you have at least five or six
6 different opinions, most of which have been expressed
7 fairly well on how one should go about this process, and
8 you have two parties in particular, the Company and the
9 Staff, aligning with a methodology that's opposed by some
10 fairly large-sized customer groups and I tried to layout
11 both theoretically and empirically what happens and why
12 it should happen in terms of allocating costs. I can.13
14
tell you, I've testified in a lot of states, the approach
the Company uses is not a recognized method. I said that
15 in the '05 case, I'll say it today even more, it is not a
16 recogni zed method.
17 The bottom line, we did some more in-depth
18 analysis even after I filed my rebuttal in looking, for
19 example, at how much of the Company's fixed production
20 cost, we're talking steam and hydro plant and combustion
21 turbines, is allocated either explicitly or implicitly on
22 an energy basis. It's almost 80 percent, 80 percent in a
23 system that is capacity constrained, not energy
24 constrained, whose additions of capacity and high cost.25 purchases are not being driven by year-round demands,
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1 whose classification of these fixed costs right off the
2 bat says almost 60 percent of those fixed costs are
3 variable, and then when it combines those variable costs,
4 the 60 percent allocation of these fixed costs on energy
5 and then winds up with using a 12CP scheme to allocate
6 the other 40 percent essentially of hydro and steam
7 production costs, wi thin that 12CP is an average demand.
8 The percentage of average demand on the
9 12CP' s, if we treat that as an implicit energy allocator,
10 which in fact it is, I can state unequivocally that it
11 is, you combine that, the result is almost 80 percent of
12 Idaho Power's fixed production plant costs allocated on
13 the basis of energy. That is unheard of in the United
14 States.
15 I don't know of another utility that even
16 comes close. That in and of itself, if you simply look
17 at the results, tells you that something is wrong, in
18 particular the system that tells you that it's trying
19 you know, its requirements for money are being driven by
20 demands for peak loads with a deterioration and decline
21 of its system load factor with a push toward demand side
22 management programs and energy efficiency, all of which
23 are contradicted by the results of this study. For
24 example, under the Company's classification scheme, if in.25 fact the irrigation program is successful and the
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1 irrigators' load on peak goes down but its energy usage
2 doesn't change, the system load factor will in fact go
3 up. DOE will get a huge chunk of cost, additional cost,
4 allocated to it simply because the load factor
5 classification changed. DOE did nothing.
6 Now, that not only is counterintui ti ve,
7 it's bad business. Similarly, if you have a situation in
8 which you are encouraging energy conservation of street
9 lights and you were successful, you would have a
10 situation in which the system load factor would decline,
11 assuming everything else equal, because energy usage
12 would come down, but the street lighting class is off
13 peak anyway, so the only thing you have is reduction in
14 energy use, not peak demand, the system load factor goes
15 down, DOE benefits, residentials or other lower load
16 factors, small commercial, pay through the nose. That's
17 not right, it's not reasonable, it's counterintuitive,
18 so, as I said, every proposal here is not equal. Some of
19 the things are just plain wrong. I've tried to lay them
20 out, so has Dr. Peseau, so has Dr. Reading and, again, we
21 have been rebutted.
22 Q So you don't like my idea, though, either
23 because essentially that would put you out of business?
.24
25
A You would put a lot of people out of
business on the paying side.
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1 COMMISSIONER SMITH: Well, maybe that will
2 be my contribution to the current economic crisis is
3 continued employment for economists.
4 THE WITNESS: You don't want to do that.
5 COMMISSIONER SMITH: Mr. Bruder, do you
6 have any redirect?
7 MR. BRUDER: May I have a moment to confer
8 with the witness?
9 COMMISSIONER SMITH: I'm usually not
10 allowing that, but if you need it, I'll suffer through
11 it.
12 MR. BRUDER: I will not make you suffer,
13 Madam Commissioner.
14 COMMISSIONER SMITH: Thank you, so does
15 that mean you have none?
