20090108Vol VII [technical hearing] pgs 1024-1620.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, Idao
BEFORE
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER JIM D. KEMPTON.
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:December 17, 2008
VOLUME VII - Pages 1024 - 1620
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CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone] * [phone]
Email csb~eritagewifi.com
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1 APPEARANCES
2 For the Staff:
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5 For Idaho Power Company:
Neil Price, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83720-0074
Barton L. Kline, Esq.
and Lisa D. Nordstrom, Esq.
and Donovan E. Walker, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
RICHARDSON & 0' LEARY
by Peter J. Richardson, Esq.
Post Office Box 7218
Boise, Idaho 83702
RACINE, OLSEN, NYE, BUDGE
& BAILEY
by Eric L. Olsen, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
Arthur Perry Bruder, Esq.
Assistant General Counsel
U. S. Department of Energy
1000 Independence Ave., SW
Washington, DC 20585
GIVENS PURSLEY LLP
by Conley E. Ward, Esq.
Post Office Box 2720
Boise, Idaho 83701-2720
BOEHM, KURTZ & LOWRY
by Kurt J. Boehm, Esq.
36 E. Seventh Street
Suite 1510
Cincinnati, Ohio 45202
-and-
FISHER PUSCH & ALDERMAN LLPby John R. Hamond, Jr., Esq.
Post Office Box 1308
Boise, Idaho 83701
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For Industrial Customers
of Idaho Power:
For Idaho Irrigation
Pumpers Association:
For The United States
Department of Energy:
For Micron Technology,
Inc. :
For The Kroger Company:
(Of Record)
(Of Record)
CSB REPORTING
[phone]
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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5 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 Sidney F.Erwin Mr.Olsen (Direct)1024(Irrigators)Prefiled Direct Testimony 1026
5 Mr.Ward (Cross)1036
Mr.Walker (Cross)1038
6 Mr.Olsen (Redirect)1040
7 Anthony J.Yankel Mr.Olsen (Direct)1043(Irrigators)Prefiled Direct Testimony 1046
8 Prefiled Rebuttal Testimony 1128
Mr.Richardson (Cross)1151
9 Mr.Bruder (Cross)1153
Mr.Walker (Cross)1160
10 Mr.Olsen (Redirect)1163
11 Rick Sterling Mr.Price (Direct)1165
(Staff)Prefiled Direct Testimony 1167
12 Mr.Kline (Cross)1184
Mr.Price (Redirect)1196.13
Lynn Anderson.Mr.Price ( Direct)1198
14 (Staff)Prefiled Direct Testimony 1200
Mr.Kline (Cross)1220
15 Commissioner Kempton 1231
Mr.Price (Redirect)1236
16
John Nobbs Mr.Price (Direct)1238
17 (Staff)Prefiled Direct Testimony 1240
Mr.Ward (Cross)1254
18
Joe Leckie Mr.Price ( Direct)1256
19 (Staff)Prefiled Direct Testimony 1259
Mr.Kline (Cross)1287
20 Mr.Price (Redirect)1293
21 Cecily Vaughn Mr.Price ( Direct)1294
(Staff)Prefiled Direct Testimony 1296
22 Ms.Nordstrom (Cross)1338
Commissioner Kempton 1353
23 Mr.Price (Redirect)1355
24.25
CSB REPORTING INDEX
(208 )890-5198
.1 I N D E X (Continued)
2
3 WITNESS EXAMINATION BY PAGE
4 Kei th Hessing Mr.Price (Direct)1357
(Staff)Prefiled Direct Testimony 1360
5 Prefiled Rebuttal Testimony 1379
Mr.Richardson (Cross)1407
6 Mr.Olsen (Cross)1410
Mr.Ward (Cross)1417
7 Mr.Walker (Cross)1436
8 Bryan Lanspery Mr.Price (Direct)1447
(Staff)Prefiled Direct Testimony 1450
9 Mr.Richardson (Cross)1480
Mr.Walker (Cross)1482
10 Commissioner Kempton 1487
Mr.Price (Redirect)1489
11
Matthew Elam Mr.Price (Direct)1491
12 (Staff)Prefiled Direct Testimony 1495
Mr.Richardson (Cross)1512.13
Curtis Thaden Mr.Price (Direct)1518
14 (Staff)Prefiled Direct Testimony 1521
Mr.Purdy (Cross)1552
15
Marilyn Parker Mr.Price (Direct)1555
16 (Staff)Pre filed Direct Testimony 1557
17 Randy Lobb Mr.Price (Direct)1574
(Staff)Prefiled Direct Testimony 1576
18 Mr.Richardson (Cross)1604
Mr.Ward (Cross)1613
19 Mr.Kline (Cross)1617
Mr.Price (Redirect)1619
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CSB REPORTING INDEX
(208 )890-5198
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1 EXHIBITS
PAGE
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2
3 NUMBER DESCRIPTION
4 FOR THE STAFF:
5 101 - Idaho Power Gas Price Forecast
6 102 - Correlations Between Monthly
Northwest Water Conditions &
Gas Prices at Sumas7
8 103 - Henry Hub Gas Forwards
9 104 - Net Power Supply Cost Adjustments
by Account
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105 - 2008 Normalized Net Power Supply
Costs
12 106 - Summary Comparison of Net Power
Supply Costs
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107 - Summary of AURORA Results
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108 - Audit Adjustments Account 920.350
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109 - Audit Adjustments Account 923
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110 - Audit Adjustments Account 928.101
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111 - Audit Adj ustments Account 930.200
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112 - Summary. of Audit Adj ustments
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113 - Adjustment for Miscellaneous
Service Revenue, Account 451
114 - Account 451 - Miscellaneous
Service Income
115 - Straight-Time Payroll (DCE 111)
116 - Adjustment to 2007 Payroll &
Incentive Operating Expenses
CSB REPORTING
Wilder, Idaho. 83676
EXHIBITS
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1 E X H I BIT S (Continued)
2
3 NUMBER DESCRIPTION PAGE
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4 FOR THE STAFF:
5 117 - Idaho Power Company Depreciation
Expense
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118 - Adjustment for Attorney Fees for
Stock Plans
8 119 - Idaho Power Calculation of CAGR
Summary
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120 - Compound Annual Growth Rate
Formula & Example Calculation
11 121 - Staff Analysis of Growth Rates by
Account Group & Cost Element
Consolidated Summary Data12
13 122 - Staff Calculation of 2007 0
Escalation to 2008 Test Year
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123 - Financing Costs Related to Hells
Canyon Relicensing
16 124 - Calculation of Financing Costs
Related to Hells CanyonRelicensing17
18 125 - P-Card Adjustments
19 126 - Summary of Revenue Requirement
127 - Summary of Adjustments
129 - Comparison of Historic
Jurisdictional Allocators
130 - Revenue Allocation Summary,
3CP /12Cp. Cost-of-Service Results
131 - Revenue Allocation Summary, 12
Months Ending 12/31/08
CSB REPORTING
Wilder, Idaho. 83676
EXHIBITS
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1 E X H I BIT S (Continued)
2
3 NUMBER DESCRIPTION PAGE
4 FOR THE STAFF:
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132 - Comparison of Cost Of Service
Resul ts & Revenue Allocation
Proposals
Premarked
7 133 - PCA Computational Factors Premarked
8 134 - Marginal Energy Costs, Summary
Total Premarked
9 135 - Calculation of Proposed Rates, Premarked10 Schedule 1
11 136 - Typical Monthly Billing Comparison Premarked
12 137 - Calculation of Proposed Rates, Premarked
Schedule 24
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138 - Calculation of Proposed Rates,
Schedule 7
Premarked
15 139 - Calculation of Proposed Rates,
Schedule 9
Premarked
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140 - Calculation of Proposed Rates,
Schedule 19
Premarked
18 141 - On-Peak/Off-Peak TOU Energy
Charge Rate Differentials
Premarked
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142 - Calculation of Proposed Rates,
Schedules 15, 39, 40 41 & 42
Premarked
143 - Idaho Power Service Area Premarked
144 - 2008 Federal Poverty Level
Guidelines Premarked
145 - Demographics - Idaho PowerTerritory Premarked
CSB REPORTING
Wilder, Idaho 83676
EXHIBITS
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1 E X H I BIT S (Continued)
2
3 NUMBER DESCRIPTION PAGE
5 146 - Idaho Power Complaints & Inquiries Premarked
2004-2007
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18 FOR THE IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.:
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4 FOR THE STAFF:
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147 - Complaints & Inquiries by Utility
Company 2005-2007
19 Premarked
CSB REPORTING
Wilder, Idaho 83676
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8 148 - Post Implementation Program,
Benefi t Cost Analysis
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149 - Appendix 2. 2007 DSM Expenses
by Funding Source
11 150 - Idaho Power's Total System DSM
Expenses 2003-2007
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151 - Revenue Allocation Summary
3CP/12CP Cost-of-Service Results
14 152 - Revenue Allocation Summary
15 153 - Comparison of Cost Of Service
Resul ts and Revenue AllocationProposals16
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301 - Development of Weighted Demand &
Energy Allocators
302 - IIPA Growth Weighted, Base Case
Class Cost of Service Study
303 - IIPA 50% Peak value June & July,
IPCo's Base Case Class Cost of
Service Study
304 - IIPA 50% Peak value June & July,
IPCo's 3CP /12CP Class Cost of
Service' Study
EXHIBITS
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1 E X H I BIT S (Continued)
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3 NUMBER DESCRIPTION PAGE
4 FOR THE IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.:
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305 - Water on the Land, Private
Enterprise Development of
Irrigation in the Snake River
Valley
Premarked
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8 306 - Company's Cost of Service as
Filed
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10 FOR THE INDUSTRIAL CUSTOMERS OF IDAHO POWER:
11 212 - Historic Growth, 1980-2004 Identified 1152
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CSB REPORTING
Wilder, Idaho 83676
EXHIBITS
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1 BOISE, IDAHO, WEDNESDAY, DECEMBER 17, 2008, 1:45 P. M.
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4 COMMISSIONER SMITH: All right, let's go
5 back on the record and we'll turn now to Mr. Olsen for
6 his case.
7 MR. OLSEN: Thank you, Madam Chairman.
8 The Idaho Irrigation Pumpers Association would like to
9 call to the stand Sidney Erwin.
11 SIDNEY F. ERWIN,
12 produced as a witness at the instance of the Idaho
13 Irrigation Pumpers Association, having been first duly
14 sworn, was examined and testified as follows:
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DIRECT EXAMINATION
18 BY MR. OLSEN:
19 Q Mr. Erwin, could you please state your
20 name and spell your last name for the record?
21 A My name is Sidney Erwin. Erwin is spelled
22 E-r-w-i-n.
23 Q Okay. Now, and in what capacity are you
24 providing testimony today?
25 A I'm providing testimony as the vice
CSB REPORTING.
[phone]
1024 ERWIN (Di)Irrigators
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1 president of the Idaho Irrigation Pumpers Association and
2 as a water user who uses irrigation pumping along with
3 the general operation of a farm and ranch.
4 Q Okay. Now, did you sponsor some testimony
5 that was filed on October 24th, 2008 which consisted
6 of -- really quick here, I apologize -- six pages and one
7 exhibit?
8 A Yes, sir.
9 Q Okay, are there any changes or corrections
10 that need to be made to that testimony?
11 A No.
12 Q Okay; so if I were to ask you the same
13 questions today that are contained in the pre filed direct
14 testimony, your answers would be the same?
15 A Yes, sir.
16 MR. OLSEN: Madam Chairman, I would move
17 to spread the testimony of Mr. Erwin on the record.
18 COMMISSIONER SMITH: If there is no
19 objection, we will spread the prefiled testimony upon the
20 record as if read.
21 (The following prefiled direct testimony
22 of Mr. Sidney Erwin is spread upon the record.)
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CSB REPORTING.
[phone]
ERWIN (Di)Irrigators1025
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1 Q. PLEASE STATE YOUR NAME, ADDRESS, EMPLOYMENT AND
2 AFFILIATION WITH THE IDAHO IRRIGATION PUMPERS
3 ASSOCIATION?
4 A.My name is Sidney F. Erwin. Currently, I am a
5 farmer in Owyhee County, Idaho and I am a member and the
6 current Vice President of the Idaho Irrigation Pumpers
7 Association, Inc.("IIPA"). My address is 29711 State
8 Highway 51, Bruneau, Idaho 83604.
9 Q.WHO PROVIDES YOUR ELECTRIC SERVICE, HOW LONG
10 HAVE YOU BEEN FARMING, AND WHAT CROPS DO YOU CURRENTLY
11 RAISE?
12 A.Idaho Power Company ("IPC") supplies all the
13 electrici ty for my farming operations which consists of
14 six ground water wells with irrigation pumps ranging from
15 75 to125 HP. I have been farming full time since 1974 in
16 the Bruneau area. I currently raise alfalfa, oat hay,
17 triticale (a wheat/rye hybrid), and irrigate pasture.
18 Q.WHAT HAS BEEN YOUR WORK AND PUBLIC SERVICE
19 EXPERIENCE WITH THE ELECTRIC UTILITY INDUSTRY IN IDAHO?
A.I graduated from the Uni versi ty of Idaho in
21 1964 with a Bachelor of Science Degree in Electrical
22 Engineering and am a licensed Professional Engineer. I
23 graduated from the University of Idaho in 1966 with a
24 Bachelor of Science in
25
1026 ERWIN, Dir 1Irrigators
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1 Business Finance. I worked from 1966 to 1968 for IPC at
2 its Hells Canyon complex as an electrical inspector and
3 from 1968 to 1972 in IPC's long term planning department.
4 I was a member of, and participated on, the 2006
5 Integrated Resource Plan Advisory Council and I am
6 currently a member of the advisory council which has
7 recently convened for IPC' s 2009 Integrated Resource
8 Plan.
9 Q.CAN YOU PLEASE GIVE A BRIEF HISTORY ABOUT THE
10 DEVELOPMENT OF GROUND WATER PUMPING IN SOUTHERN AND
11 SOUTH-EASTERN IDAHO?
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13
14
A.Yes. Ground water pumping for irrigation
purposes began rapidly developing in the in the 1950s and
1960s in the Snake River plain. This corresponded with
15 IPC' s development of the Hells Canyon complex during the
16 same period and the corresponding surplus of cheap, clean
17 electrici ty to run the irrigation pumps that pumped water
18 from the Snake River plain aquifer. This phenomenon is
19 cataloged in the IPC brochure of the day entitled "Water
20 on the Land" which is attached hereto as exhibit 305.
21 Expansion of various forms of irrigation pumping has also
22 been spurred over the years by the change in irrigation
23 practices from flood irrigation to more efficient
24 sprinkler irrigation. However, by the late 1980s
25 addi tional ground water pumping slowed due to the
1027 ERWIN, Dir 2Irrigators
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1 recogni tion of the interconnectedness of surface water
2 rights and ground water rights and was halted in 1992
3 wi th the moratorium on new ground water rights in the
4 Snake River plain aquifer.
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8 /
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10 /
1028 ERWIN, Dir 2aIrrigators
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1 Q. WHAT EFFECT HAS THE GROUND WATER RIGHT
2 MORITORIUM HAD THE ON IRRIGATION CLASS LOAD GROWTH?
3 A.Wi thout any additional land coming under
4 cultivation as a result of ground water pumping
5 moratorium and the fact that water is limited resource,
6 the Irrigation Class load has not been growing for at
7 least the last two decades. This is clearly shown by the
8 data provided by IIPA witness Mr. Anthony Yankel
9 ("Yankel").
10 Q.ARE THE IRRIGATION CLASS ENERGY SALES EXPECTED
11 TO GROW IN THE FUTURE?
12 A.No. IPC' s current2008 Integrated Resource Plan
13 Update ("2008 IRP") forecasts that the Irrigation Class
14 annual sales growth will be -0.1 percent for the next ten
15 years. i Further, given the moratorium on ground water
16 pumping it is hard to conceive of any scenario whereby
17 there will ever be any significant Irrigation Class sales
18 growth.
Q.WHAT DOES IPC ATTRIBUTE ITS CURRENT NEED FOR
20 ADDITIONAL GENERATION, TRANSMISSION AND DISTRIBUTION
21 RESOURCES?
22 A.The 2008 IRP and IPC primarily attribute IPC' s
23 need for additional generation, transmission, and
24 distribution resources to customer and load growth. 2
25 This load
1029 ERWIN, Dir 3Irrigators
1.2
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24 i 2008 1RP,Appx. A, p. 39.
2 1d. at p.9; Gale 01 at p.18 11.15-24, p.19,1I.1-21..25
1030 ERWIN, Dir 3aIrrigators
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1 growth is the result of residential population growth and
2 associated commercial development in the Treasure
3 Valley. 3
4 Q.DOES IPC' S CLASS COST OF SERVICE STUDY
5 APPROPRIATELY TAKE INTO ACCOUNT THE IRRIGATION CLASS'
6 LACK OF GROWTH WHEN ASSIGNING IPC' S ADDITIONAL GROWTH
7 RELATED GENERATION, TRANSMISSION AND DISTRIBUTION COSTS?
8 A.No. As discussed by IIPA witness Yankel, IPC's
9 class cost of service methodology more or less assumes
10 that all customer classes grow proportionately when
11 assigning growth related costs. For customer classes
12 that are actually growing, the cost of service studies'
13 allocation of growth costs is offset by the additional
14 class revenue generated as a result of the realized
15 growth. However, because growth in the Irrigation Class
16 has been stagnant, and will continue to be such into the
17 foreseeable future, there is no offsetting Irrigation
18 Class growth revenues associated with the allocation of
19 growth relate costs that are given to the Irrigation
Class in IPC' s cost of service studies.As a result of
21 this mismatch, the Irrigation Class revenues will
22 continue to be erroneously shown as significantly below
23 cost of service unless the Commission acts to address
24 this unj ust and unreasonable assignment of growth related
25 costs to the stagnant Irrigation Class. The IIPA' s
1031 ERWIN, Dir 4Irrigators
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1 proposal to use Growth Corrected cost of service
2 principals to assign the costs of system growth addressed
3 in this case in a nondiscriminatory manner to those
4 customer classes that are
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24 3 2008 1RP at p. 9; Keen 01, p. 5, 11. 10-17, p. 7, 11. 1-21; Gale 01
at p. 1811.15-24, p. 19, 11. 1-21.
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1032 ERWIN, Dir 4aIrrigators
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1 actually causing this growth and generating offsetting
2 revenue is a fair, just and reasonable approach that I
3 encourage the Commission use to address this lingering
4 problem.