16 MR. BRUDER: I have very limited.
17
18 REDIRECT EXAMINATION
20 BY MR. BRUDER;
21 Q Dr. Goins, the Chairman has asked quite
22 rightly aren't all the experts not unbiased and because
23 they're not unbiased, how can we ever get a fair
24 methodology. Could one valid response to that be to
25 engage in an outside unbiased entity to develop such a
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1 fair methodology?
2 A It could. The other less expensive option
3 would simply be to listen to what I've proposed and agree
4 wi th that, but it is, I mean, it is one approach, but
5 what we have here is a real fundamental problem, because
6 if this process continues, you're going to have high load
7 factor customers being encouraged to do things that you
8 don't want them to do and there are unintended
9 consequences. When you base prices on wrong cost
10 allocations and assign those, you get bad price signals.
11 I don't care how great your rate design is, you can
12 tinker with it until you can't stand it anymore, it's
13 still going to be wrong.
14 Q And last, I think you spoke at some length
15 about top-down and bottom-up approaches. Now, when we
16 look at the 3CP /12CP methodology, does that involve
17 something that's referred to as BIP?
18 A Yes, Mr. Tatum explains that he's
19 essentially tried to assign his steam and hydro plant and
20 combustion turbine plant and also power purchases, the
21 demand-related components of those, into a category
22 called base load, intermediate or peaking, but he doesn't
23 have an intermediate component. He lumps those two
24 together and essentially winds up assigning base load and
25 hydro plant to the base load category and combustion
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1 turbines to the peaking category.
2 He says that's recognized in the NARUC
3 manual. Yes, there are two pages in the NARUC '92 manual
4 that address it. In the 1973 manual, it's not addressed
5 at all. The reason is is that it wasn't even developed
6 until the late '7 Os. It came about as a result of the
7 EPRI, NARUC sponsored cost of service and rate design
8 groups that were formed and the BIP method I can tell you
9 then was rej ected by all the hundreds of participants in
10 that study, and that it was then regenerated in the early
11 '80s, primarily as a way to deal by consumer advocate
12 groups with the high cost of nuclear power plants. In
13 essence, the result was those groups were getting hit
14 tremendously with the high cost of nuclear power plants
15 that were com~ng into rate base and they hired people who
16 found methods to shift costs away from them. BIP was one
17 of those.
18 Q Is BIP in use anywhere in the nation now
19 as far as you know?
20 A No, it's not. Well, I shouldn't say that.
21 Arkansas has a method that kind of mimics it. No one, to
22 my knowledge, has a straight BIP method. Even the method
23 that Idaho Power calls a BIP is strictly speaking not a
24 BIP method because, again, the costs are assigned to time
25 periods in the BIP method. Idaho Power has assigned
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1 costs to cost categories, base load and peaking, and
2 there is no we asked questions in discovery in terms
3 of matching up those costs and all the other things to
4 see if in fact there was any empirical basis for
5 determining to assign this type of plant or this amount
6 of cost to this particular category. There was none. No
7 in-depth, empirical analysis had been done, so it was
8 just an arbitrary assignment.
9 We in fact have done analyses, for
10 example, that clearly demonstrate that hydro capacity has
11 a strongly peaking influence. In fact, we did a simple
12 correlation of the operation by hour of Idaho Power's
13 plants and looking at its purchases as well to load. The
14 simple correlation showed, for example, that hydro plant
15 is significantly correlated to loads and what does that
16 mean? That means that it's used in large part to help
17 meet peak load as well as serving as a base load
18 resource. Idaho Power's methodology assigns zero of
19 those costs to the peaking period. That simple
20 assignment in the BIP method is empirically,
21 demonstratively wrong.
22 MR. BRUDER: I have nothing further.
23 Thank you very much.
24
25
COMMISSIONER SMITH: But Commissioner
Redford does.
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1 EXAMINATION
2
3 BY COMMISSIONER REDFORD:
4 Q So I guess what I want to ask you is maybe
5 since you're stating that the -- oh, thank you -- you're
6 stating that the cost of service study and analysis are
7 wrong for the purpose of allocating costs to the various
8 classes of service, each and every class has under your
9 posi tion an improper or erroneous classification,
10 allocation?