5 Q.HOW LONG HAVE YOU PARTICIPATED IN THE
6 IRRIGATION PEAK REWARDS PROGRA, WHAT ARE ITS BENEFITS TO
7 IRRIGATION CLASS MEMBERS AND HOW HAS IT HELPED IPC IN
8 ADDRESSING THE PROBLEM OF THE SYSTEM'S EVER INCREASING
9 DEMAND FOR ELECTRICITY?
10 A.I have participated in the Irrigation Peak
11 Rewards Program (" Program") for the past two years. The
12 Program is a benefit to me and other members of the
13 Irrigation Class in that it provides an option to
14 irrigators to voluntarily control their electricity
15 costs. Further, the reduced load should help the
16 Irrigation Class reduce its allocation of peak demand in
17 IPC' s cost of service study and thereby help mitigate the
18 magnitude of future price increases such as IPC has
19 proposed in this case. The Program benefits the system
20 as a whole in that it has been used to cost effectively
21 reduce approximately 40 MW of system load. In turn, this
22 load reduction helps slow the pace of growth by delaying
23 the need for additional generation resources. 4
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Q.WHAT CHANGES ARE ANTICIPATED IN THE PEAK
REWARDS PROGRA AND HOW WILL THOSE CHANGES BENEFIT THE
1033 ERWIN, Dir 5Irrigators
1 IRRIGATION CLASS AND THE SYSTEM?.2
3 /
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5 /
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7 /
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24 4 See Keen 01, p. 5,1I. 18-24, p.6,11.1-7.25
1034 ERWIN,Dir 6Irrigators
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1 A.Shortly, the IIPA, IPC and Staff will be before
2 the Commission recommending changes to the Program.
3 These changes would allow IPC the ability to interrupt
4 the electricity to participating customers' pumps, at
5 IPC' s option, during the critical, summer super-peak
6 hours (the "New Program"). The IIPA has been an active
7 participant in the development and implementation of a
8 similar program on the Rocky Mountain Power system
9 wherein 215 MW of irrigation load was enrolled in Rocky
10 Mountain Power's program for the 2008 irrigation season.
11 The New Program will be beneficial to the Irrigation
12 Class in that it will allow its members a voluntary
13 method to significantly reduce their electricity costs
14 and should also improve the Irrigation Class cost of
15 service results in future rate cases. The program should
16 significantly benefit the IPC system and could
17 conceivably have the ability to reduce summer peak load
18 by an additional several hundred MW, thereby
19 significantly delaying the addition of new generation
20 resources like the recent addition of the 179 MW Danskin
21 peaker plant.
22 Q.DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
23 A.Yes.
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25
1035 ERWIN, Dir 6Irrigators
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1 (The following proceedings were had in
2 open hearing.)
3 MR. OLSEN: Thank you, and I tender him
4 for cross-examination.
5 COMMISSIONER SMITH: And we will also mark
6 for identification Exhibit 305.
7 Mr. Ward, do you have any questions?
8 MR. WARD: Just one.
9
10 CROSS-EXAMINATION
11
12 BY MR. WARD:
13 Q Mr. Erwin, on page 6 of your testimony at
14 line 11, you testify that the new program that you have
15 discussed has the ability to reduce summer peak load by
16 an additional several hundred megawatts. I was just
17 curious, did you get that figure from your participation
18 in Idaho Power's IRP program or some other source?
19 No, the information that I gave here isA
20 based upon my conversations with various high lift
21 pumpers in the area and their willingness to participate
22 in an Idaho Power Company conservation program. The new
23 program that has been proposed, not been accepted yet,
24 has very favorable monetary values in it and very.25 favorable time periods for many more irrigators to
CSB REPORTING
[phone]
1036 ERWIN (X)Irrigators
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1 participate than what have participated in the past Peak
2 Rewards Program.
3 The interest that I have gotten from
4 conversations with various irrigators around the state is
5 that they are very interested in looking at this program
6 and trying to make it work. The other thing that comes
7 about is Rocky Mountain in using the same type of program
8 got a very large participation out of their people. We
9 will certainly have some folks who are limited by water
10 constraints and system constraints and probably will not
11 be able to participate like they'd like to, but everyone
12 has expressed an interest in looking at the program and
13 participating as best they can.
14 MR. WARD: Attorneys should never say I
15 just have one question.
16 Q BY MR. WARD: Would most of those
17 participants be ground water pumpers? I would take it
18 that if you'r~ under a canal, it's going to be a little
19 more difficult to participate in that program.
20 A They will be both ground water pumpers and
21 river pumpers. In my area and on east there are quite a
22 number of irrigation pumpers who pump out of the river,
23 probably six or seven proj ects. All of those have
24 expressed some interest in looking at the program to see
25 if they can work. There is one project that will not be
CSB REPORTING.
[phone]
1037 ERWIN (X)Irrigators
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1 able to participate because they only have 5. 7 gallons
2 per acre, no way can they get by. They need eight
3 gallons to make it work, so they're not going to be able
4 to.
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6
7 have questions?
8
9 don't.
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20 BY MR. WALKER:
21 Q
MR. WARD: Okay, thank you.
COMMISSIONER SMITH: Mr. Purdy, do you
MR. PURDY: I'm sorry I'm late and no, I
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions, Your Honor.
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: No questions.
COMMISSIONER SMITH: Mr. Price.
MR. PRICE: No questions.
COMMISSIONER SMITH: Mr. Walker.
CROSS-EXAMINATION
Good afternoon, Mr. Erwin. You state in
22 your testimony that you run a farming operation in Owyhee
23 County?
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A
Q
That I do.
Is that a family farm? Has it been in
CSB REPORTING
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1038 ERWIN (X)Irrigators
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1 your family for a number of years?
2 A Yes.
3 Q How long has your family farmed in
4 there?
5 A The current place I'm on, we've been there
6 34 years this coming May. The real estate is owned by a
7 102-year-old mother of mine. My father in his wise
8 conduct of estate planning when he died 25 years ago left
9 it to my mother and I'm stuck with farming until
10 something happens to her. That doesn't mean I don't
11 enjoy it, but some days I can think of better things to
12 do.
13 Q So is it fair to say that kind of in the
14 Western tradition of family farms that your farm exists
15 and kind of passes on to the next generation to carry it
16 on--
17 A That's true.
18 Q -- and operate?
19 A That's true.
Q And the actual customer for the accounts
21 wi th Idaho Power, is that you yourself or would that be
22 the family farm or the trust?
23 A That's my 102-year-old mother. It's
24 listed as Annabelle Erwin. The reason for that is that
25 in the Power Company's diligence to not cause me to have
CSB REPORTING
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1039 ERWIN (X)Irrigators
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1 to ante up a big deposit to start with, I have left the
2 account in her name. To change it, I have to come up
3 wi th a depositor I have to go through some scenario to
4 change that and when she dies, I don't know what I'll do.
5 I'll figure that out when that happens.
6 MR. WALKER: That's all the questions I
7 had.
8 COMMISSIONER SMITH: Any questions from
9 Commissioners?
10 COMMISSIONER REDFORD: No.
11 COMMISSIONER SMITH: Any redirect?
12 MR. OLSEN: Yes.
13
14 REDIRECT EXAMINATION
15
16 BY MR. OLSEN:
17 Q Mr. Erwin, Mr. Ward here talked a little
18 bit about the. Peak Rewards Program and you were present
19 here prior to the lunch break with the testimony of
20 Dr. Goins; is that correct?
21
22
A Yes.
Q Okay, and Dr. Goins brought up an issue of
23 trying to change the load shape of the irrigation class.
24 Do you recall that testimony?
25 A Yes.
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1040 ERWIN (Di)Irrigators
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1 Q Okay. What efforts have the irrigation
2 pumpers tried to do in that area and maybe you could
3 expound a little bit upon that, your efforts,
4 particularly?
5 A The irrigation pumpers realizing that peak
6 loads are a problem for the Idaho Power Company system
7 have sought to come up with methods whereby we could help
8 the Power Company achieve their goal of meeting their
9 loads and still help the irrigators by decreasing us a
10 slight bit or. in some cases quite a little the cost of
11 lifting water to irrigate crops. I've been involved with
12 the Irrigation Pumpers Association for the last four or
13
14
fi ve years and because of my involvement there and also
my involvement on the IRP advisory committee, I have
15 observed that it's extremely important not only to Idaho
16 Power but to the irrigators and to all customer classes
17 that we figure out some way to keep the peak load at a
18 manageable level which, hopefully, we can achieve by
19 getting large participation in the conservation program
20 that is now under consideration by the Commission.
21 In order to be successful at this, it's
22 going to take a fair amount of good salesmanship on both
23 the part of the irrigators and on the part of Idaho Power
24 Company to offer the program to the various irrigators in
25 a fashion that they are willing to look at it and accept
CSB REPORTING
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1041 ERWIN (Di)Irrigators
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1 it. One of the issues that I'm faced with right now is
2 that now is the time that I need to be selling this
3 program to the irrigators' so that they can plan
4 accordingly for next season, so I'm patiently waiting for
5 the Commission to do something with their action on the
6 irrigation plan because I need that so that I can go
7 forth and talk the irrigators into trying to participate
8 and see what we can do in that area.
9 Q Okay, one other question. The theme of
10 this case and looking at the cost of service and what the
11 irrigators have put forth, the issues of growth, and
12 we've talked about the fact that the irrigation class has
13 remained steady for the last few years, what other
14 external factors such as water and/or the lack of it
15 affect--
16 COMMISSIONER SMITH: Mr. Olsen?
17 MR. OLSEN: Yes.
18 COMMISSIONER SMITH: Usually the purpose
19 of redirect is to clarify information that was elicited
20 during cross-examination.
21
22
MR. OLSEN: Yes.
COMMISSIONER SMITH: So what are you doing
23 now?
24
25
MR. OLSEN: I have no further questions.
COMMISSIONER SMITH: Thank you. Thank you
CSB REPORTING
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1042 ERWIN (Di)Irrigators
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1 for your help, Mr. Erwin.
2
3
4
5 excused?
6
THE WITNESS: Thank you.
(The witness left the stand.)
MR. OLSEN: May I ask the witness to be
COMMISSIONER SMITH: If there is no
7 obj ection, Mr. Erwin is excused, and we're ready for your
8 next witness.
9 MR. OLSEN: Yes, the Idaho Irrigation
10 Pumpers calls Mr. Anthony Yankel to the stand, please.
11 COMMISSIONER SMITH: Commissioner Redford
12 says that was too mean, so I apologize.
13
14 ANTHONY J. YANKEL,
15 produced as a. witness at the instance of the Idaho
16 Irrigation Pumpers Association, having been first duly
17 sworn, was examined and testified as follows:
20
18
19
21 BY MR. OLSEN:
22 Q
DIRECT EXAMINATION
Mr. Yanke1, could you please state your
23 name and spell your last name for the record, please?
24
25
A
Q
Anthony J. Yankel, Y-a-n-k-e-l.
In what capacity are you testifying before
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1043 YANKEL (Di)Irrigators
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1 the Commission today?
2 A On behalf of the Idaho Irrigation Pumpers
3 Association.
4 Q Okay. Did you file in this case direct
5 and rebuttal testimony, specifically the direct testimony
6 consisting of 45 pages and Exhibits 301 through 305, and
7 rebuttal testimony consisting of 12 pages and Exhibit
8 306?
9 A Yes, except I believe I did not sponsor
10 305 You said through 305. It's 304.
11 Q On your direct testimony?
A Yes,plus Exhibit 306.
Q Plus Exhibit 306 on your rebuttal?
A Yes.
Q Okay.Are there any changes or
12
13
14
15
16 corrections that need to be made with respect to either
17 the direct or the rebuttal testimony?
18 A There is one on the direct testimony, page
19 44. There's a column of numbers there, basically between
20 line 2 and 3.
21
22
23
24
- 25
COMMISSIONER SMITH: I'm sorry, what page?
THE WITNESS: 44.
COMMISSIONER SMITH: 40?
THE WITNESS: 44.
COMMISSIONER SMITH: In your direct
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1044 YANKEL (Di)Irrigators
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19
1 testimony?
2 THE WITNESS: Yes.
3 COMMISSIONER SMITH: Mine ends at page
4 34.
5 THE WITNESS: You missed the good part.
6 COMMISSIONER SMITH: Okay, we'll get our
7 books fixed. Go ahead.
8 THE WITNESS: Okay. There's a column of
9 numbers there, basically a number for each month, and the
10 signs are backwards, so every negative sign should be a
11 posi ti ve sign, every posi ti ve sign should be a negative
12 sign. It does not make any difference to the rest of my
13 testimony, just that the signs were mixed up. That's all
14 I have.
15 Q BY MR. OLSEN: If I were to ask you the
16 questions that are contained in your direct and rebuttal
17 testimony today, would your answers still be the same?
A Yes.
MR. OLSEN: Madam Chairman, I would move
20 to spread the testimony of Mr. Yankel on the record.
21 COMMISSIONER SMITH: If there is no
22 objection, it is so ordered.
23 (The following prefiled direct and
24 rebuttal testimony of Mr. Anthony Yankel is spread upon
25 the record.)
CSB REPORTING
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1045 YANKEL (Di)Irrigators
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1 Q.PLEASE STATE YOUR NAME, ADDRESS, AND
2 EMPLOYMENT.
3 A.I am Anthony J. Yankel. I am President of
4 Yanke1 and Associates, Inc. My address is 29814 Lake
5 Road, Bay Village, Ohio, 44140.
6 Q.WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL
7 BACKGROUND AND PROFESSIONAL EXPERIENCE?
8 A.I received a Bachelor of Science Degree in
9 Electrical Engineering from Carnegie Institute of
10 Technology in 1969 and a Master of Science Degree in
11 Chemical Engineering from the University of Idaho in
12 1972. From 1969 through 1972, I was employed by the Air
13 Correction Division of Universal Oil Products as a
14 product design engineer. My chief responsibilities were
15 in the areas of design, start-up, and repair of new and
16 existing product lines for coal-fired power plants. From
17 1973 through 1977, I was employed by the Bureau of Air
18 Quali ty for the Idaho Department of Health & Welfare,
19 Division of Environment. As Chief Engineer of the
20 Bureau, my responsibilities covered a wide range of
21 investigative functions. From 1978 through June 1979, I
22 was employed as the Director of the Idaho Electrical
23 Consumers Office. In that capacity, I was responsible
24 for all organizational and technical aspects of
25 advocating a variety of positions before various
1046 YANKEL, DI 1Irrigators
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1 governmental bodies that represented the interests of the
2 consumers in the State of Idaho. From July 1979 through
3 October 1980, I was a partner in the firm of Yankel,
4 Eddy, and Associates. Since that time, I have been in
5 business for myself. I am a registered Professional
6 Engineer in the states of Ohio and Idaho. I have
7 presented testimony before the Federal Energy Regulatory
8 Commission (FERC), as well as the
9
/
1047 YANKEL, DI 1aIrrigators
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12
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15
1 State Public Utility Commissions of Idaho, Montana, Ohio,
2 Pennsylvania, Utah, and West Virginia.
3 Q.ON WHOSE BEHALF ARE YOU TESTIFYING?
4 A.I am testifying on behalf of the Idaho
5 Irrigation Pumpers Association, Inc. (Irrigators).
6 Q.WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
7 PROCEEDING?
8 A.My testimony will address:
9 .Disproportionate growth on the system
10 .Irrigation Peak Rewards Program
.Allocation of Sales For Resale and
Purchase Power based on usage
Q. WHAT ARE YOUR CONCLUSIONS AND RECOMMENDATIONS
IN THIS CASE?
A.I make the following conclusions and
16 recommendations:
17
18
19
20
21
22
23
24
25
.There has been very rapid growth on the
system for all customer classes except the
Irrigators' load which has been flat for
at least the last 25 years. The cost of
this growth shows up in all aspects of the
Company's cost structure; Production,
Transmission, and Distribution.
1048 YANKEL, DI 2Irrigators
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1 .In spite of the lack of Irrigation growth,
2 the Company's cost-of-service study
3 allocates disproportionate amounts of
4 these costs to the Irrigators. The
5 Irrigators have gotten more than the
6 system average increase for at least the
7 last 15 years.
8 .If the Company's "Base Case"
9 cost-of-service study were modified to
10 match its marginal cost allocation factors
11 wi th the growth causing the marginal costs
12 (as opposed to historic usage billing
13 determinants), the rate of return for the
14 Irrigation class would more appropriately
15 reflect the lack of Irrigation
16 contribution to the system growth and
17 growth related costs. If the impact of
18 growth is recognized, the Irrigation rate
19 of return would be over four times the
20 system average. Based upon a proper
21 matching of the Company's marginal costs
22 allocation factors with growth (as opposed
23 to historic billing determinants), I
24 recommend no increase in this case for the
25 Irrigators.
1049 YANKEL, DI 3Irrigators
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17
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1 .The Irrigation Peak Rewards Program is
2 about to undergo maj or improvements that
3 should greatly increase participation
4 levels and become a maj or resource for
5 Idaho Power to use in controlling its
6 summer peak load. These changes should be
7 in place for next summer's Irrigation
8 season and system peak loads. Any
9 consideration of cost of service and
10 revenue responsibility should reflect the
11 fact that there will be maj or changes to
12 the system peak loads when these rates are
in effect as well as the Irrigation
contribution to those peak loads.
.The Company has historically allocated
Sales For Resale revenues on a simplistic
basis (annual energy usage and/or
generation demand
1050 YANKEL, DI 3aIrrigators
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1 responsibili ty). Data and computing
2 techniques are available today to match
3 these sales on an hourly basis with the
4 cost causation the makes these sales
5 possible. An example is presented as to
6 how this can be done and a recommendation
7 is made to consider such techniques for
8 future cases.
9
10
11
12
13
14
15
16
17
18
19
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21
22
23
24
25
1051 YANKEL, DI 4Irrigators
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1 DISPROPORTIONATE GROWTH ON THE SYSTEM
2 Q.HAS GROWTH ON THE IDAHO POWER SYSTEM BEEN
3 UNIFORM?
4 A.No. For more than two decades there has been a
5 maj or imbalance in the growth on the Idaho Power system
6 between customer classes.
7 Q.UPON WHAT DO YOU BASE YOUR STATEMENT THAT THERE
8 HAS BEEN AN IMBALANCE OF GROWTH ON THE SYSTEM?
9 A.Even the most casual observer should note that
10 for years there has been strong and persistent growth on
11 the Idaho Power system and that this growth has not
12 occurred in the Irrigation load. This is most easily
13 demonstrated by observing the following graph1:
14
15 Historic Growth7,000
6,000 -
5,000
l 4,000
3,000 .,--k---A("'~-
2,000
1,000
1980 1985
16 ~----· &;_.-../
Comm. & Ind. ,v.....,t(...17/
181 .....t,.."¿:;;-~r---'--/1;.J'-K",./ I
ReSidentjal-~
i
19
Irrigation
1990 1995 2000 2005
1052 YANKEL, DI 5Irrigators
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~.
lOver the last 25 years, the Irrigation load has been
2 basically flat-decreasing 2%; Residential load has
3 increased 54%; and the combined Commercial/Industrial
4 load has over doubled at an increase of 124%. All
5 customer classes, except the Irrigation class, have
6 caused the phenomenal growth on the Idaho Power system.
7 This pattern is expected to continue. 2
8 Q.WHY DOES THIS GRAPH OF 25 YEARS OF HISTORICAL
9 USAGE END WITH 2005?
10 A.The data for this graph came from the Company's
11 2006 Integrated Resource Plan ("IRP"). I utilized the
12 Company's IRP because it is a source of data where it is
13 possible to get 25 years of historical data as well as
14 proj ected usage, all in one place. The most recent Idaho
15 Power IRP is for 2006. Historical data from the
16 Company's 2006 IRP only goes to 2005. There was a 2008
17 IRP Update, but it did not provide similar historical
18 information.
19 Q.HAS THERE BEEN GROWTH IN UTILITY PLANT-IN-
20 SERVICE?
21 A.Yes. In order to keep up with this growth,
22 there have been significant increases in Plant-In-Service
23 at all functions as demonstrated by the following graph3:
24
25 /
1053 YANKEL, DI 6Irrigators
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1
2
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5 /
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7 /
8
9
10
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12
13
14
15
1 Historic usage data taken from pages 25, 27, 29, 31 of Appendix A
of Idaho Power's 2006 IRP.
2 According to Appendix A, page 39 of Idaho Power's 2008 Integrated
Resource Plan Update, over the next 10 years Irrigation load is
expected to decline slightly, while all of the other classes are
expected to experience continued load growth.
3 Data taken from FERC Form 1 for years 1981-2006.
1054 YANKEL, DI 6aIrrigators
-_....-....__.._--_._-_..".....__.-
1.2 1,800
3 1,600
4 1,400
5 0 1,20000 --Ô 1,00060 Ja.~800 -
7 )(~600 --
8
.
.
---
Historic Plant in Service --~..
Generation ~~
9
400
200
I
/ /--" ~~/' _/ I
_----- Transmission I
i
i
.,."',...."......"'so ¿/'
Distribution ,~
V"'~~'-~"~'
~.-.-.-_..--~-
I
10
11
o I i
1980 1985 1990 1995 2000 2005
12
13
14
15 In the last 25 years, Generation plant has increased $768
16 mìllion or 93%, Transmission plant has increased $360
17 million or 145% (more than doubled its 1981 level), and
18 Distribution plant has increased the most by addìng an
19 additional $780 million or 246% (over tripled ìts 1981
20 level) .
21 Given the huge percentage growth in
22 Distribution Plant-In-Service and the fact that the
23 absolute dollar magnitude even exceeded that of new
24 Generation plant, it is worthwhile to look at these
25 accounts in more detail:
1055 YANKEL, 01 7Irrìgators
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11
2 350
3 300
4 250
Historic Plant Account Values
5 ooo~ 200ooo
~ 150
fß
Line Transformers
6
7
8
9
10
11
100
UG conduit
~~----,.....,,_..,
,,._._--,."" ...."'~~
,,,,.,..~--.
- ," UG conductor"'/',"
,,,'-'~"
A..'tt"r"'-_....~....~O.._:._/'
-"0/0-"0'/'- .OH conductor
50
- ---------------_.-.-_._--_.-------- -_.
o
1980 1985 1990 1995 2000 2005
12
13
23
14 As can be seen from the above graph, the increase in
15 plant-in-service has occurred in all aspects of
16 Distribution Plant. What is not readily apparent from
17 the above graph is the percentage change in various
18 accounts. The Overhead Conductor account has doubled,
19 while the Poles and Line Transformer accounts have
20 tripled in the last 25 years. However, the Underground
21 accounts have gone up over 700% of their levels from 25
22 years ago.
DOES THE COMPANY'S ALLOCATION METHODS AND COSTQ.
24 OF SERVICE STUDIES PROPERLY REFLECT THE IMPACT OF THESE
25 GROWTH RATES .ON COSTS TO CUSTOMER CLASSES?
1056 YANKEL, DI 8Irrigators
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1 A.No. IPCo witness Gale stated in his testimony
2 in this case4 that the Company has been advocating cost
3 based rates:
4 Idaho Power has consistently advocated for the
principle that rate spread among the customer
5 classes and for component pricing wi thin the
customer classes should be primarily cost-based.
6 Accordingly, the company's ratemaking proposals have
tradi tionally advocated movement towards
7 cost-of-service results which assign costs to those
customers that cause the Company to incur the costs.
8
9 Al though IPCo tries to follow this policy with respect to
10 the results produced by its cost of service studies, the
11 Company's cost of service study inappropriately allocates
12 a significant portion of this growth to the Irrigation
13 class. Gi ven the obvious fact that growth and the cost
14 of growth are not being fueled by the Irrigators, the
15 allocation of. significant portions of the cost of this
16 growth to the Irrigators is on its face
17 counter-intui ti ve. Additionally, the Company is not
18 properly signaling the rate schedules that are growing
19 that their growth is expensive-thus, promoting additional
20 growth.
21 Q.PLEASE FURTHER EXPLAIN HOW THE RESULTS OF THE
22 COMPANY'S CLASS COST OF SERVICE STUDY ARE
23 COUNTER-INTUITIVE.
24 A.As pointed out above, the trend that has been
25 in place for more than two decades is that the
1057 YANKEL, DI 9Irrigators
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20
21
22
23
24.25
1 non-Irrigation load has increased, while the Irrigation
2 load has either stayed even or decreased. The following
3 lists the annual system peak demand data utilized in both
4 this case and Case IPC-E-94-5 which used a 1993 test
5 year5 (15 years ago):
6
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
4 See the direct testimony of John R. Gale at page 23 lines 16-24.
5 The non-irrigation data listed for Case IPC-E-94-5 does not include
data for FMC.
1058 YANKEL, DI 9aIrrigators
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1
2
Annual System Peak 1993 2008 ~Change0
Irrigation (kW)572,219 610,726 6.7%
Non-Irrigation ( kW)1,212,428 2,331,457 92.3%
As can be seem from above,the changes in load at the
time of the single annual system peak are striking.Over
the last 15 years,the rate of growth for the
3
4
5
6
7 non-irrigation customers has been at a rate that is
8 approximately 14 times greater than that for the
9 Irrigators.
10 A similar pattern can be seen with respect to
11 the annual energy consumption:
12 Annual Energy Usage 1993 2008 % Change
13 Irrigation (MWH) 1,799,035 1,720,416 -4.4%
14 Non-Irrigation (MWH) 8,867,253 13,316,310 50.2%
15 As can be seem from above, the changes in annual energy
16 usage follow a diverging pattern. Over the last 15 years
17 the Irrigation usage has decreased usage by almost 5%,
18 while Non-Irrigation usage has increased approximately
19 50%. As pointed out by Irrigator witness Sidney F.
20 Erwin, the fact that there is a moratorium on new ground
21 water rights in the Snake River Plain Aquifer prohibits
22 Irrigation load from growing due to the lack of water.
23 Although there has been conversion of some flood
24 irrigated land to sprinkler irrigation, much of this
25 limi ted growth has been offset by more efficient
1059 YANKEL, DI 10Irrigators
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22
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24
25
1 irrigation methods being applied. For the other customer
2 classes, there are far less limitations to their
3 continued growth as predicted by the Company.
4 Q.WHY is THIS HISTORIC PRESPECTIVE OF BILLING
5 DETERMINANTS IMPORTANT?
6
7 /
8
9 /
10
11 /
1060 YANKEL, DI lOaIrrigators
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1 A.It has been an often repeated theme of this
2 rate case as well as past rate cases that growth on the
3 system is causing cost increases and the corresponding
4 need to seek rate increases for the customers. As stated
5 by Company President Mr. Keen in this case6:
6 Q. Are these actions alone sufficient to ensure a
reliable' and safe supply of electricity for your
customers?A. No. The need to expand infrastructure and
obtain new energy supplies continues to grow. Our
recently filed update of our Commission-accepted
Integrated Resource Plan, or "IRP", forecasts the
addi tion of between 12,500 and 13,000 new customers
per year over the 20-year planning period. Energy
demand is forecast to grow about 30 average
megawatts per year with a 70 megawatt-per-year
increase in peak demand levels - a growth rate that
would be greater if not for our demand-side
management efforts during the period. These trends
will require continuing expansion of generation and
delivery systems and energy efficiency programs.
The IRP details our need to add 650 megawatts of
supply-side capacity and 225 megawatts of
transmission capacity from 2008 through 2012.
7
8
9
10
11
12
13
14
15
16 Gi ven the substantial growth on the Idaho Power system
17 and the cost of that growth, one would expect that the
18 cost of that growth would be borne by the customers that
19 are causing that growth. Contrary to this premise, the
20 Company's cost of service studies over the last 15 years
21 have proposed to allocate disproportionate increases to
22 the Irrigators in order to pay for the cost of growth of
23 other customers. The following is a listing of the
24 percentage increases recently sought by Idaho Power and
25 the percentages increases that the Company's costs of
1061 YANKEL, DIllIrrigators
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16
17
18
19
20
21
22
23
24
25
1 service studies assigned to the Irrigators as well as
2 Residential and General Service (secondary):
3 Overall
Increase
17.68 %
Increase toIrrigators
67.10%
Increase to
Residential
13.38%
Increase to
GS (Sec.)
8.00%4
Case No.
IPC-E-03-137
5 IPC-E-05-288 7.82%27.03%2.76%7.32%
6 IPC-E-07-089 10.35%42.64%0.11%9.14%
7 IPC-E-08-1010 9.89%32.38%2.01%9.44%
8
9 /
10
11 /
12
13 /
14
15
6 See direct testimony of J. Lamont Keen at page 7 lines 1-17.
7 Exhibit 41 page 1 line 233
8 Exhibit 44 page 1 line 53
9 Exhibit 45 page 1 line 53
10 Exhibit 57 page 1 line 53
1062 YANKEL, DI l1aIrrigators
.
.
.
1 Note that in spite of the Irrigators not causing any
2 growth or growth related costs, the Company's cost of
3 service study attempts to give Irrigators percentage rate
4 increases that are significantly above the system
5 average, while those same cost of service studies have
6 always shown the Residential customers and the General
7 Service (secondary) customers as needing less than the
8 average rate increase. Clearly, these Company cost of
9 service studies have been producing counter-intuitive
10 recommendations with respect to the Irrigation customers.
11 Q.IS THE ALLOCATION METHODOLOGY IN THE COMPANY'S
12 COST OF SERVICE STUDY IN THIS CASE THE SAME AS THAT FROM
13 15 YEARS AGO?
14 A. Generally speaking, yes.There have been some
15 minor changes compared to 15 years ago, but the
16 allocation methodology used by the Company in this case
17 under Exhibits 54-58 (referred to by the Company as its
18 "Base Case") is similar for the major allocators (D10,
19 D13, and E10). If anything, the allocation methodology
20 under the Company's Base Case may be more tolerant of the
21 lack of Irrigation growth than was the allocation
22 methodology used 15 years ago. In spite of the Company's
23 proposed method in this case being "more tolerant of the
24 lack of Irrigation growth", it is still wide-of-the-mark
25 of fairly allocating the cost of growth to those classes
1063 YANKEL, DI 12Irrigators
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11 /
12
13
14
15
16
17
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19
20
21
22
23
24
25
1 that have been growing and thus, causing substantial cost
2 increases to the system.
3 Q.HOW DO THE COSTS ALLOCATED TO THE IRRIGATORS
4 AND OTHER CUSTOMERS IN THIS CASE, COMPARED TO THE COST OF
5 SERVICE STUDY PROVIDED 15 YEARS AGO, REFLECT THE LACK OF
6 GROWTH OF THE IRRIGATION CLASS AND THE SIGNIFICANT GROWTH
7 IN OTHER CUSTOMER CLASSES?
8
9 /
/
1064 YANKEL, DI 12aIrrigators
.
11
1 A.A comparison of the level of costs allocated to
2 Irrigators in this case with those allocated 15 years
3 ago, demonstrates the counter-intuitive nature of these
4 studies when growth and the cost of growth is not
5 addressed in the allocation factors. A comparison of the
6 allocated Production rate base between this case (IPCo' s
7 "Base Case") and the case 15 years ago reveals the
8 following:
9 Production11 (x$1000)1993 2008 % Change
10 Irrigation $164,667 $230,329 39.9%
Non- Irrigation $847,877 $1,533,152 80.8%
12 Under the Company's allocation method, the Production.13
14
plant rate base attributed to Irrigators has increased by
40% and the percentage of new Production plant attributed
15 to Irrigators (whose load has been virtually stagnant) is
16 half the percentage increase that has been allocated to
17 all of the customer classes that have been experiencing
18 rapid growth.
19 The counter-intuitive nature of the Company's
20 allocation methods with respect to this lopsided growth
21 are even better observed with respect to the rate base
22 associated with Transmission plant. A comparison of the
23 allocated Transmission rate base between this case
24 (IPCo' s "base case") and the case 15 years ago reveals.25 the following:
1065 YANKEL, DI 13Irrigators
.
.
.
16
17
18
19
20
21
1 Transmission12 (x$1000)1993 2008 % Change
2 Irrigation $41,271 $ 89,016 115.7%
3 Non- Irrigation $207,152 $597,840 188.6%
4
5 /
6
7 /
8
9 /
10
11
12
13
14
15
22 11 1993 data comes from Case No. IPC-E-94-5, Company Exhibit 32,
pages 3 and 4. The 2007 data comes from Case No. IPC-E-08-10,
23 Company Exhibit 55 (base case), page 3.
12 1993 data comes from Case No. IPC-E-94-5, Company Exhibit 32,
24 pages 3 and 4. The 2007 data comes from Case No. IPC-E-08-10,
Company Exhibit 55 (base case), page 3.
25
1066 YANKEL, DI 13aIrrigators
.
.
.
1 In spite of the fact that the overall usage of the
2 Irrigators has been flat and their growth in contribution
3 to the annual system peak has been virtually non-existent
4 in comparison to the other customer groups, the Company's
5 allocation method is giving Irrigators over double the
6 transmission rate base it had 15 years ago and
7 approximately the same percentage increase in new
8 Transmission plant that it is giving all other customer
9 classes.
10 The counter-intuitive nature of the Company's
11 allocation methods with respect to this lopsided growth
12 can also be observed with respect to the rate base
13 associated with Distribution plant. A comparison of the
14 allocated Distribution rate base between this case
15 (IPCo' s "base case") and the case 15 years ago reveals
16 the following:
17 Distribution 13 (x$1000) 1993 2008 % Change
18 Irrigation $105,394 $187,260 77.7%
19 Non-Irrigation $425,080 1,070,312 151.8%
20 Once again, in spite of the fact that the overall energy
21 usage of the Irrigators has been on the decline and their
22 growth in contribution to the annual system peak has been
23 virtually non-existent in comparison to the other
24 customer groups, the Company's allocation method in this
25 case is giving almost double the dollar amount of
1067 YANKEL, DI 14Irrigators
.
.
.
20
21
22
23
24
25
1 Distribution plant-in-service to the Irrigators that was
2 gi ven 15 years ago even though there was no growth by the
3 Irrigators. The Company's allocation method has given
4 approximate half of the percentage increase in new
5 Distribution plant to the Irrigators that it is giving
6 all other customer classes. One would expect only a
7 small amount of this growth in Distribution plant went to
8 serve Irrigation customers.
9
10 /
11
12 /
13
14 /
15
16
17
18
19
13 1993 data comes from Case No. IPC-E-94-5, Company Exhibit 32,
pages 3 and 4. The 2007 data comes from Case No. IPC-E-08-10,
Company Exhibit 55 (base case), page 3.
1068 YANKEL, DI 14aIrrigators
.
.14
15
16
17
18
19
20
21
22
23
24.25
1 Q.WAS THE WORKSHOP THAT WAS INITIATED AS A RESULT
2 OF THE 2003 CASE ABLE TO COME TO ANY CONCLUSIONS
3 REGARDING THE TREATMENT OF THE ALLOCATION OF THE COSTS
4 ASSOCIATED WITH THIS GROWTH?
5 A.Al though there was general consensus among the
6 workshop participants on a number of issues, the only
7 agreement regarding the treatment of growth in the
8 Company's cost of service study is that there is a
9 disconnect between the classes that were growing and
10 causing the costs to be incurred and the allocation of
11 those costs. Regarding whether new growth was properly
12 covering its cost of service, "The Parties' Final Report
13 in IPC-E-04-23" stated:
Most of the workshop time was devoted to discussion
of this issue. The parties agreed that there was
something inherently troubling with the way costs,
associated with growth, were allocated. This is
evidenced by the relatively large increase in
revenue requirement allocated to customers whose
load and energy requirements were unchanged or grew
only slightly. While there was agreement that the
cost of growth did not necessarily get allocated to
the customer classes that grew, we were unable to
devise a technical remedy to the allocation
procedure that would also satisfy the courts. The
parties were unable to devise and agree to a
cost-of-service allocation methodology that would
properly allocate the cost of growth, without making
a distinction between new and old customers. Even a
search of what others, around the country, were
doing produced little in the way of an acceptable
solution. Therefore, it was concluded that the only
remedy is a policy solution. The parties were not
willing to agree to the particulars of such a policy
and recommend that the Commission formulate such a
policy in the next rate proceeding. (Emphasis
added)
1069 YANKEL, DI 15Irrigators
.
.
.
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
1 Q.WERE THE WORKSHOP PARTICIPANTS ABLE TO DEVELOP
2 A CONSENSUS POSITION THAT DEFINED THE COST IMPACTS OF
3 GROWTH?
4 A.No. As pointed out above, the workshop
5 participants were not able to develop a consensus method
6 for allocating the cost of growth in a manner that was
7 acceptable to all parties. The problem with attempting
8 to develop a consensus was recognized by various
9 participants at
10
1070 YANKEL, DI 15aIrrigators
.1 the workshop. Although there was general consensus that
2 there was something inherently very wrong with the
3 present allocation scheme as related to its ability to
4 allocate the cost of growth, no one felt that they could
5 go back to their clients and admit that they agreed to a
6 methodology that would cost their client more money-this
7 decision was left to the Commission.
8 Q.DOES THE COMPANY'S APPROACH TO RATEMAKING AND
9 COST ALLOCATION ATTEMPT TO REFLECT COSTS?
10 A.That is the Company's stated goal, although
11 that may not be the result. The classification and
12 allocation used by the Company, only looks at half of the
13 cost causation equation-it assumes a steady state.14 si tuation or one with even growth across all classes.