11 A Under the studies presented by Idaho Power
12 and the Staff and the revenue spreads that are based on
13 the cost assignments resulting from those studies, the
14 answer is yes.
15 Q This case has been going on for some time
16 and probably apologize that we didn't read your direct
17 and rebuttal testimony early on, but we're right in the
18 middle of a case, what would you suggest in the event the
19 Commission decides to accept your position that we do
20 empower a third party to look at it from an independent
21 basis and then after that basis is established, then we
22 look at cost allocation?
23
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A Well, No.1, I said that after identifying
a lot of flaws and deficiencies, I made I fixed this
problem and that problem and that problem, okay, and the
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1 resul t indicates significantly different cost assignments
2 and I said simply as interim measure an across-the-board
3 spread of the revenue requirement in this case would be
4 reasonable, in particular if you adopted something on the
5 order of Staff's three, I think three, percent increase
6 or something like that because there's no clear
7 indication from the Company's studies nor the one
8 recommended by the Staff in terms of what that cost
9 assignment, actual cost assignment, should be.
10 If you wanted to adopt the approach, if
11 you agreed with me on the problems I've cited in my
12 direct and rebuttal and you agreed with the approaches
13 that I have used to fix those problems, then what I
14 recommended is that you adopt a revenue spread that
15 reflected those cost results and what those cost
16 results -- and you could see who gets a higher than
17 average increase, who gets a lower increase. I didn't
18 recommend a specific increase in that, but I said that if
19 you don't want to do that, if you just want to go, say,
20 okay, from this case we're going to hire somebody from
21 the outside to look at this, go with an across the board,
22 hire somebody from the outside, but if you don't want to
23 do that, then I would say take the results from my study
24 and shape whatever revenue spread you choose for each
25 class to reflect in your best judgment what a fair
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1 assignment of those costs and the associated rate
2 increases would be, and what that would indicate is
3 certainly nothing even close to the results that you get
4 from the revenue spreads that the Company has proposed in
5 this case.
6 Q Thank you. When you do a cost of service
7 study, the allocations to all the classes of customers
8 should equal 100 percent?
9 A On a jurisdictional basis, yes.
10 Q Is there ever a case where a class of
11 customers are' -- where there's a cost of service study
12 simply just on one class?
13 A Well, there are studies in which you
14 treat -- the answer is yes. I've seen it, for example,
15 in certain special contracts that I've participated in,
16 but in those and not for DOE, but in those studies,
17 for example, in the jurisdictional cost of service study,
18 the individual customer is treated as an identifiable
19 separate class. The same can hold, you could take any
20 class you have today, you could split it in five
21 different ways if you wanted to. You could develop
22 factors for all of those subgroups and you could in fact
23 develop cost allocations for those.
24 I think the Chair raised an issue about.25 the irrigation class and splitting it into groups in a
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1 question earlier this morning. That could be done in a
2 cost of service study, for example, to see what the
3 resul ts are if you do it.
4 Q We've had hearings throughout the state or
5 the southern portion of the state that Idaho Power serves
6 and we have a lot of irrigators that have stated that
7 growth in this industry hasn't changed much in the last
8 15 years and yet, Idaho Power wants to allocate to them
9 15 percent of the rate increase. Are they justified in
10 questioning this?
11 A Well, no. As I said in my rebuttal
12 testimony to Mr. Yankel, if the irrigators want to avoid
13 essentially a lot of these rate increases, they need to
14 shift as much of their load off peak as possible. I
15 mean, if you're advising someone what to do, you say
16 whatever it takes, you know, run your pumps at night to
17 irrigate your crops if that can be done. It's a big
18 issue, but until that's done, you can read the study
19 anyway you want to, it's not going to
20 Q Idaho Power has a Peak Rewards system
21 whereby the a~riculture, the farmers turn off the power
22 and, of course, I believe there's another study that's
23 proposing that automatic metering would, that there's a
24 system by which the Company would shut the power off
25 during these peak periods, but nevertheless, Idaho Power
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1 still assigns a high rate to the irrigators.