15 The NARUC Electric Utility Cost Allocation Manual makes a
16 general statement that is right on target in this
1 7 situation:
18 The common obj ecti ve of the methods reviewed in
the following two parts is to allocate19 production plant costs to customer classes
consistent with the cost impact that the class20 loads impose on the utility system. (emphasis
added) 14
21
22 As a general statement, I believe all parties would agree
23 with this NARUC policy. As demonstrated above, there has
24 been a tremendous amount of growth on the system over the.25 last 25 years with associated costs to support that
1071 YANKEL, DI 16Irrigators
.
13.14
15
16
17
18
19
20
21
22
23
24.25
1 growth. For all practical purposes, the Irrigators have
2 not participated in that rapid growth and were not the
3 cause of the costs associated with that growth. However,
4 as has been demonstrated above, the Company's cost of
5 service studies do not address the disproportionate cost
6 of growth and, thus, do not accomplish this goal.
7
8 /
9
10 /
11
12 /
1072 YANKEL, DI 16aIrrigators
.
.
.
1 Q.is THE COMPANY ADVOCATING THE SAME GENERAL
2 ALLOCATION METHODOLOGY IN THIS CASE AS IT DID OVER THE
3 PAST 15 YEARS?
4 A.No. Although the Company provided as its Base
5 Case an allocation methodology that is similar to what it
6 has proposed ~n the past, it is favoring a new
7 classification/ allocation method in this case. The
8 resul ts of the Company's Base Case are contained in Mr.
9 Tatum's Exhibit 57. The new method favored by Mr. Tatum
10 and the Company, classifies/allocates Production costs
11 based upon function (base, intermediate, and peak) during
12 the three summer months. The results of the Company's
13 preferred method are contained in Mr. Tatum's Exhibit 66.
14 The Company is not proposing any changes to its
15 Transmission, Energy, or Distribution allocators. Thus,
16 there is very little overall change.
17 Q.IS THE NEW ALLOCATION METHOD ADVOCATED BY THE
18 COMPANY FOR PRODUCTION RELATED COSTS AN IMPROVEMENT OVER
19 THE PAST METHOD THAT IT ADVOCATED?
20 A.Only very marginally. This new method only
21 addresses Production cost and it still suffers from the
22 same shortcomings as the Company's past studies-it
23 allocates costs on a stagnant basis, with no recognition
24 of the impact of growth on costs. This new method still
25 suggests that the Irrigation customers pay a substantial
1073 YANKEL, DI 17Irrigators
.
.
19
20
21
22
23
1 amount for the cost of growth for which they have not
2 caused.
3
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
.24 14 Electric Utility Cost Allocation Manual, published by the National
Association of Regulatory Utility Commissioners 1992 at page 39.
25
1074 YANKEL, DI 17aIrrigators
.
.
.
1 Q.DOES THE COMPANY BASE CASE ALLOCATION
2 METHODOLOGY RECOGNIZE THE NEED TO RECOGNIZE GROWTH IN ITS
3 ALLOCATION METHODOLOGY?
4 A.Although the Company's Base Case allocation
5 methodology falls short of recognizing the disparity of
6 growth on the. system, it has been stated that it is the
7 Company's intention to do so. In Case IPC-E-05-28
8 Company witness Brilz15 offered the following with respect
9 to the Company's thoughts regarding the Base Case
10 methodology:
11 Q. What is the reasoning for using marginal cost
weightings in the derivation of the demand- and12 energy-related allocation factors?
13 A. The use of marginal cost weighting is intended
to strike a balance between backward-looking costs
already incurred and forward-looking costs to be
incurred. in the future.
14
15
16 The exact same language appears in Mr. Tatum's testimony
17 in the 2007 rate case16. Mr. Tatum provides very similar
18 testimony in this case. 17 The intent is appropriate-the
19 execution falls short of the goal.
20 The balance between historic and forward
21 looking costs that is struck in the Company's study is
22 50% based upon an unweighted 12-CP allocation that is
23 designed to reflect today's share of cost causation on
24 the system18. The other 50% of the allocation factor
25 purports to reflect forward-looking costs and this is
1075 YANKEL, DI 18Irrigators
1 where the maj or disconnect occurs. The Company.2 inappropriately defines forward-looking costs using the
3 same test-year 12-CP usage characteristics (present day
4 usage) and combines it with marginal weighting factors
5 that reflect
6
7 /
8
9 /
10
11 /
12
13.14
15
16
17
18
19
20
21
22 15 Case No. IPC-E-05-28, witness Brilz at page 19.
16 Tatum testimony in Case No. IPC-E-07-08, page 25, line 10.
23 17 Tatum testimony in Case No. IPC-E-07-08, page 36, lines 2-4.
18 For purposes of this discussion, I accept this part of the
24 Company's method. However, this approach ignores the lopsided growth
that has taken place for over two decades on the system..25
1076 YANKEL, DI 18aIrrigators
.
.
.
1 "forward-looking costs to be incurred in the future" in
2 order to meet growth. Thus, the Irrigators (as well as
3 all classes) get assigned costs, based upon weighting
4 factors designed to reflect growth that is going to be
5 incurred by the System in the future, but not based upon
6 the usage/growth that is going to create those costs.
7 Thus, unrealistic results occur where the Irrigation load
8 is stagnant or decreasing, but the cost of the system
9 growth is being assigned to it, not based upon future
10 growth of the Irrigators, but based upon the present
11 usage of the irrigators.
12 HOW COULD THE COMPANY'S BASE CASE ALLOCATIONQ.
13 METHODOLOGY BE BETTER ALIGNED TO REFLECT
14 "BACKWARD-LOOKING COSTS ALREADY INCURRED AND
15 FORWARD-LOOKING COSTS TO BE INCURRED IN THE FUTURE"?
16 A.The. simplest way to correct the Company's Base
17 Case study would be to continue to define
18 "backward-looking costs" based on test year usage levels
19 and "forward-looking costs" at the anticipated increase
20 in usage levels in the Company's IRP. The
21 "backward-looking costs" would simply be costs as they
22 exist today and allocated on the basis of today' s energy
23 or 12-CP as is presently done in the Company's "base"
24 cost of service study. The "forward-looking costs" would
25 be developed using the same weighting factors used by the
1077 YANKEL, DI 19Irrigators
.
.
.
11
12 /
13
14
15
16 /
17
18
19
20
21
22
23
24
25
1 Company associated with the cost of the anticipated
2 growth, but would be allocated on the basis of only the
3 growth that is anticipated from each rate schedule over a
4 future ten year period. The relative share of historic
5 costs and anticipated costs related to growth would then
6 be averaged using the Company's existing procedure in
7 order to develop a composite allocation factor for use in
8 spreading test year costs for allocation purposes. In
9 this manner, the methodology would be exactly the same as
10 the
/
1078 YANKEL, DI 19aIrrigators
.
.
1 Company's Base Case, but the marginal costs would be tied
2 to the marginal/new usage and not to the present level
3 (status quo) of usage.
4 Q.HOW COULD THE CHANGE THAT YOU PROPOSE BE
5 1IMPLEMENTED TO THE COMPANY'S COST OF SERVICE STUDY IN
6 ORDER TO INSURE THAT THIS COUNTER-INTUITIVE RESULT DOES
7 NOT CONTINUE IN THE FUTURE?
8 A.One very simple change could be made. Instead
9 of combining the Company's growth related weighting
10 factors with existing billing determinants, they could be
11 combined with forecasted growth-making an
12 apples-to-apples comparison.
13 The. Company's 2006 IRp19 that served as a basis
14 for developing the weighted cost factors can also serve
15 as the source of the data for the forecasted growth as
16 well. In Exhibit 301, I have simply modified the
17 Company' s all~cation weighting procedure to apply the
18 marginal cost weightings developed by the Company to only
19 the growth that is expected over the next ten years20.
20 For example, the Company's Exhibit 59 page 1 takes the
21 May normalized demand for the Residential class of
22 894,322 and multiplies it by a weighting of 10.41 in
23 order to develop a weighted demand of 9,309,897. The
24 starting figure of 894,322 is a test year value and not.25 reflecti ve of the growth that will take place on the
1079 YANKEL, DI 20Irrigators
1 system.Only the future growth in Residential load.2 should be used for this calculation.
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21 19 This is the last IRP where a full range of forecasts and data was
provided. The 2008 Update did not contain detailed data to break out
22 growth by group~ng.
20 A ten year growth horizon was chosen to give some stability to the
23 numers without forecasting out so far that reliability concerns
would be raised. Although a five year growth horizon would have
24 produced more beneficial allocators for the Irrigators, it was felt
that a ten year growth horizon would be preferable..25
1080 YANKEL, DI 20aIrrigators
.1 According to the Company's 2006 IRP21, the average load
2 for the Residential class will increase from 4,865,000 to
3 5,811,000 billed MWh or 19.45% between 2006 and 2016.
4 Thus, instead of using the Company's billing unit of
5 894,322, a value for expected growth must be used. The
6 expected growth for Residential load in May can be
7 estimated at 173,946 MWh (894,322 MWH x 0.1945) over
8 the next ten years. This value of 173, 946 MWh should be
9 multiplied by the Company's weighting factor of 10.41.
10 Similar adjustments to only include the growth portion of
11 each class' load in the Company's method needs to be
12 made..13 Q. DID YOU PROPOSE THIS MECHANISM AS A MEANS OF
14 REFLECTING THE COST OF GROWTH TO THE WORSHOP IN CASE
15 IPC-E-04-23?'
16 A.No. The proposal I made to the Workshop was
17 one that looked backward and tried to capture the amount
18 of growth and the cost of growth that took place over the
19 previous 25 y~ars. The Workshop was not able to come to
20 an agreement regarding that proposed methodology as a
21 means of properly allocating the cost of growth. The
22 methodology that I am proposing here is forward looking
23 and it matches the future marginal costs the Company
24 employs in its cost of service study with future growth..25 It does not attempt to separate "old electrons" from "new
1081 YANKEL, DI 21Irrigators
.
.
17
18
19
20
21
22
23
1 electrons" or "new customers" from "old customers."
2 Q.WHAT GROWTH PERCENTAGES DID YOU INCORPORATE
3 INTO YOUR REVISION OF THE COMPANY'S BASE CASE COST OF
4 SERVICE STUDY?
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
24 21 Idaho Powers 2006 IRP - Sales and Load Forecast page 26..25
1082 YANKEL, DI 21aIrrigators
.
.
.
1 A.Using the Company's 2006 IRP22, the following
2 growth percentages were calculated:
3 Residential 19.45%
4 Commercial (Sch. 7, 9, 40, 42)30.04%
5 Industrial (Sch. 19)27.24%
6 Irrigation 1.03%
7 Special Contracts 9.38%
8 I utilized these percentages as the basis for calculating
9 the amount of growth (beyond test year billing
10 determinants) associated with the Generation and
11 Transmission plant (allocators D10, D13, and E10). I
12 made no calculation to reflect the growth in Distribution
13 plant that is larger than the growth in either Generation
14 or Transmission plant.
15 Q.WHAT IS THE IMPACT ON THE COMPANY'S BASE CASE
16 COST OF SERVICE STUDY WHEN ITS GROWTH RELATED WEIGHTING
17 FACTORS ARE APPLIED TO FORECAST GROWTH AS OPPOSED TO
18 HISTORIC/PRESENT USAGE AND HOW DO THOSE RESULTS COMPARE
19 WITH THE BASE CASE STUDY IN THE COMPANY FILING?
20 A In spite of the fact that this change is only
21 directed at 50% of the allocation factor, as can be seen
22 from Exhibit 302, there is a major difference between the
23 indexed rates of return that result from using weighting
24 factors that are properly aligned with expected growth,
25
22 Idaho Powers 2006 IRP - Sales and Load Forecast pages 26-36
1083 YANKEL, DI 22Irrigators
.1 compared to the Company's Base Case study that does not
2 link marginal cost weighting factors with growth. The
3 indexed rates of return for the maj or rate schedules are
4 summarized below:
5 Study Res.S ch . 9 (s) S ch . 19 I r r .
6 Growth Corrected23 1.309 -0.173 -0.211 4.574
7 Company's Base Case24 1.231 1.011 0.789 0.505
8 Al though the difference between these two cost of service
9 runs is quite large for some rate schedules, it should
10 come as little surprise. It has been well recognized by
11 virtually all parties that the Company's present
12 allocation method does not properly address the cost of.13
14
growth and the fact that for at least twenty-five years
the Irrigators have been getting saddled with costs that
15 they have not placed upon the system. In fact, the
16 Irrigators have often gotten rate increases larger than
17 the system average.
18 By way of contrast, the Growth Corrected study
19 follows more intuitive logic. The growth on the system
20 over the last two-plus decades has not been even across
21 all classes. Irrigation load has been virtually flat,
22 Residential load has increased rapidly, but not as
23 rapidly as Commercial and Industrial load. Given the
24 growth in average system load25 of 20. 7% that is predicted.25 over the next ten years in the 2006 IRP, any rate group
1084 YANKEL, DI 23Irrigators
.
.
.
18
19
1 that would be growing less than the average should be
2 getting a smaller share (compared to its size) of the
3 marginal costs, while those growing faster should get a
4 higher percentage. The Irrigation growth is essentially
5 zero and Special Contract growth is less than the
6 average, so this Growth Correction increases the rate of
7 return for those classes over that produced by the
8 Company's Base Case study. Residential growth is about
9 the system average, so there is little impact of using
10 the Growth Corrected
11
12 /
13
14 /
15
16 /
17
20 23 Irrigation Exhibit 301, line 38.
24 Company Exhibit 55, page 1, line 52.
21 25 Idaho Powers 2006 IRP Sales and Forecast at page 36 shows sales in
2016 of 16,817 GWh compared to 13,938 GWh in 2006 for a difference of
22 20.7%.
23
24
25
1085 YANKEL, DI 23aIrrigators
.
.13
14
15
16
17
18
19
20
21
22
23
24.25
1 method compared to the Company's Base Case. The
2 Commercial and Industrial load growth is above average
3 system growth so the Commercial and Industrial customer's
4 rate of return is lowered. Gi ven the fact that the
5 Corrected Growth cost of service run recognizes the link
6 between growth and the growth related weighting factors,
7 the resulting indexed rates of return are quite logical:
8 .The Residential growth rate is somewhat less
9 than the system average; therefore, the indexed
10 rate of return goes up a little when compared
11 to the Company's Base Case.
12 .The Commercial growth rate is significantly
above system average; therefore, the indexed
rate of return for Schedule 9 significantly
drops when compared to the Company's Base Case.
.The Industrial growth rate is above system
average (but not as much as Commercial);
therefore, there is a substantial drop in the
indexed rate of return for Schedule 19 when
compared to the Company's Base Case.
.The Irrigation growth rate is essentially
non-existent; therefore, the indexed rate of
return goes up a great deal when few of the
growth related costs are allocated to it
compared to the Company's Base Case.
1086 YANKEL, DI 24Irrigators
1 Q.DO THE RESULTS OF THE COST OF SERVICE.2 STUDY IN EXHIBIT 302 REFLECT THE GROWTH DIFFERENTIAL THAT
3 IS ASSOCIATED WITH THE DISTRIBUTION SYSTEM?
4 A.No.Exhibit 302 only reflects changes to the
5 Company's cost of service study to reflect growth on the
6 Generation and Transmission system.Over the last 25
7 years,the growth in
8
9 /
10
11 /
12
13 /.14
15
16
17
18
19
20
21
22
23
24.25
1087 YANKEL,DI 24aIrrigators
.
.
.
1 Plant-in-Service associated with the Distribution system
2 has been greater than both thè Generation and
3 Transmission system. A methodology needs to be adopted
4 for addressing the growth on the Distribution system as
5 well. It should be remembered that not only have the
6 Irrigators had very little impact for the past 25-plus
7 years on the cost of the Company's distribution plant,
8 the Irrigators have virtually nothing to do with the
9 costs associated with the Company's Underground
10 Distribution costs.
11 Q.THE GROWTH FACTORS THAT YOU INPORPORATED INTO
12 THE COMPANY'S STUDY ARE BASED UPON ENERGY GROWTH AND NOT
13 DEMAND. is THIS A PROBLEM?
14 A.No. First, there is only energy data available
15 in the Company's 2006 IRP regarding forecast usage.
16 Admittedly, the use of forecast demand levels by rate
17 schedules would have a higher appeal, although not
18 necessarily be more accurate. If demand forecasts by
19 class become available, I have no problem substituting
20 that data.
21 Second, the impact of using demand as opposed
22 to energy values may give the appearance of being more
23 accurate, but in the overall scheme of things, growth in
24 energy and growth in demand are highly (although not
25 100%) correlated with each other. The fact that all
1088 YANKEL, DI 25Irrigators
.
.13
14
15
16
17
18
19
20
21
22
23
24.25
1 classes are undergoing significant growth, while the
2 Irrigator load is virtually stagnant, is the maj or factor
3 involved. Once this watershed difference is recognized,
4 the rest is simply icing on the cake.
5 Third, I am not making a proposal to right all
6 of the wrongs that have occurred over the last 25 years
7 because the Irrigators have been penalized for costs that
8 they did not cause. I am
9
10 /
11
12 /
/
1089 YANKEL, DI 25aIrrigators
.
.
.
1 simply trying to get recognition of the problem and begin
2 to make minor corrections as we continue to move through
3 a period of rapid growth on the system by most, but not
4 all, classes of customers.
5 Q.HOW SHOULD THE RESULTS OF EXHIBIT 302 BE
6 UTILIZED FOR PURPOSES OF THIS CASE?
7 A.The issue of addressing growth in the Company's
8 cost of service study is a new direction for the
9 Commission, and one that generally has not been faced by
10 other commissions across the country. As the Final
11 Report in the IPC-E-04-23 Workshop stated: "The parties
12 agreed that there was something inherently troubling with
13 the way costs, associated with growth, were allocated."
14 As recognized at the Workshop, the cost causation of
15 growth is indisputable and the lack of growth on the part
16 of the Irrigators is indisputable as well. Recognizing
17 that the Commission moves cautiously (but deliberately)
18 in these matters, I recommend that Exhibit 302 be used to
19 generally direct the Commission's ordered rate spread in
20 this case.
21 Q.BASED UPON THE GENERAL RESULTS OF EXHIBIT 302,
22 WHAT PORTION OF THE RATE INCREASE IN THIS CASE DO YOU
23 RECOMMEND FOR THE IRRIGATORS?
24
25
A.Over the last several rate cases, the
Irrigators have been given the same or a higher
1090 YANKEL, DI 26Irrigators
.
.
.-
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 percentage increase than the system average. These
2 increases have been given because the Company's
3 cost-of-service studies have never addressed the
4 disproportionate growth and
5
6 /
7
8 /
9
1091 YANKEL, DI 26aIrrigators
.
.
1 associated costs between the classes. There was no
2 growth on the part of the Irrigators to cause the costs
3 to be incurred that were associated with the rate
4 increases being sought. The following represents a brief
5 picture of the increases that have been given to the
6 Irrigators because this disproportionate growth and cost
7 causation has not been recognized:
8 Case #Order #Ave.Increase Irrigation Increase
07-08 30508 5.20%5.65%05-28 30035 3.20%3.20%03-13 29505 5.20%13.95%94-05 25880 4.19%10.23%
9
10
11
12 Over the last 10-plus years, the Irrigators have gotten
13 well over the average rate increase, in spite of the fact
14 that they have not been causing the growth and the need
15 for the rate increases on the system. Based upon the
16 greater than average increases which have been given to
17 the Irrigators in the past and the results of the simple
18 correction/alignment of marginal costs with the growth
19 causing those costs which demonstrates26 that the
20 Irrigators should be given a significant decrease in
21 rates; I reco~end that the Irrigators be given no
22 increase in this case. I recommend that the Residential
23 class be given the average rate increase, and that
24 Schedules 9 and 19 be given larger than average.25 increases.
1092 YANKEL, DI 27Irrigators
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11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Q.WHY SHOULD THERE BE ANY GROWTH ADJUSTMENT IN A
2 COST OF SERVICE STUDY WHEN EVEN WITH RATE SCHEDULES THERE
3 WILL BE SOME CUSTOMERS CAUSING THE GROWTH WHILE OTHERS
4 ARE NOT?
5 A.Just because one may not wish to set rates on
6 the basis of individual customers that are causing the
7 growth, this is no excuse for ignoring the larger picture
8 that significant
9
10 /
/
1093 YANKEL, DI 27aIrrigators
1 growth is taking place, and that growth is well defined.2 on a class or rate schedule level. Rates have always
3 been set for a group of similarly situated customers and
4 not on the particular characteristics of individual
5 customers, unless that customer was very large and
6 unique. It is also my understanding that there are
7 possible discrimination problems when seeking to charge
8 indi vidual customers wi thin a class different rates based
9 upon when they first took service. With respect to this
10 prohibition, I am not proposing a difference of rates
11 among individual customers within a class based on
12 growth, but the assignment of growth related costs to the.13 classes that are causing those growth related costs.
14 From that perspective, my adjustment is essentially the
15 same as that proposed by the Company when it used
16 marginal cost weighting factors in order to allocate
17 production and transmission plant.
18 Addi tionally, growth is not a simple question
19 of defining who are the new customers. Growth in load is
20 taking place both because of new customers as well as
21 because of increased usage by existing customers.
22 At this time, the Irrigators are looking for
23 some recognition by the Commission (as was given by the
24 Workshop from Case IPC-E-04-23) that there is "something.25 inherently troubling with the way costs, associated with
1094 YANKEL, DI 28Irrigators
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15
16
17
18
19
20
21
22
23
1 growth, were allocated." Some initial attempt to
2 recognize this problem in the allocation of revenue
3 requirement in this case would greatly move this
4 discussion forward, without causing a maj or disruption in
5 class revenue requirement in this case.
6
7 /
8
9 /
10
11 /
12
13
14
24 26 Exhibit 302 line 43.25
1095 YANKEL, DI 28aIrrigators
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.
1 IRRIGATION PEA RES PROGRA
2 Q.is THERE SOMETHING NEW HAPPENING WITH RESPECT
3 TO THE COMPANY'S IRRIGATION PEAK REWARDS PROGRAM?
4 A.Yes. The Company, Irrigators and the Staff
5 have been meeting to discuss possible improvements in
6 this program for the benefit of all. A new program,
7 modeled off of the "company option" load management
8 program in the PacifiCorp service area, will soon be
9 brought before the Commission with the hope of having the
10 program in place before the 2009 Irrigation Season. The
11 Irrigators are very supportive of this program as well as
12 the one offered in the PacifiCorp service area that
13 interrupts electricity to irrigation pumps at the
14 Company's option during the summer super-peak hours as
15 opposed to just on designated days of the week as the
16 current program does. The Irrigation Peak Rewards
17 Program is a workable program that produces tangible
18 benefi ts for the Company as well as all ratepayers.
19 Q.HOW MUCH BENEFIT CAN BE EXPECTED OUT OF THIS
20 NEW PEAK REWARDS PROGRA?
21 A.Both the Irrigators and the Company are hopeful
22 that this new "company option" program will be very
23 successful for the Irrigators and the system as a whole.
24 The PacifiCorp service area in Idaho has an Irrigation.25 load during the annual system peak of approximately 255
1096 YANKEL, DI 29Irrigators
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.13
14
15
16
17
18
19
20
21
22
23
24.25
1 MW. Under this new program PacifiCorp has signed up
2 approximately 215 MW of Irrigation load that it can
3 interrupt at any time (presumably at peak times for the
4 Company). PacifiCorp is still working with this program
5 in order to get the maximum benefit from it. Unlike the
6 previous
7
8 /
9
10 /
11
12 /
1097 YANKEL, DI 29aIrrigators
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.
.
1 program that PacifiCorp had or the Peak Rewards program
2 that Idaho Power presently has, interruptions are only
3 occurring when the Company needs the electricity and not
4 merely occurring because a clock states that the
5 designated day and designated time have arrived for an
6 interruption-irrespective of need. With PacifiCorp
7 having control over approximately 85% (215 MW / 255 MW)
8 of its Irrigation load, great strides can be made in the
9 reduction of costs and the reduction of peaking
10 resources.
11 According to Idaho Power's filing in this case,
12 the IPCo Irrigators' contribution to the annual
13 coincident peak is approximately 650 MW. I do not expect
14 to see 85% of the rpco Irrigation load on this new Peak
15 Rewards program, but if there was even 50% participation,
16 this would yield a peak reduction capability of 325 MW.
17 By comparison1 Idaho Power's present Peak Rewards program
18 has only been yielding approximately 40 MW of reduction
19 on a system where the Irrigation load is over 2.5 times
20 larger than that on the PacifiCorp system.
21 Q.WHAT BENEFIT DOES THE IRRIGATION PEAK REWARDS
22 PROGRAM PROVIDE TO THE SYSTEM?
23 A.On July 11, 2007 Quantec issued a Report to
24 PacifiCorp (Rocky Mountain Power) entitled "Assessment of
25 Long-Term, System-Wide Potential for Demand-Side and
1098 YANKEL, Dr 30Irrigators
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10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Other Supplemental Resources". This Report was designed
2 to (and virtually did) cover all aspects of DSM or
3 al ternati ve resources. The Irrigation Load Curtailment
4 program was viewed as one of only three "firm" DSM
5 options that represent a Class 1 resource. Of these
6 three Class 1 options, the Irrigation Load Curtailment
7 program had the lowest costs per unit of avoided capacity
8 and in fact these costs were calculated to be less
9
/
1099 YANKEL, DI 30aIrrigators
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.
19
20
1 than half of the cost of the next closest option (direct
2 load control of air conditioners). The Irrigation Load
3 Curtailment program was calculated to have an avoided
4 cost of capacity in the Rocky Mountain Power region of
5 $98/kW-year.
6 Q.HOW APPLICABLE TO IDAHO POWER IS THAT REPORT'S
7 AVOIDED CAPACITY FIGURE OF $98/KW-YEAR FOR ROCKY MOUNTAIN
8 POWER?
9 A.Al though these are different utili ties, they
10 operate in the same general market, and in this case,
11 both operate in southern Idaho. According to the
12 Company's 2006 IRP, the following resources are being
13 pursued with the associated costs:
14 $ /kW-month27
$5.53
$/kW-year
$6915
170 MW Simple Cycle CT
(non-fuel)
16 100 MW Wind $16.40 $197
17 50 MW Geothermal $33.68 $404
18 Expansion of DSM
Residential Existing Canst.
Commercial Existing Canst.
Industrial Efficiency
$64
$122
$123
$5.34
$10.15
$10.26
21 Based upon these options that IPCo is pursuing, the
22 $98/kW-year figure is a good representation of the
23 avoided cost of a program like the Irrigation Peak
24 Rewards program..25 Q.WHAT WILL BE THE COST OF THE NEW IRRIGATION
1100 YANKEL, DI 31Irrigators
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.
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16
17
18
19
20
21
22
1 PEAK REWARDS PROGRAM?
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
23 27 Levelized cost of generation taken from IPCo's 2006 IRP, Appendix
0, page 59. Levelized DSM costs taken from IPCo's 2006 IRP, pages 67
24 and 68.
25
1101 YANKEL, DI 31aIrrigators
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.
.
20
1 A.Because of the newness of the program, similar
2 data and calculations are not available. The credit to
3 be paid to participants in the new program will be
4 approximately $32 per kW. Of course there will be the
5 cost of the equipment, installation costs and some level
6 of ongoing O&M . Collectively, these costs should be
7 substantially below the $ 98 per kW benefit that was
8 calculated for a similar program for PacifiCorp. There
9 will be a large dollar benefit not only for the
10 Irrigators that participate, but for all customers on the
11 system.
12 Q.HAS THE COMPANY'S PEAK REWARDS PROGRAM
13 BENEFITED THE IRRIGATORS, BY WAY OF THE COMPANY'S COST OF
14 SERVICE STUDY IN THIS CASE?
15 A.Yes. The interruptibili ty of the Irrigators is
16 reflected in this case. If there was an interruption at
17 the time of any of the monthly peaks, there was an
18 attempt to reflect the level of that interruption in the
19 Company's cost of service study.
Q.IS THE COMPANY'S METHOD OF FLOWING THROUGH THE
21 LEVEL OF INTERRUPTIONS INTO THE COST OF SERVICE STUDY IN
22 THIS CASE APPROPRIATE?
23 A.The treatment of the level of interruptions in
24 this case, may have been appropriate for now, but these
25 methods will probably need to be adj usted for the future.
1102 YANKEL, DI 32Irrigators
1 Basically,the problem faced by the Company is that for.2 most classes it has load research meters that it uses to
3 gather data regarding what the peak contribution to
4 system peak is for customers wi thin a given
5
6 /
7
8 /
9
10 /
11
12
13.14
15
16
17
18
19
20
21
22
23
24
..25
1103 YANKEL,DI 32aIrrigators
1 sample. The problem with the Irrigators is that the.2 sample must not only represent the general population,
3 but it needs to represent the level of interruptions as
4 well. Under the existing Peak Rewards program there were
5 a host of interruption options and days during which an
6 Irrigator could be involved-all adding complexity. The
7 Company's solution to this problem thus far has been to
8 pullout of the load research data any customers that may
9 have been interrupted and then determine the level of
10 interruptions from other data.
11 If there is a large level of participation as
12 expected with the new program, the present scheme may not.13 work. Basically, such a large participation could wreak
14 havoc on the load research sample that was set up for
15 other purposes. Additionally, the new program is not
16 designed for Irrigation pumps less than 30 hp, which
17 would mean that all of the interruptible customers would
18 be in load research strata 2, 3, and 4, but not stratum
19 1. It is quite possible that for such a large level of
20 participation that the load research sample may need to
21 be redesigned in order to reflect two groups of
22 customers-interruptible and firm.
23 Q.WHY IS IT IMPORTANT TO LOOK AT COST OF SERVICE
24 RESULTS FROM A PROGRA THAT WILL NOT BE IMPLEMENTED UNTIL.25 NEXT YEAR?
1104 YANKEL, DI 33Irrigators
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.
20
21
22
23
24.25
1 A.Rates set in this case will be implemented in
2 the future. Gi ven the seasonality of the Irrigation
3 load, these rates will be implemented for them at the
4 same time as the new Peak Rewards program will be
5 implemented. Normally, test year loads and costs are
6 used as the basis for setting future rates. However,
7 "normally" implies that the past (test year) will be a
8 reflection of the future when rates are in effect. As
9 was addressed above, "normally" does not properly address
10 the fact that the Irrigation load is not causing growth
11 and the costs associated with that
12
13 /
14
15 /
16
17 /
18
19
1105 YANKEL, DI 33aIrrigators
.
.
.
1 growth. Likewise, "normally" does not address the
2 watershed change in Irrigation load that will take place
3 under the new Peak Rewards program.
4 Q.WHAT WOULD BE THE IMPACT OF A 50% REDUCTION IN
5 SYSTEM PEAK CONTRIBUTION IN THIS CASE IF THE NEW PEAK
6 REWARDS PROGRAM HAD BEEN IN EFFECT FOR THE TEST YEAR?
7 A.The exact impact would be difficult to
8 calculate because there are a lot of assumptions that
9 would need to be made with respect to what impact the
10 operation of this new Peak Rewards program would have
11 upon the overall system load. It would have impacted the
12 time and date of the monthly peaks-and the resulting
13 class contributions to those peaks as they vary by day
14 and hour of the day. For purposes of estimating the
15 impact of the new Peak Rewards program during the test
16 year, I have simply assumed that the Irrigation peak
17 contribution is cut in half for the months of June and
18 July (the only two months when the new peak rewards
19 program will be operating).
20 Exhibit 303 contains a summary page of the cost
21 of service results under the Company's base case and
22 assuming that the Irrigation peak contribution to the
23 June and July system peaks were cut in half. As can be
24 seen from Exhibit 303, the Irrigation rate of return has
25 been increased from 3.36% in the Company's base case up
1106 YANKEL, DI 34Irrigators
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11 /
12.13
14
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17
18
19
20
21
22
23
24.25
1 to 5.12%, just below the system average of 6.61%.
2 Exhibit 304 contains a similar summary page that is the
3 cost of service result based upon the same assumptions
4 regarding the impact of the Irrigation Peak Rewards
5 program, but using the Company's new/preferred 3CP/12CP
6
7 /
8
9 /
10
1107 YANKEL, DI 34aIrrigators
.
.
.
1 cost of service study. As can be seen from Exhibit 304,
2 the Irrigation rate of return has been increased up to
3 6.19%, just below the system average of 6.61%.
4 Q.HOW DO THE EXPECTED RESULTS OF THE COMPANY'S
5 COST OF SERVICE STUDIES REFLECT HOW COSTS SHOULD BE
6 ALLOCATED TO THE IRRIGATORS IN THIS CASE?
7 A.The Irrigation load is seasonal and thus, rates
8 in this case for the Irrigators will be implemented next
9 year-the same time that the new Peak Rewards program will
10 be implemented. Rates for the Irrigators (like other
11 classes) should be implemented in a manner that reflects
12 expectations at the time of implementation. The
13 Irrigation load will be substantially different in 2009
14 and rates should attempt to reflect that difference.
15 Implementation of the new Peak Rewards program will
16 essentially put the Irrigators at the system average cost
17 of service (absent any recognition for the negative
18 impact that the 25 years of disproportionate growth has
19 had on the Irrigators). Based simply on the adoption of
20 the new Peak Rewards program (that does not have to be
21 anywhere near as successful as the results obtained for
22 PacifiCorp), the Irrigators should get no more than the
23 system average rate increase.
24
25
1108 YANKEL, DI 35Irrigators
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1 SALES FOR RESALE AN PURCHASED POWER
2 Q.HOW HAVE SALES FOR RESALE REVENUES AND
3 PURCHASED POWER COSTS BEEN TRADITIONALLY ALLOCATED?
4 A.Tradi tionally, Sales For Resale revenues and
5 Purchase Power costs are classified and allocated as
6 ei ther demand or energy related. For purposes of this
7 case, the Company has classified all of the Idaho
8 jurisdictional Sales For Resale revenue and all Wholesale
9 Purchase Power (non-cogen) as energy related. Thus the
10 Sales For Resale revenue and Wholesale Purchase Power
11 expense are presently being allocated to individual rate
12 schedules based upon the energy allocator associated with
13 each rate schedule. This is a simplistic approach that
14 has generally been used (either the generation level
15 demand or energy allocator) around the country for as
16 long as I am aware.
17 Q.HOW MANY DOLLARS ARE AT STAKE WITH RESPECT TO
18 SALES FOR RESALE REVENUE AND WHOLESALE PURCHASED POWER
19 COSTS?
20 A.In this case for the Idaho jurisdiction there
21 is $104 million associated with Sales For Resale and $58
22 million associated with Wholesale Purchase Power costs.
23 These revenues and expenses are 100% allocated on the
24 basis of annual energy usage-the same as fuel. If the.25 Company would have classified some or all of these
1109 YANKEL, DI 36Irrigators
1 revenues and/or costs on the basis of demand,they would.2 have then been allocated on the generation level system
3 demand allocator that is used to allocate plant.
4
5 /
6
7 /
8
9 /
10
11
12.13
14
15
16
17
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20
21
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23
24.25
1110 YANKEL,DI 36aIrrigators
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.
.
1 Using the Company's energy allocation factor of 11.74%28,
2 the Irrigators are given $12,264,00029 of the Sales for
3 Resale revenue and $6,808,00030 of the Wholesale Purchase
4 Power costs. The net benefit to the Irrigators (using
5 the annual energy allocator) of this revenue, less
6 expense, is $5,456,000.
7 Q. YOU REFER TO THE TREATMENT OF THESE REVENUES
8 AND COSTS AS A SIMPLISTIC APPROACH. WHY IS THIS APPROACH
9 SIMPLISTIC?
10 A.Most individuals involved with utility
11 ratemaking try to assign/allocate costs in a manner that
12 they believe reflects cost causation. However, the
13 allocation of these revenues and/or costs on the basis of
14 annual energy usage or system demand, defies the
15 principle of cost causation. The allocation of Sales For
16 Resale revenues or Purchase Power costs on the basis of
17 annual energy usage or system demand allocators has been
18 done over the years for the sake of convenience. This
19 "convenience" has its roots in the historic inability to
20 come up with a straight-forward method that reflects cost
21 causation. With today' s data bases and computing
22 capabili ties, what once was impossible to establish can
23 now be readily developed.
24 Q.WHY DOES THE ALLOCATION OF SALES FOR RESALE
25 REVENUE OR PURCHASED POWER EXPENSE ON THE SIMPLE BASIS OF
1111 YANKEL, DI 37Irrigators
1 ANNUAL ENERGY OR DEMAND,DEFY COST CAUSATION?.2
3 /
4
5 /
6
7 /
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23 28 See Tatum Exhibit 59 page 5 of 6.
29 $104,466,000 x 0.1174 = $12,264,000
24 30 $57,989,000 ~ 0.1174 = $6,808,000.25
1112 YANKEL, DI 37aIrrigators
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.
.
1 A.A simple example can demonstrate the disconnect
2 between these allocation factors and cost causation.
3 Assume that a utility has customer Class "A" that uses
4 500 MWh and only 500 MWh every hour of the year and a
5 second customer Class B that uses 500 MWh every hour for
6 only six months and zero for the other six months. To
7 keep the example simple, assume that this utility has
8 Sales for Resale when customer Class "B" is not taking
9 energy of 500 MWh during each remaining hour of the year.