2 A Well, that only results -- well, I
3 shouldn't say it only results. It results in large part
4 simply from the fact that a large percentage of the
5 demand for the irrigators remains on peak and is measured
6 and included in these calculations and the load factor
7 for the class continues to remain fairly low. Until
8 those things change, until the peak demand decreases and
9 the load factor goes up, you'll see significant
10 increases, and I address this issue of what I call
11 vintage pricing, entitlements to. If you're not growing,
12 you're entitled to your old rate. It's a problem that's
13 been around and addressed by lots more people than me on
14 this and by regulatory commissions as well.
15 The problem you get into is pricing
16 discrimination, that if somebody is being assigned costs
17 based on contributions to peak usage, for example, and is
18 not charged whatever the price is for that product that's
19 been sold to them and another person who simply moved
20 into the state who does the same thing suddenly gets
21 charged for that or has a similar load on peak and
22 they're charged this marginal or incremental cost, under
23 most regulatory regimes that's pricing discrimination and
24 under the law it's illegal, so it's a serious problem.
25 It's not just an academic issue. It's a serious business
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problem.
COMMISSIONER REDFORD:Thank you very
much,Doctor.I appreciate your testimony.
THE WITNESS:You're quite welcome.
COMMISSIONER SMITH:Commissioner
Kempton.
COMMISSIONER KEMPTON:Thank you,
3
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8 Madam Chairman.
9
10 EXAINATION
11
12 BY COMMISSIONER KEMPTON:
13 Q Dr. Goins, if the Commission were to
14 follow the guidance that you give to us in both your
15 direct and -- well, in your direct and rebuttal to the
16 extent that you've been rebutting, would you consider the
17 change from the rate structure that now exists to one
18 that's going to transfer to the residential class
19 dramatic?
20
21
A I didn't catch that last word.
Q Dramatic, would you consider that
22 adj ustment dramatic to the residential class?
23 A No, actually, under the cost study that I
24 recommended, residential has a below average increase, I.25 believe, and the reason is in large part that if you look
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1 at the residential's load as a class in the month of
2 December relative to the month of July when the system
3 peaks, there may be a 10 percent change differential or
4 something like that. If you look at some other classes,
5 small commercial, for example, irrigators, that
6 differential is dramatic. In the case of small
7 commercial, for example, it's over 50 percent.
8 Irrigators, it's a lot more than that, and so you do get
9 in fact increases for those groups that are significant
10 and have to be mitigated. I mean, they have to be
11 mitigated.
12 Under the cost study that I did and
13 recommended in this case, irrigators were shown, I think,
14 with -- this is in Exhibit 610 -- something like a 60
15 percent increase. I'm not recommending a 60 percent
16 increase for the irrigators, and as I said, you use the
17 study with common sense and reasonable judgment, the
18 results from it, to set rates and in particular, if
19 you're looking at relatively small increases, that job
20 becomes easier.
21 In fact, it's -- I'll put it this way: If
22 you were going to, for example, agree to the Staff's
23 revenue requirement, and I'm not into the revenue
24 requirements phase and issues in this case other than
25 knowing in general what the increase is and it's
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1 relatively low, now is a good time to make changes in the
2 cost analysis to better reflect how Idaho Power operates
3 and how costs are being driven, and the reason is the
4 overall increase is relatively low and the increases for
5 any class can be mitigated. They can be held to a
6 reasonable level and it's much easier to do that when
7 you've got a small increase than if somebody is coming in
8 asking for 10,15,20 and that's what you're going to
9 give them. That's when it really becomes problematic of
10 making what I would call a bold move, but in this case,
11 it is clear that there are so many things wrong with the
12 Company's study that some dramatic changes have to be
13 made and should be made and if you're going to make those
14 changes and do them in a reasonable and prudent way, this
15 is an ideal spot to do it, I'm assuming, if the increase
16 is going to be something on the order of what Staff
17 proposed.