10 Thus, the utility has a completely flat load of 1,000 MWh
11 during each hour of the year. Ignoring reserves and
12 other requirement, this simple utility could get along
13 with 1,000 Mw of capacity and simply run flat-out. Who
14 should get what percentage of the Sales For Resale
15 revenue (less associated expense)?
16 The historic way of allocating these costs
17 would be based upon either the annual energy or demand
18 allocator. However, annual usage has nothing to do with
19 this sale. The sale was brought about because Class B
20 was not utilizing the plant dedicated to it. Class A had
21 little or nothing to offer as it was using the same
22 amount of energy every hour of the year. It is this
23 disconnect between how the sale is made possible in the
24 first place and how these revenues have been
25 traditionally. allocated. The cost causation in this case
1113 YANKEL, DI 38Irrigators
.1 is that Sales For Resale revenues were obtained because
2 of what was occurring during each hour, compared to how
3 much plant was available to generate the Sale For Resale
4 as opposed to supplying Class A or Class B.
5 Q.USING THIS SIMPLE EXAMPLE, WHAT WOULD BE A
6 BETTER WAY TO ALLOCATE THESE SALES FOR RESALE REVENUES?
7 A.Assume that a 12 CP method is used to allocate
8 generation plant. Under the above assumptions, Class A
9 gets 2/3rd of the generation demand allocator and Class B
10 gets 1/3rd.
11
12 /.13
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16 /
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18
19
20
21
22
23
24.25
/
1114 YANKEL, DI 38aIrrigators
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1 Note, I am not advocating any particular allocation
2 method. The example I am developing is independent of
3 the allocation method used.
4 How should Sales For Resale revenue be
5 allocated? The conventional way to allocate would be to
6 give 2/3rd of these revenues to Class A. However, it is
7 the freed up capacity at the time of the sale that
8 creates the basis (cost causation) for the sale. During
9 anyone hour of the year, 2/3rd of the plant is allocated
10 to Class A-because Class A is paying for it. During any
11 of the hours when the sale is made, Class A "owns" 66.7%
12 of the generation plant and is using 50% of it. Thus,
13 Class A is using only 50% of the actual generation while
14 it has 16. 7 % (or 167 Mw) that it is paying for available
15 to support the sale. Likewise, Class B is allocated 33%
16 of the plant and pays for 33% of the plant. During the
17 sale,Class B is not taking any energy so its entire 33%
share or 333 Mw is available to support the sale.Thus,
Class B should get the revenue associated with 333 Mw and
Class A should get the revenue associated with 167 Mw.
Class B gets 67%of the revenue (333 /500 =67% )and
18
19
20
21
22 Class A gets 33% (167 / 500 = 33%). Under the
23 simplistic/traditional approach, Class A would have
24 inappropriately gotten twice as much of the Sales for
25 Resale revenue. The above example only addresses
1115 YANKEL, DI 39Irrigators
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15 /
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17
18
19
20
21
22
23
24.25
1 assignment of plant at the time of the sale, not at other
2 times or related costs.
3 Q.PLEASE GIVE A HIGH LEVEL VIEW OF THE PROPOSAL
4 YOU ARE MAKING FOR THE TREATMENT OF SALES FOR RESALE
5 REVENUE AND PURCHASED POWER COSTS.
6 A.The Company has provided three cost of service
7 studies in this case. Other intervenors may develop
8 studies of their own. They will all likely have
9 different system
10
11 /
12
13 /
1116 YANKEL, DI 39aIrrigators
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.
.
1 allocators. For purposes of assigning/allocating Sales
2 For Resale revenues and Purchase Power costs, a separate
3 study must be conducted outside of the cost of service
4 study. That study should use actual hourly energy data
5 for individual rate schedule usage, system generation,
6 Sales For Resale, and Purchase Power.
7 The energy generated by the system varies by
8 hour (because of high or low load, maintenance, low
9 wholesale prices, etc.). Each rate schedule is not
10 assigned/allocated a specific level of megawatts or
11 specific plant, but a percentage share of the energy
12 generated that is being utilized during any given hour.
13 The percentage of energy generated each hour for a given
14 rate schedule would remain the same. Once again, I am
15 not advocating a specific allocator, merely keeping the
16 allocator consistent with the allocator used to assess
17 (not allocate) Sales For Resale revenue.
18 The assignment of generation output would then
19 be matched with the hourly usage for the individual rate
20 schedule. This hourly usage would come from the load
21 shape defined by the Company's Load Research data as
22 calibrated by the actual monthly consumption levels in
23 order to correct for any bias in the data.'
24 If the hourly usage for a given rate schedule
25 was greater than its allocated share of generation during
1117 YANKEL, DI 40Irrigators
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19
20
21
22
23
24
25
1 that hour, then the shortfall would be made up with
2 "purchased power". Likewise, if the hourly usage was
3 less than the allocated share of generation plant during
4 that hour, the excess would be offered up as Sales For
5 Resale. In reality not all of this excess will be used
6 as Sales For Resale, because some of it will go to offset
7 the amount where other rate schedules were short of
8 generation and needed to "purchase" their additional
9 needs. However, just like when a sale occurs, the rate
10 schedules that have the excess during a time of need
11 should be fully compensated for that excess that would
12 otherwise need to be purchased.
13
/
1118 YANKEL, DI 40aIrrigators
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.
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1 Q.CAN YOU PROVIDE A MORE DETAILED EXAMPLE USING
2 ACTUAL LOAD DATA FROM 2007?
3 A.Yes. Using data for the Irrigation class for
4 May 7, 2007 at 7: 00 and 8: 00 a.m. a table can be
5 constructed that demonstrates both how to account for a
6 class having too much generation available as well as too
7 little. During the 7:00 a.m. hour there was only 1,332
8 MWh of company generation being produced. Based upon the
9 Irrigators 14 ~ 58% share31 of system generation costs
10 (D10), the Irrigators have a callan 194 MWh32 during that
11 hour. The Irrigation load is only 187 MWh during that
12 hour so the Irrigators have an excess of 7 MWh of
13 generation that they are not using. During that hour,
14 the average price of purchased power was $38.62 per MWh.
15 The Irrigators should be credited with $278 (7.20 x
16 $38.62 = $278) associated with this load that could have
17 been" sold" to other rate schedules (or simply reduced
18 purchased power by this amount).
19
20
21
22
23
24
25
HR7 HR8
Generation MWH 1,332 1,368Irr.Allocation 14.6%14.6%Irr.Generation
MWH 194 199
Irr.Load MWH 187 204
Excess Load
MWH -7 5
P.P.Rate $/MWH $38.62 $39.95
P.P.Cost $-$278 $180
1119 YANKEL, DI 41Irrigators
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13
14
15
16
17
18
1 The 8: 00 a.m. hour works the same way, but in
2 this case, the Irrigation load of 204 MWh is more than
3 the 199 MWh the Irrigators can claim based upon their
4 percentage of the amount of
5
6 /
7
8 /
9
10 /
11
12
19 31 See Tatum Exhibit 59, page 1 of 6.
321,332 MWh x 0.1458 = 194 MWh.
20
21
22
23
24
25
1120 YANKEL, DI 41aIrrigators
.1 energy (generation plant) that is being produced at that
2 hour. Therefore, 5 MWh have to be "purchased" for the
3 Irrigators at a cost of $180. Thus, during some hours
4 there is a credit, and other hours there is a cost,
5 however, in no hour do the Irrigators simply get
6 allocated revenues and costs based upon their relative
7 share of annual usage.
8 Q.HAVE YOUR ANALYZED THE IRRIGATION LOAD DURING
9 ALL OF 2007 IN ORDER TO DETERMINE THE IMPACT OF PROPERLY
10 ALLOCATING SALES FOR RESALE REVENUE AND PURCHASED POWER
11 COSTS?
12 A.Yes. I have analyzed every hour of the year in.13 the same manner as demonstrated above for May 7, 2007.
14 As would be expected, the Irrigation load generally
15 required during every hour of the summer months
16 (May-September) that electricity be purchased as the
17 allocation of 14.58% of the generation plant operating
18 during any single hour was not sufficient to supply all
19 of the Irrigation needs during that hour. Thus, most of
20 the Purchase Power that was assigned/allocated to the
21 Irrigators was done during the 5-summer months and at the
22 summer purchased power prices. Likewise, the Irrigation
23 usage was quite low during the other seven months of the
24 year. Thus, most of the Sales For Resale that was.25 assigned/allocated to the Irrigators was done during the
1121 YANKEL, DI 42Irrigators
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10 /
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
1 7-winter months and at these Fall, Winter, and Spring
2 prices. When off-setting all of the Purchase Power costs
3 wi th the Sales For Resale revenues, the Irrigators came
4 out ahead by $5.8 million:
5
6 /
7
8 /
9
1122 YANKEL, DI 42aIrrigators
.
.
.
1 J
F
M
A
M
J
J
A
S
o
N
D
$11,201,602
$9,185,196
$6,944,090
$2,514,395
-$7,653,643
-$12,110,793
-$16,972,610
-$13,595,024
-$2,129,092
$7,928,012
$9,066,863
$11,459,272
$5,838,269
2
3
4
5
6
7
8 Q.THE RESULTS OF ALLOCATING THESE REVENUES AND
9 EXPENSES ON AN HOURLY BASIS (TAKING INTO ACCOUNT THE
10 IRRIGATOR'S UNUSED OR OVER USED GENERATION ASSIGNMENT)
11 DID NOT PRODUCE A RESULT THAT WAS SIGNIFICANTLY DIFFERENT
12 THAN THE SIMPLISTIC ALLOCATION USED BY THE COMPANY. WHY
13 IS IT IMPORTANT TO PURSUE THIS MORE RIGOROUS ANALYSIS?
14 A. The Company's Sales For Resale and Purchase
15 Power figures are based upon normalized data and produce
16 a net benefit of these revenues and expenses to the
17 Irrigators of $5.5 million. The analysis I performed
18 above produced a net benefit of $5.8 million, but it was
19 based upon actual Irrigation usage levels during 2007
20 which (because of the hot, dry summer) were about 10%
21 greater than normal33. This means that my analysis called
22 upon Company generation 10% more than normal and thus,
23 resulted in much higher Purchase Power costs and lower
24 Sales For Resale revenues for the Irrigators. If the
25 same analysis were to be performed
1123 YANKEL, DI 43Irrigators
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5 /
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7 /
8
9
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12.13
14
15
16
17
18
19
20
21
22
23
24 33 The FERC Form 1 list Irrigation usage at 1,924,000 MWh in 2007 or.about 18% higher than the 1,635,000 MWh in 2006.
25
1124 YANKEL, DI 43aIrrigators
.
.
1 with 10% less summer usage, the resulting benefit to the
2 Irrigators would have been $10.2 million greater at $16.0
3 million:
4 J
F
M
A
M
J
J
A
S
o
N
D
$11,201,602
$9,185,196
$6,944,090
$2,514,395
-$6,227,134
-$10,123,050
-$14,018,817
-$11,079,392
-$863,318
$7,928,012
$9,066,863
$11,459,272
$15,987,719
5
6
7
8
9
10
11 This increase in benefit of $10.2 million is
12 approximately equal to the disproportionately large
13 increase in rates that the Company has proposed for the
14 Irrigators in this case.
15 Q.WHAT ARE YOUR RECOMMENDATIONS REGARDING THE
16 TREATMENT OF SALES FOR RESALE REVENUES AND PURCHASED
17 POWER COSTS IN THIS CASE?
18 A.I have already made one recommendation
19 regarding the spread of rates to the Irrigators in this
20 case-based upon the disproportionate growth and cost
21 impact of that growth, the Irrigators should get no
22 increase in this case. I am of the opinion that the
23 Commission will get a number of proposals in this case to
24 change some allocation methods to "better reflect".25 seasonali ty. I want the Commission to be aware that one
1125 YANKEL, DI 44Irrigators
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.
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24
25
1 of the largest shortcomings in the Company's cost of
2 service study is not the large marginal cost weighting
3 that it already places upon seasonal allocation of
4 generation plant and costs. If other parties wish to
5 address or investigate any perceived seasonality
6 problems, I recommend that the investigation begin
7
8 /
9
1126 YANKEL, DI 44aIrrigators
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.
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17
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19
20
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22
23
24
25
1 with which rates schedules are using Purchase Power and
2 when. Likewise, the investigation should address which
3 rate schedules should benefit from which Sales For
4 Resale. Simply broad brushing these revenues and
5 expenses on the basis of annual usage or some perceived
6 weighting, when hourly information is available, is not
7 acceptable. I recommend that detailed cost causation
8 analysis be done as opposed to general theories being
9 espoused.
10 Q.DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
11 A.Yes.
12
13
1127 YANKEL, DI 45Irrigators
.
.
.
10
1 Q.PLEASE STATE YOUR NAME, ADDRESS, AND
2 EMPLOYMENT.
3 A.I am Anthony J. Yankel. I am President of
4 Yankel and Associates, Inc. My address is 29814 Lake
5 Road, Bay Village, Ohio, 44140.
6 Q.ARE YOU THE SAME ANTHONY J. YANKEL THAT
7 PREVIOUSLY FILED DIRECT TESTIMONY IN THIS CASE?
8 A.Yes.
9 Q.WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY?
A.I wîii address the cost allocation and revenue
11 spread testimonies of Staff witnesses Hessing and Lobb as
12 well as intervenor witnesses Peseau and Reading. More
13
14
specifically, I will address the fact that although these
wi tnesses expressed recognition of the general impact of
15 growth on Idaho Power's cost of service results, they
16 made no adj ustments for growth impacts, and in fact,
17 allocated costs and proposed rate increases to the
18 Irrigators that completely ignores the impact of
19 disproportionate growth on the system.
20 As a part of my rebuttal testimony, I will
21 present a simple example of the impact of
22 disproportionate growth on the accuracy of the Company's
23 class cost of service study. This example will
24 demonstrate that disproportionate growth by the
25 Residential class not only provides an inappropriate
1128 YANKEL, RE 1Irrigators
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10 /
11
12.13
14
15
16
17
18
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22
23
24.25
1 negati ve impact on a class such as the Irrigators that is
2 not growing, but it also results in far less of an
3 increase to the Residential class than it would otherwise
4 recei ve if the
5
6 /
7
8 /
9
1129 YANKEL, RE 1aIrrigators
.
.
.
1 price signal were sent to the class that is growing.
2 This result is counterintui ti ve on its face. A cost of
3 service study that produces such inappropriate results is
4 wholly inadequate for defining cost of service, and thus
5 revenue requirement, when there is such a disparity in
6 the rate of growth between customer classes. The
7 Commission needs to address these inadequacies before it
8 considers a disproportionate rate increase for classes
9 that are not growing, while not giving disproportionately
10 large increases to classes that are growing and thus
11 causing the majority of the new costs that are being
12 incurred by Idaho Power.
13 HYPOTHETICA EXALE
14 Q.PLEASE SET THE STAGE FOR YOUR REBUTTAL
15 TESTIMONY BY DESCRIBING THE EXAMPLE THAT YOU WILL PRESENT
16 TO DEMONSTRATE THE IMPACT OF DISPROPORTIONATE GROWTH ON
17 THE RELIABILITY OF THE COMPANY'S CLASS COST OF SERVICE
18 STUDY.
19 A.The illogical impact calculated by the
20 Company's cost of service study due to disproportionate
21 growth can easily be demonstrated by the hypothetical
22 example presented by Staff witness Hessing in his
23 rebuttal testimony in the Idaho Power's last rate case
24 (IPC-E-07-8). I will present the same example in this
25 case, only slightly modified by the data for this case.
1130 YANKEL, RE 2Irrigators
1 Q.PLEASE PROVIDE YOUR ASSUMPTIONS AND EXPLAIN HOW.2 THEY COMPARE TO MR. HESSING'S ASSUMPTIONS IN THE LAST
3 CASE.
4
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6
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8
9 /
10
11
12.13
14
15
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18
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20
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23
24.25
1131 YANKEL, RE 2aIrrigators
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24
25
1 A.I will make the following assumptions in
2 conformance with Mr. Hessing's prior example:
3 1 )I used the same 250,000 MWh growth in
4 annual residential load at the generation
5 level as did Mr. Hessing in the last case.
6 It should be noted that this figure is
7 similar to the normalized Idaho
8 jurisdictional load that increased 251,792
9 MWh between this case and the last case.
2 )The power supply costs to serve the
additional load were 56.48 $/MWh1.
Therefore, the additional cost of power
supply is $14,120,000 (250,000 x 56.48).
In the last case, Mr. Hessing used a power
supply cost of 62. 79 $ /MWh.
3 )Like Mr. Hessing, I put all of these costs
under Purchase Power, booked to Account
555.1.
4.Like Mr. Hessing, I grew residential
monthly energy and demand amounts in
proportion to the normalized amounts.
This allowed the calculation of new
allocation factors for all classes (E10,
D10, D13, D20, D30, D50, and D60). Mr.
Hessing only calculated new allocation
1132 YANKEL, RE 3Irrigators
.
.
.
15 /
16
17
18
19
20
21
1 factors for E10, D10, and D13, thus my
2 study assigns more cost to the Residential
3 customers.
4 5.Residential usage at Sales level was
5 90.03% of the generation level growth in
6 load due to deli very losses. 2 Thus, the
7 additional Residential sales were 225,083
8 MWh at Sales level. Mr. Hessing used
9 89.1% in the last case.
10
11 /
12
13 /
14
22 1 See Company Exhibit 50 in this case for the annual Marginal Cost of
Energy for 2008.
23 2 Company Exhibit 68 page 5 lists Residential Generation load at
5,625,931 MWh and Company Exhibit 70 page 1 lists Residential Sales
24 load at 5,065,087 MWh. Thus, Sales level is 90.03% (5,065,087/
5,625,931) of Generation level.
25
1133 YANKEL, RE 3aIrrigators
.
.
.
15
16
17
1 6 )I assumed that the increased retail
2 revenue associated with the additional
3 Residential sales occurred at 62.77 $/MWh,
4 which is the current average residential
5 revenue per MWh3. The increased
6 Residential revenue associated with the
7 load growth is $ 14,128,460 (62.77 x
8 225,083) .
9 7 )Mr. Hessing ran his hypothetical example
10 using the Company's "Base Case" cost of
11 service study, which he supported using in
12 the last case. In this case Mr. Hessing
13 is supporting the use of the Company's
14 3CP /12CP method. For that reason, I ran
this hypothetical example using the
3CP /12CP cost study.
Q.HAVE YOU PREPARED AN EXHIBIT SHOWING THE
18 RESULTS OF THIS HYPOTHETICAL DISPROPORTIONATE GROWTH IN
19 RESIDENTIAL LOAD?
20 A.Yes, I have prepared Exhibit 306 which is a
21 summation of the changes in the main cost categories for
22 the larger rate schedules and the special contract
23 customers that occurred between the Company's filed
24 3CP/12CP study and using the above assumptions showing an
25 increase in usage to the Residential class only. This
1134 YANKEL, RE 4Irrigators
.
.
.25
1 example is designed to demonstrate the impact that
2 disproportionate growth has on the Company's cost of
3 service study results. Contrary to what everyone knows
4 regarding the fact that growth is causing a severe cost
5 burden to the system, the Company's cost of service study
6 calculates that the Residential class should get a
7 decrease in its revenue requirement because of this
8 hypothetical addition of 250,000 MWh of load. Because
9 the Company's cost of service study does not properly
10 recognize the cost of
11
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
3 See Company Exhibit 70, page 1.
1135 YANKEL, RE 4aIrrigators
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.
.
1 this hypothetical growth, the Company's cost of service
2 study calculates a need to decrease the Residential
3 revenue requirement by $3.3 million or 1% of its revenue
4 requirement. However, under the Company's cost of
5 service study all of the other maj or customer groups and
6 special contract customers that did not grow have to have
7 their revenue requirements increased in order to offset
8 the reductions that is calculated for the Residential
9 class. The change in revenue requirement based upon this
10 hypothetical increase in Residential sales is as follows:
11 Residential (1)
General Service (9)
Large Power (19)
Irrigation (24)
DOE/INL
Simplot
Micron
$ -3,299,1521,334,757
972,094
302,580
114,523
102,014
368,166
12
13
14
15 Q.COULD THE INAPPROPRIATENESS OF THE ABOVE
16 RESULTS BE CHANGED IF THE IMPACT ON TRANSMISSION AND
17 DISTRIBUTION COSTS WERE ALSO CONSIDERED?
18 A.No. The only thing that the introduction of
19 additional transmission and distribution costs
20 (associated with the growth) would have would be that on
21 a total system basis, the Company's overall revenue
22 requirement would be shown to increase because of the
23 cost of that growth. Unfortunately, the Company's cost
24 of service study would spread those additional
25 transmission and distribution costs to all customer
1136 YANKEL, RE 5Irrigators
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.
.
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
1 groups (including those that did not cause the costs to
2 be incurred). The overall result would be the
3 same-customer classes that were not growing would be
4 given some of the cost responsibility that rightfully
5 belongs to the customer group (s) that is growing and
6 causing the costs increase.
7
8 /
9
1137 YANKEL, RE 5aIrrigators
.
.
.
1 Q.WHAT CAN BE CONCLUDED FROM THE ABOVE EXAMPLE
2 REGARDING THE IMPACT OF DISPROPORTIONATE GROWTH AS
3 CALCULATED FROM THE COMPANY'S COST OF SERVICE STUDY?
4 A.Al though the Company's cost of service study
5 may be adequate for calculating relative cost causation
6 in a static environment or where growth is relatively
7 even between customer groups, it is wholly inadequate for
8 addressing the differences in cost causation when the
9 growth rate is different between customer groups. In
10 fact, the Company's cost of service study is very capable
11 of calculating illogical results when the growth rate is
12 uneven. With respect to the Irrigation class, the growth
13 rate on the Idaho Power system has been uneven for at
14 least the last 25 years.
15 Q.IN THE PAST IT HAS BEEN SUGGESTED THAT THE
16 SUPREME COURT HAS PROHIBITED THE CHARGING OF DIFFERENT
17 RATES TO CUSTOMERS BASED UPON WHEN THE CUSTOMER FIRST
18 STARTED TAKING SERVICE. DOES YOUR PROPOSAL GO AGAINST
19 THIS PRINCIPLE?
20 A.No. My proposal is not to treat customers
21 differently, but to fix the Company's cost of service
22 study so that it does not produce illogical results with
23 respect to the disproportionate growth on the system.
24 The Company has proposed for years, and the Commission
25 has generally accepted, allocation factors that include
1138 YANKEL, RE 6Irrigators
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.
.
10
11
12
13
14
15
16
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19
20
21
22
23
24
25
1 some form of weighting for marginal system costs. My
2 proposal is similar, in that it is to develop allocation
3 factors that
4
5 /
6
7 /
8
9 /
1139 YANKEL, RE 6aIrrigators
.
.
.
1 reflect the marginal usage (growth) on the system and to
2 allocate costs according to the classes causing the
3 growth (marginal cost).
4 TESTIMONY OF OTHER WITNSSES
5 Q.WHAT is THE STAFF'S OVERALL POSITION REGARDING
6 THE COMPANY'S COST OF SERVICE STUDY IN THIS CASE?
7 A.The Staff's overall position is that the
8 3CP /12CP cost of service study proposed by the Company
9 reasonably allocates costs to the various classes. Staff
10 wi tness Lobb states4:
11 Specifically, the recommended cost of service study
provides a more accurate allocation of production12 costs based on how production plant is used, when it
is used and the value of the plant at the time it is13 used.
14 As demonstrated in the example provided above, the
15 Company's cost of service study may accurately allocate
16 costs on a static basis, but it is incapable of
17 accurately reflecting cost causation in a situation where
18 growth is disproportionate-a situation that has existed
19 for years.
20 Q.DOES THE STAFF ADDRESS THE FLAWS IN THE
21 COMPANY'S COST OF SERVICE STUDY?
22 A.No. After making the above statement that the
23 Staff found the Company's 3CP/12CP study to provide a
24 more accurate allocation of costs, Staff witness Lobb
25 goes on to states:
1140 YANKEL, RE 7Irrigators
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.
18
19
20
21
22
23
24.25
1 Wi th respect to revenue spread among the classes,
Staff believes that cost of service is an inexact
science to be used as a guide in setting class
revenue
2
3
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
4 See Direct Testimony of Randy Lobb, page 19, lines 14-17.
4 See Direct Testimony of Randy Lobb, page 19, lines 18-23.
1141 YANKEL, RE 7aIrrigators
.
.
1
2
requirements. That is why Staff witness Hessing
uses cost of service in his proposal to move toward,
but not all the way to, cost of service as indicated
by the study. (Emphasis added)
3
4 Although the Staff recognizes that cost of service is "an
5 inexact science", it does not go so far as to recognize
6 that, with respect to disproportionate growth, that the
7 Company's cost of service study produces counterintui ti ve
8 resul ts. Furthermore, the Staff's limitations on the
9 increase to the various classes is not based upon the
10 inexactness of the study, but the concept of
11 gradualism-the Staff is willing to use the "inexact"
12 study as the target to which rates should be directed.
13 As pointed out in the above example, the Company i s cost
14 of service study is not only inexact, but it produces
15 illogical results with respect to disproportionate growth
16 on the system.
17 Q.DOES STAFF WITNESS HESSING'S TESTIMONY ADDRESS
18 THE DISPROPORTIONATE GROWTH ON THE SYSTEM OR ITS IMPACT
19 UPON COST OF SERVICE TO THE VARIOUS CUSTOMER CLASSES?
20 A.Al though Staff witness Hessing recognizes the
21 disproportionate growth that is taking place on the
22 system, his recommendation regarding rate spread does not
23 take these factors into account. As a matter of fact,
24 Mr. Hessing simply discounts the impact of.25 disproportionate growth. Mr. Hessing recognizes the
1142 YANKEL, RE 8Irrigators
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.
.
14
15
16
17
18
19
20
21
22
23
24
25
1 disproportionate growth and the cost of that growth when
2 he states6:
3 There are a number of circumstances that have caused
changes in cost of service results. Load growth,
substantially in the residential class, has occurred
in record amounts.
4
5
6 /
7
8 /
9
10 /
11
12
13
6 See direct testimony of Keith Hessing beginning at page 9 line 23.
1143 YANKEL, RE 8aIrrigators
.
.
.25
1 However, in spite of recognizing the disproportionate
2 rate of growth between the Residential class and all
3 other classes (let alone the Irrigation class which is
4 simply not growing), he does not acknowledge that the
5 cost of service study that the Staff endorses produces
6 counterintui ti ve results with respect to disproportionate
7 growth-charging non-growing customer classes for the
8 growth and the cost of growth of other classes. However,
9 this counterintui ti ve result is exactly what his Exhibit
10 124 in the last case showed. Instead, he states?:
11 No customer class is entitled to rates based on agrandfathered share of old costs.
12
13 The Staff's emphasis is misplaced, as demonstrated by the
14 example I provided earlier and Mr. Hessing providing in
15 the last case. The cost of service study is completely
16 inadequate when it takes costs that are solely incurred
17 for a given class and not only allocates those cost to
18 other classes, but then calls for a rate decrease for the
19 class that is causing the costs to be incurred in the
20 first place.
21 Q.WHAT DOES THE STAFF TESTIMONY SAY WITH RESPECT
22 TO THE NEED TO SEND APPROPRIATE PRICE SIGNALS TO
23 CUSTOMERS?
24 A.Staff witness Lobb addresses price signals to
customers in his testimony8:
1144 YANKEL, RE 9Irrigators
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.
20
21
22
23
1
2
Staff's policy with respect to rate design is tobalance the need to send appropriate price signals
wi th the need to have relatively stable rates and
appropriate revenue recovery. (Emphasis added)
3
4 I agree that this is an appropriate policy. Customers
5 need to be given appropriate price signals so that they
6 understand the costs that they are causing to be incurred
7 on the system. However, if the Company's cost of service
8 study finds that the Residential class should be getting
9 less than the
10
11 /
12
13 /
14
15 /
16
17
18
19
24 7 See Direct Testimony of Keith Hessing at page 10 line 9.
8 See Direct Testimony of Randy Lobb at page 20 line 12..25
1145 YANKEL, RE 9aIrrigators
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.
.
1 average increase in spite of its large rate of growth (as
2 it did in the example above), then the appropriate price
3 signal is not being provided. Based upon the Company's
4 cost of service study, the cost of growth will continue
5 to be under-priced, an inappropriately low price signal
6 will be sent, and growth (and its related costs) will be
7 promoted as opposed to paying its own way.
8 Q.DO THE WITNESSES FOR THE INTERVENING PARTIES
9 RECOGNIZE THE INAPPROPRIATENESS ASSOCIATED WITH THE
10 COMPANY'S COST OF SERVICE STUDY AS IT RELATES TO
11 DISPROPORTIONATE GROWTH ON THE SYSTEM?
12 A.Al though there is some recognition of the
13 problem, the other intervenors do not fully address the
14 issue. For example, Dr. Peseau on behalf of Micron
15 recognizes that the Company's cost of service study does
16 not adequately address the cost of growth and in
17 particular peak growth on the system, but he fall short
18 of directly addressing the issue of growth9:
19 Simply put, Idaho Power chooses a peculiar means of
conducting its 3CP /12CP cost of service study. It20 is not, in my opinion, a study that is guided by the
Electric' Utility Cost Allocation Manual published
21 January 1992 by NARUC, as Mr. Tatum suggests.
Testimony of Tim Tatum, P. 6, L. 4-8.
22
23
24
25
The reasons the choice of (the) study is peculiar is
because it is in direct conflict with the very real
problem identified in numerous places in Idaho
Power's filing, this is the problem of the Company's
excessi ve peak load growth, ...
1146 YANKEL, RE 10Irrigators
1 Q.HAVE OTHER INTERVENING PARTIES MADE A SIMILAR.2 RECOGNITION OF THE LOAD GROWTH ISSUE AND SPECIFICALLY THE
3 DISPROPORTIONATE LEVEL OF GROWTH AMONG THE CLASSES?
4
5 /
6
7 /
8
9 /
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25 9 See Direct Testimony of Dr. Peseau at page 41 line 22.
1147 YANKEL,RE lOaIrrigators
.
.
.
1 A.Dr. Reading on behalf of the Industrial
2 Customers of Idaho Power has made a similar recognition
3 of the problem with the Company's cost of service study
4 as it relates to growth and particularly the
5 disproportionate growth with respect to the Irrigation
6 class10:
7 The modifications I have recommended align cost
responsibili ty more in line with the Company's
changing load growth patterns. These changes will
also better provide price signals to the customer
classes that are creating costs through system load
growth. The results of these changes also increase
the revenue requirement for the irrigation class
only slightly. The irrigation class has the
misfortune of having the need for power during
summer on peak that is when the Company's system
needs are growing the fastest. Irrigation load isnot growing. Yet due to increasing residential and
commercial demand, their cost allocations are
increasing due to their relatively high summer use.
8
9
10
11
12
13
14
15 It is interesting to note that even though Dr. Reading is
16 trying to address the changing load growth pattern and he
17 recognizes that the Irrigators are not growing, his cost
18 of service results give even more of an increase to the
19 Irrigators-he has not fully addressed the issue.
20 Q.WHAT ARE YOUR RECOMMENDATION REGARDING REVENUE
21 SPREAD IN THIS CASE?
22 A.As demonstrated in the example I gave earlier
23 and as presented by Staff witness Hessing in the last
24 Idaho Power rate case, the Company's cost of service
25 study produces counterintuitive results when it addresses
1148 YANKEL, RE 11Irrigators
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.
19
20
21
22
23
24.25
1 disproportionate load growth. As stated in my direct
2 testimony and as stated in the conclusions from the
3 Workshop that was initiated by the Commission as a result
4 of Case IPC-E-04-23, there is "something inherently
5 troubling with the way costs, associated with growth,
6 were allocated."
7
8 /
9
10 /
11
12 /
13
14
15
16
17
18
1149 YANKEL, RE 11aIrrigators
.
.
1 10 See Direct Testimony of Dr. Reading at page 17 line 1.
2 We have already had a Workshop to address the
3 issue of treating the cost of disproportionate growth on
4 the system. That Workshop participants concluded that
5 there was a problem with the way the Company's cost of
6 service study allocated the cost of growth, but the
7 Workshop participants left for the Commission the
8 solution to that problem. No party is willing to
9 advocate an increase in costs to its client that will
10 correct a problem for another customer group. Of course,
11 they would advocate a solution if the shoe was on the
12 other foot. Now is the time to for the Commission to
13 recognize and address this problem so that the Irrigators
14 and other static classes are not be penalized by the
15 disproportionate growth taking place on the system. The
16 methodology put forward by the Irrigators give the tools
17 to the Commission to address this issue in a
18 nondiscriminatory and reasonable manner. A less than
19 average increase, or no increase, for the Irrigation
20 class would be a step in the right direction of
21 recognizing the inequities inherent in the Company's cost
22 of service methodology.
.
23
24
25
Q.DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?
A.Yes.
1150 YANKEL, RE 12Irrigators
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.
.
1
2 open hearing.)
(The following proceedings were had in
4 for cross-examination.
MR. OLSEN: And then he's now available3
5 COMMISSIONER SMITH: And we will mark for
6 identification Exhibits 301 through 304 and 306.
7 Let's see, Mr. Ward, do you have
17
18
8 questions?
9
10 you.
11
12
13
14
15 Madam Chair.
16
MR. WARD: I have no questions. Thank
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: No questions.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Just a couple,
CROSS-EXAINATION
19 BY MR. RICHARDSON:
20 Q Mr. Yankel, would you refer to page 5 of
21 your direct testimony?
22
23
A
Q
Yes.
And on this page you have a graph showing
24 historic growth and suggest over on the top of page 6
25 that the combined commercial/industrial load has over
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1151 YANKEL (X)Irrigators
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.
1 doubled at an increase of 124 percent. Do you see
2 that?
3 A Yes.
4 MR. RICHARDSON: Madam Chair, may I
5 approach the witness?
6 COMMISSIONER SMITH: You may.
7 (Mr. Richardson approached the witness.)
8 Q BY MR. RICHARDSON: Mr. Yankel, the
9 industrial and commercial classes are not typically
10 considered one class for purposes of cost of service
11 studies, are they?
12 A For cost of service purposes, there are a
13 number of rate schedules as opposed to classes.
14 MR. RICHARDSON: Madam Chair, I handed out
15 a document which I'd like marked as Exhibit No. 212.
16 COMMISSIONER SMITH: Thank you. We will
17 mark it as Exhibit 212.
18 (Industrial Customers of Idaho Power
19 Exhibit No. 212 was marked for identification.)
20 Q BY MR. RICHARDSON: Mr. Yankel, I had this
21 graph prepared to show essentially what you're showing on
22 page 5, however, with the industrial class and the
23 commercial class separated out and you will note the
24 copying didn't come out very well, but the bottom.25 triangled line is the irrigation class if you're looking
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1152 YANKEL (X)Irrigators
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.
1 at the far right-hand side going up. The next highest
2 line with the X' s would be the industrial class. The
3 boxes would represent the residential class and the
4 triangles on top would represent the commercial class.
5 Is that a fair representation of your chart on page 5,
6 however, with the commercial and industrial separated
7 out?
8 A I've obviously not done the math, but I
9 assume that's a fair representation.
10 MR. RICHARDSON: Okay, thank you.
11 Madam Chairman, that's all I have.
12 COMMISSIONER SMITH: Thank you, Mr.
13 Richardson. Mr. Bruder, do you have cross?
14 MR. BRUDER: Just very briefly.
15
16 CROSS-EXAMINATION
17
18 BY MR. BRUDER:
19 Q Sir, I'm looking at your direct testimony
20 on page 3 and you speak of the irrigators' ability to
21 reduce peak usage.
22
23
A Yes.
Q Is it so that the higher the rate the more
24 there is the imperative, the willingness to reduce.25 peak?
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1153 YANKEL (X)Irrigators
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18
1 A There are a couple of different rates that
2 you could be talking about. One, you could just be
3 talking about the irrigation bill or two, you could be
4 talking about the rate rebate or reduction that would be
5 gi ven. Probably in both cases, you know, if the
6 irrigation rate overall cost was doubled, yes, there
7 would probably be more incentive. If the billing credit
8 was increased, there would be more of a willingness, but
9 then again, if the irrigation rate was doubled, you'd
10 probably get no irrigation so, therefore, you wouldn't
11 have to worry about it.
12 Q I think you've round-aboutly answered
13 yes?
14 A Yes. Again, I wasn't sure which one of
15 those rates you weren't talking about, though.
16 Q I wasn't either, it's okay.
17 A Okay.
Q I'm looking now at your testimony at page
19 5 where we have this chart that would appear to present
20 growth for various customer classes. Now, this presents
21 growth in total hours of usage, not growth in peak; isn't
22 that right?
23 A That is correct. Chances are -- first of
24 all, growth in peak numbers did not exist, so what I have
25 is that --
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1154 YANKEL (X)Irrigators
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1 Q Why don't you limit the answer to just yes
2 or no.