18 Q And if it is on the line of something that
19 Idaho Power proposed in terms of revenue collection?
20 A You would have to look at the -- as I
21 said, my results, my analyses were based on Idaho Power's
22 proposed revenue and that's where the 60 percent, for
23 example, came out for irrigation in my Exhibit 610, at
24 that level, and as I said just a moment ago, you have to
25 do something to mitigate that. You have to keep it at
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1 some reasonable level. Does it justify an above average
2 increase if you're looking at three percent? Yes.
3 Should it be 20? No, but that's where the job -- that's
4 a normative question and that's where your job comes in
5 in terms of making reasonable and prudent and practical
6 judgments based on the evidence.
7 This cost of service study is one input
8 that you have. It's not the be-all and end-all, believe
9 me. I believe in the studies that we proposed and the
10 posi tions I've taken, I truly do, but I wouldn't stake my
11 life on the results of them being 100 percent accurate
12 and anybody else in this room that's done one of these
13 studies at any point wouldn't do it either. This is a
14 guide. It should be a key component for you, but anybody
15 in the ratemaking business knows that it's a guide. I
16 believe it should be given -- you know, it should be a
17 key component in your decision, but it can't be the only
18 component.
19 Q We've talked in the recent past, I think
20 you've been in here, about the educational process for
21 the various consumers and if we move forward on this in
22 one fell swoop, we'll probably hear a lot of customers,
23 the voices of a lot of customers, back through their
24 voting representation with the various legislators that
25 we have and that would be typical in any state. It's not
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1 unusual for any state to be -- any legislative body to be
2 responsi ve to a massive amount of complaints from their
3 consumers, so in following guidance that you have
4 presented here today, would that process be best defined
5 at this point as a transitional process during which time
6 Idaho Power would begin to develop an educational process
7 for the customers to make them aware of where they are
8 going in the near future? I would suggest that if you do
9 it all at once, you better clear the decks because that
10 rate case is probably going to be short lived as well as
11 the Commissioners who made it.
12 A Well, it depends on what's in your
13 educational program. If you're talking about trying to
14 explain to the general public the concepts of cost of
15 service, it's a losing battle. It simply will not
16 happen. You can design the greatest program in the
17 world, but the typical user is totally uninterested. The
18 only thing the typical user is interested in is what does
19 my bill say. The aggressive user is going to be looking
20 at the details of the bill. Some will respond to bill
21 inserts or public forums or something like that that
22 indicates what the pricing is and they should be provided
23 that, but in terms of making everybody a rate expert,
24 it's very difficult.
25 Being able to send real-time signals to
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1 customers, you know, with a light going off in your
2 ki tchen or in your garage or somewhere telling you the
3 price of electricity is now $.20 a kilowatt-hour, that
4 gets your attention. In educational terms, that is a lot
5 more informative to customers than a bill insert, so I
6 wouldn't let that issue stop me from making fundamental
7 changes in the way that costs are determined because
8 remember, the cost of service study is one component. It
9 gi ves you a guide and the problem I have is if that guide
10 is wrong, it makes you make bad decisions.
11 Q My point is that I think in the future
12 that Idaho Power and the other utili ties as well,
13 probably, are' going to file rate cases in much closer
14 proximi ty than they have in the past. It gives you a
15 chance, perhaps, to do a modified change and
16 progressively move to something else, at the same time
17 not educate the public so much as educate the
18 legislature.
19
20
A Yes.
Q Committees understand the process. The
21 energy committee here, while they certainly may not have
22 the technical capability to understand a cost of service
23 study, can understand the implications of that when it's
24 read by technical staff, so once again, it's a question
25 of whether recognizing your position and assuming that
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1 position valid, would you articulate a process that is
2 incremental or would you simply say do it all at once and
3 let the chips fall where they may? The Commission is
4 capable of doing either one of those and we have no
5 compunctions about making hard decisions. The question
6 is just the advisability and the smoothest way of
7 entering something this complex and this big.
8 A Well, again, if I were doing it and given
9 the circumstances as they exist and assuming that
10 something on the order of Staff's revenue requirement is
11 approved, I would go ahead and make the changes. I would
12 then move not only with legislative leaders but also with
13 the Company that the Company has to be aggressive in
14 thinking about ways to control cost, to the reliance on
15 markets for power, total reliance in terms of building
16 nothing but CTs and routing the market, to believe that's
17 the way you're going to grow yourself in the future seems
18 to me very problematic and I say that not really caring
19 what the IRP says is the least cost unit or whatever.
20 There's some practical aspects.
21 In my opinion, Idaho Power is engaged in a
22 high risk strategy in terms of power supply positions, so
23 I would be working with the Company in terms of thinking
24 about that outside the context of a rate case and
25 whatever can be done to provide reasonable price signals
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1 to customers that Idaho Power has gone from being an
2 energy constrained system to a capacity constrained
3 system and that we can't continue to add more and more
4 expensi ve production resources to meet these peak demands
5 and see a general decline in our system load factor and
6 then have cost allocation methods that produce assignment
7 of those costs that are totally reversed, that wind up
8 assigning costs to low growth customers or to high load
9 factor customers whose loads are steady and those kinds
10 of things and. until you address this issue of peak demand
11 and get customers to respond to those price signals, it's
12 a difficult situation, but I would take a two-prong
13 approach or three prongs, actually, so given the premise
14 that I laid out, if the revenue requirement is a
15 reasonable increase, I would make the move in terms of
16 fixing obvious faults and deficiencies in the Company's
17 cost of service methodology.
18 I would work with my legislative leaders
19 to get them to get involved in this issue of how Idaho
20 Power has changed from the '80s, the early '80s, an
21 abundant hydro to a system now in which hydro is used so
22 much to follow and shape load and which is totally
23 different than you thought about 20 years ago with hydro
24 as a base load resource only, and then I'd be working
25 wi th Idaho Power to address this issue of what is the
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1 best way that we can acquire power supply resources to
2 meet the growth in Idaho and to serve the existing loads
3 fairly and reasonably and reliably. It's not just a
4 one-issue or one-step problem. This goes broader than
5 that, I think.
6 Q Okay, one last question, then, and perhaps
7 a short response. The question won't beg a short
8 response, but it probably perhaps would be better if it
9 were.
10 A I take the hint.
11 Q And that is how do you think this kind of
12 a process would affect the credit rating of Idaho Power
13 which is currently a triple B?
14 A I'm not a financial analyst, so I can't
15 say as an expert. As a lay person, I think until Idaho
16 Pow€r rights its pricing schemes, if those pricing
17 schemes are based on wrong cost developments and
18 assignments and implementation practices, over time the
19 quality of the Company will deteriorate. The better its
20 pricing scheme is, the more realistic it is in terms of
21 tracking costT the better Idaho Power will be in
22 recovering its cost, the better consumers will be in
23 making the consumption and investment decisions they make
24 on a daily basis and the overall quality in terms of
25 financials, I would assume, would certainly not
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1 deteriorate and would likely, you know, I wouldn't say it
2 would be a key component, but it certainly would be a
3 factor, and two things would happen here: One would be,
4 while I'm not a financial expert, I'm generally familiar
5 wi th some of these things, the outside reviewers who are
6 looking at what's the regulatory climate here would in
7 fact see that the regulatory climate in Idaho recognizes
8 problems that. exist and is taking steps to address them.
9 That is a favorable rating factor that goes into the
10 determination of Idaho Power's capital costs.
11 COMMISSIONER KEMPTON: No further
12 questions.
13 THE WITNESS: I hope that was brief
14 enough.
15 COMMISSIONER SMITH: I think for you,
16 perhaps. So relative, isn't it? Okay.
17 THE WITNESS: I get the point.
18 COMMISSIONER SMITH: Mr. Bruder, I assume
19 you have no more redirect.
21 Madam Chairman.
MR. BRUDER: You're correct,
22
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25
COMMISSIONER SMITH: Thank you.
(The witness left the stand.)
COMMISSIONER SMITH: Okay, we've almost
eaten up the lunch hour, so shall we just keep going?
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