3 A How about you ask me the question again?
4 Q You already answered, I think. Okay,
5 let's take it again. Okay, I'm sorry, let's take it
6 again. This chart we have here at page 5 of your
7 testimony tracks total hours of usage and growth of total
8 hours of usage and not growth of peak; is that right?
9 A Hours of energy, I think, is more accurate
10 than hours of peak. It's energy. You say hours meaning
11 it's gigawatt-hours, but it's energy and not peak, yes.
12 Q Okay, and did you just say that the
13 figures for peak growth are not available?
14 A From the sources that I have, I do not
15 have these numbers available every year broken out by
16 grouping. I was able to get this from the Company's IRP.
17 This information is readily available. The information I
18 have in my testimony is readily available.
19 Q But it is the growth of peak rather than
20 the growth of what we call energy usage throughout the
21 year that is driving the increase in cost, is it not?
22 A It is the growth in peak and energy that's
23 causing different sets of costs and my understanding is
24 and from my review growth in peak is probably a little
25 bi t faster than growth in energy, but the two are pretty
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1155 YANKEL (X)Irrigators
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.
1 much hand in hand. The growth rate, percentage growth
2 rate, is probably a little bit higher as far as peak
3 goes, so if I was to graph, if I had available the
4 information for peak as opposed to energy, which is what
5 I have here, the lines would probably be steeper as far
6 as the growth rates go.
7 Q You said a little bit steeper, it would be
8 considerably steeper. It's my understanding that peak
9 has grown much faster than overall demand; isn't that
10 right?
11 A Most of what I've seen and, again, I've
12 not tried to do a difference between them, but energy
13 could be growing at, say, two-and-a-half percent, peak
14 could be growing at three percent. I mean, there is a
15 difference. Certainly, peak is growing faster and peak
16 is more of a problem than what it was 25 years ago. 25
17 years ago I believe Idaho Power considered itself an
18 energy constrained system. Today it is considered not an
19 energy constrained system but a peak constrained system,
20 so there certainly has been changes due to that, but it's
21 just a question of quantifying significantly more or
22 more, certainly more. It would certainly be steeper.
23
24
25
Q But you can't quantify it beyond that?
A I can't beyond that, no.
Q I direct your attention now to page 15 of
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1156 YANKEL (X)Irrigators
.
.
1 your testimony. Beginning at line 10 there, we find
2 about a 16-line or 15-line quotation from The Parties'
3 Final Report in IPC-E-04-23 that says that it would be
4 difficul t with finding -- now I'm reading line 17 -- with
5 finding an allocation procedure that would satisfy the
6 courts. Can you tell us what the courts would find
7 unsatisfactory?
8 A This statement is a composite statement by
9 all of the members of the workshop and there were certain
10 members that wanted this particular statement put in
11 regarding the courts and what the courts would view. My
12 understanding is that the courts did not want to make a
13 difference between new and old customers, such as a
14 vintaging proposal which I agree with as far as that
15 goes, I have no problem with that, so it was put in there
16 to address the concerns of my understanding is there were
17 two Supreme Court cases in Idaho that addressed vintaging
18 where you price one customer, you give him a price based
19 upon when he first took service versus a different
20 customer when they took service, which is a different
21 proposal than what I have before you.
22 Q Here at page 26 of your direct, beginning
23 at line 8, please tell me when you're there.
.24
25
A I'm there.
Q Okay, you say that the issue of addressing
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1157 YANKEL (X)Irrigators
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.
.
1 growth in the Company's cost of service study is a new
2 direction for the Commission and one that generally has
3 not been faced by other commissions. Is this unique or
4 unusual to this Commission? Isn't there, nationwide
5 isn't there, quite a lot of attention being paid to
6 growth and how to deal with it in terms of cost of
7 service?
8 A Not in the cases I'm referring to which
9 specifically has to do with the disproportionate growth.
10 There's certainly concerns about growth. Unfortunately,
11 it's more on the Western side of the country than on the
12 Eastern side where they're kind of going the opposite
13 direction and they're kind of worried about that, but
14 there is a cost of growth and it's driving up costs
15 uniformly for all customers, as it's doing in Idaho as
16 well. The position I'm trying to put forth at this point
17 or the concern I was trying to address is the fact that
18 it's the disproportionate growth, the fact that a very
19 large customer class is not growing and is being charged
20 costs of the growth which is being incurred by other
21 classes, so it's a question really looking at the growth
22 and how the growth is divided up as opposed to just the
23 cost of growth itself.
24 Q And that's what is unique or unusual in
25 this situation, not growth generally, but what you call
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1158 YANKEL (X)Irrigators
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20
1 disproportionate growth?
2 A Yes, and that's what was the subj ect
3 you know, my opinion when we first brought it up in the
4 '03 case, the Commission ordered that there be a workshop
5 in the '03 case because of the issue and that's what we
6 still have before us today, so I think it's still a very
7 new concept for the Commission.
8 Q One more question and I had a note that
9 this has been. covered, I'm going to look at your rebuttal
10 now at page 6.
11 A Yes.
12 Q In the second question there beginning at
13 the end of line 15, you speak of rates based upon when
14 the customer first started taking service and you say
15 generally that the Supreme Court of this state has
16 prohibited rates that are based in that manner. Now, I'm
17 just going to ask yes or no, is it your testimony that
18 your proposal in this case is not based on when the
19 customer first started taking service?
A Correct or yes. Yes, my -- to be clear,
21 yes, my testimony is not based upon when the customer
22 first started taking service.
23
24 Thank you.
MR. BRUDER: I have nothing further.
25 COMMISSIONER SMITH: Thank you. Any
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1159 YANKEL (X)Irrigators
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.
.
1 questions, Mr. Price?
2 MR. PRICE: No questions.
3 COMMISSIONER SMITH: Mr. Walker.
4
5 CROSS-EXAMINATION
6
7 BY MR. WALKER:
8 Q There's a lot of testimony about growth or
9 non-growth and that's not really the same as saying that
10 there's change or no change within the irrigation class,
11 is there? And maybe I can ask that a better way.
12 There's new irrigation customers and old ones dropping
13 off, new ones coming on, people changing around, it's not
14 just a stuck static customer base, is it?
15 A Yes and no. There certainly are customers
16 coming on and off, people -- again, I'm not out in the
17 field, but there are people certainly that sell their
18 farms, people lease a different piece of property and
19 come in and, therefore, there are changes in the pumping,
20 you know, in the connections that the Company has. Over
21 the years there have been increases in the number of
22 pumps. I shouldn't say that. There have been increases
23 in the number of meters and customers. A lot of that, my
24 understanding, may be due to some BPA credits and
25 whatnot. There is a limit on the BPA credits of 400
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1160 YANKEL (X)Irrigators
.1 horsepower as far as how that kicks in, so some of the
2 set-ups that used to be out there that may have metered
3 three or four pumps, they may have put another meter in,
4 that type of thing, so my overall direction, though, was
5 based upon overall usage, energy usage and demand usage,
6 but on a customer level, there certainly has been changes
7 in, you know, the account, who has the account. There
8 have been increases in the number of accounts that are
9 out there, but the overall amount of land that's being
10 irrigated is probably less now than what there was 10
11 years ago.
12 Q So there's a li ttle bit of movement with,.13 you know, it's not just a static group, there's new
14 customers, maybe new fields, different fields, different
15 amounts they may pump from year to year or any number of
16 things that make this more, you know, more of a dynamic,
17 not just a static stuck? When we talk about growth and
18 look at numbers that there's no growth, it's not
19 necessarily the same that there's nothing going on
20 there?
21 A No, there are definitely things that are
22 going on. There is some movement. Again, the lack of
23 growth that I'm referring to is the lack of growth with
24 respect to the need for new production facilities and new.25 transmission facilities.
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1161 YANKEL (X)Irrigators
.
.
.
1 Q And even if we look at load, all of the
2 numbers aren't just stuck, they move around a little bit,
3 too; isn't that right?
4 A In a dry year there will be a lot more
5 pumping and you can see that. There are bumps on that
6 curve that go up and down, but overall, it's a pretty
7 flat curve.
8 Q And if we were to look at your total time
9 period from, say, '93 to '08, there was actually an
10 increase in the coincident peak demand by the irrigation
11 class; isn't that true?
12 A Over that 15-year time frame there was and
13 we could probably pick another 15-year time frame.
14 Again, I don't have the data, we don't have that type of
15 data, but it probably would have gone down at different
16 times as well.
17 Q So it's not necessarily a correct picture
18 to just think of it as everything flat, nothing changing.
19 In fact, the peak did grow from '93 to 2008?
20 A Yes, but by comparison to the rest of the
21 growth on the system, it's very flat.
22
23
MR. WALKER: That's all I have.
24 from the Commission?
COMMISSIONER SMITH: Do we have questions
25 COMMISSIONER REDFORD:No.
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1162 YANKEL (X)Irrigators
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1 COMMISSIONER SMITH: Do you have any
2 redirect, Mr. Olsen?
3 MR. OLSEN: I just have a couple of
4 questions.
5
6 REDIRECT EXAMINATION
7
8 BY MR. OLSEN:
9 Q With respect to the question talking about
10 the growth corrected adj ustments or Mr. Bruder talked
11 about the legal constraints, does the irrigators'
12 proposal try to segregate customers between new customers
13 and old customers?
14 A No, I'm strictly looking at growth on the
15 system and that would change moving forward. It's no
16 different the proposal that I have out there than what
17 presently exists now, the difference between customers.
18 We could have customers today that are not using at all
19 on peak and they still get charged essentially whatever
20 the allocation factor is for peak usage for the
21 irrigators even though they may irrigate strictly at
22 night. We're looking at this as a class of customers and
23 strictly as the growth on the class.
24
25
MR. OLSEN: I have no further questions,
Madam Chair.
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1163 YANKEL (Di)Irrigators
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18
19
20
21
22
23
24.25
1 COMMISSIONER SMITH: Thank you for your
2 help, Dr. Yankel.
3 THE WITNESS: Mister.
4 COMMISSIONER SMITH: Mister.
5 (The witness left the stand.)
6 MR. OLSEN: Madam Chair.
7 COMMISSIONER SMITH: Yes, Mr. Olsen.
8 MR. OLSEN: Could I ask that Mr. Yankel be
9 excused?
10 COMMISSIONER SMITH: If there is no
11 obj ection, we will excuse Mr. Yankel. Okay, unless there
12 is another suggestion, it is my intention now to go to
13 the Staff.
14 MR. PRICE: Commission Staff would like to
15 call Mr. Rick Sterling.
16
17
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1164 YANKEL (Di)Irrigators
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1
2
RICK STERLING,
produced as a witness at the instance of the Staff,
3 having been first duly sworn, was examined and testified
4 as follows:
5
6
7
8 BY MR. PRICE:9 Q10 A11 Q12 A
13 Q
DIRECT EXAMINATION
Please state your name.
My name is Rick Sterling.
And who is your employer?
The Idaho Public Utilities Commission.
And what is your job title at the
Staff engineer.
And on October 24th of this year did you
17 have occasion to prepare written direct testimony in this
14 Commission?
15 A
16 Q
18 case?
19
20
21
22
A
Q
A
Q
Yes, I did.
Including Exhibit Nos. 101 through 107?
That's correct.
Do you have any corrections or additions
23 to this testimony?
24
25
A
Q
No, I do not.
And if I were to ask you the same
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1165 STERLING (Di)Staff
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17
18
19
20
21
22
23
24
25
1 questions that were posed in your written direct
2 testimony today, would your answers be the same?
3 A Yes.
4 MR. PRICE: I would move at this time to
5 spread Mr. Sterling's written testimony on the record,
6 including Exhibit Nos. 101 through 107.
7 COMMISSIONER SMITH: If there is no
8 obj ection, we will spread the prefiled testimony upon the
9 record as if read and identify Exhibits 101 through 107.
10 (The following prefiled direct testimony
11 of Mr. Rick Sterling is spread upon the record.)
12
13
14
15
16
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1166 STERLING (Di)Staff
.
.
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Rick Sterling. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utili ties
7 Commission as a Staff engineer.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science degree in
11 Civil Engineering from the University of Idaho in 1981
12 and a Master 9f Science degree in Civil Engineering from
13 the University of Idaho in 1983. I worked for the Idaho
14 Department of Water Resources from 1983 to 1994. In
15 1988, I received my Idaho license as a registered
16 professional Civil Engineer. I began working at the
17 Idaho Public Utilities Commission in 1994. During my
18 employment at the IPUC, I have attended the annual
19 regulatory studies program sponsored by the National
20 Association of Regulatory Commissioners (NARUC) at
21 Michigan State University, as well as numerous other
22 seminars and short courses.
23 Q.What is the purpose of your testimony in this
24 proceeding?.25 A.The' purpose of my testimony is to discuss the
CASE NO. IPC-E-08-10
10/24/08 1167 STERLING, R (Di) 1
STAFF
.
.
.
1 net power supply cost recommendation of Idaho Power, to
2 explain why I believe it is too high, and to make an
3 alternative recommendation that I believe fairly and
4 reasonably represents the Company's normalized net power
5 supply cost for the 2008 test year.
6 Q.Please briefly summarize your proposed net
7 power supply cost adj ustments.
8 A.I am proposing a net power supply cost of $77.6
9 million, which is approximately $11.2 million less than
10 Idaho Power's proposed net power supply cost. My net
11 power supply cost recommendation is based on the use of a
12 natural gas price of $7. 75 per MMBtu in the AURORA model.
13 Q. Have you reviewed the work done by Idaho Power
14 to develop a net power supply cost recommendation for
15 this case?
16 A.Yes, I have reviewed the Company's testimony
17 and recommendations related to net power supply cost, and
18 have also reviewed all of the supporting exhibits and
19 workpapers prepared by the Company as well as all of the
20 power supply cost simulations made using AURORA.
21 Q.What is Idaho Power recommending as the net
22 power supply cost to be included in its revenue
23 requirement?
24
25
A.Idaho Power is recommending a net power supply
cost of $88.4 million in addition to PURPA costs of $63.3
CASE NO. IPC-E-08-10
10/24/08 1168 STERLING, R (Di) 2
STAFF
.
.
20
1 million, for a total power supply cost of $151.7 million.
2 Q.Do you agree with the net power supply cost
3 recommendations contained in the testimony of Idaho Power
4 witness Greg Said?
5 A.No, I do not. I believe that the net power
6 supply cost recommendations of the Company are too high.
7 I do accept the Company's estimate of PURPA costs,
8 however.
9 Q.Why do you believe that the net power supply
10 cost recommendations of the Company are too high?
11 A.I believe that Idaho Power's net power supply
12 cost recommendations are too high because of inaccurate
13 assumptions made by the Company regarding natural gas
14 fuel prices used in AURORA, the model used for computing
15 net power supply costs.
16 Q.Are' natural gas price assumptions crucial in
17 the determination of net power supply costs, even though
18 Idaho Power has a relatively small amount of natural gas
19 fired generation on its system?
A.Yes, Idaho Power's net power supply costs are
21 not only a function of the costs of fueling and operating
22 its own generating resources, but are also a function of
23 the costs of its off-system purchases and its secondary
24 sales. During the maj ori ty of the year, gas-fired.25 generation is the marginal resource in the region;
CASE NO. IPC-E-08-10
10/24/08 1169 STERLING, R (Di) 3
STAFF
.1 consequently, it tends to set the market price for all
2 market purchases and sales. Obviously, higher gas prices
3 dri ve electric market prices up and lower gas prices
4 dri ve market prices down.
5 Q.How do high gas prices affect Idaho Power and
6 its ratepayers?
7 A.High gas prices actually benefit Idaho Power
8 and its ratepayers in most years. Because Idaho Power is
9 a net energy seller over the course of the year, high gas
10 prices, which in turn cause high electric market prices,
11 allow the Company to sell its surplus low-cost hydro and
12 coal generation at those higher market prices,.13
14
substantially reducing its net power supply costs.
Q. What assumptions about gas price did Idaho
15 Power make for purposes of its AURORA power supply cost
16 simulations?
17 A.Idaho Power's derivation of the gas prices it
18 used in AURORA is shown on Staff Exhibit No. 101. Idaho
19 Power obtained 10-year gas price forecasts from three
20 different sources-PlRA, DOE-EIA, and Global Insight-and
21 five-year forecasts from two sources-NYMEX and NGX.
22 Idaho Power computed a weighted average price using each
23 of the ten years from 2008-2017, then made other
24 adjustments to prepare the prices for input into the.25 AURORA model. Idaho Power generated upper and lower
CASE NO. IPC-E-08-10
10/24/08 1170 STERLING, R (Di) 4
STAFF
.
.
.
1 limi ts for gas prices to be used in AURORA by applying
2 the standard deviation in actual prices at Sumas from
3 2001 through 2007. The result of this exercise was an
4 average gas price of $ 7. 74 /MMBtu with upper and lower
5 limits of $9.75/MMBtu and $5.73/MMBtu.
6 Q.How was this range of assumed gas prices used
7 by Idaho Power in the AURORA model?
8 A.Idaho Power assumed that high gas prices are
9 associated with low water conditions and that low gas
10 prices occur when water conditions are high. For the 80
11 water years of record used in the power supply analysis,
12 the Company created an algorithm that assigned the
13 highest gas price ($ 9. 75) to the lowest water year on
14 record and assigned the lowest gas price ($5. 73) to the
15 highest water year on record. Gas prices were then
16 assigned to all of the years in between based on their
17 relati ve water condition.
18 Q.What is wrong with this approach in your
19 opinion?
20 A.I believe that Idaho Power's approach is wrong
21 for two reasons. First, I do not believe it is
22 appropriate to use 10, or even five years of gas price
23 forecasts when we are really only trying to establish
24 power supply costs between now and when Idaho Power files
25 its next general rate case. Idaho Power's last general
CASE NO. IPC-E-08-10
10/24/08 1171 STERLING, R (Di) 5
STAFF
.
.
.
15
1 rate case was filed only about one year before this one,
2 and the Company has indicated that it expects to make
3 more frequent rate case filings in the future.
4 Informally, Idaho Power has told Staff that its future
5 rate case filings could be made as often as annually.
6 Therefore, because we are likely only setting rates to be
7 effecti ve for approximately the next year, it seems
8 logical that we should only be using gas price forecasts
9 representati ve of the same time frame. Gas price
10 forecasts five or ten years into the future have no
11 relevance whatsoever when we are only setting rates one
12 year into the. future.
13 Q. What is your other primary obj ection to the
14 method used by Idaho Power?
A.My second obj ection relates to Idaho Power's
16 assumption that gas prices are directly related to hydro
17 condi tions. I do not believe that gas prices are
18 correlated with hydro conditions on Idaho Power's system,
19 or for that matter, even with Northwest hydro conditions.
20 I believe that natural gas prices are influenced by
21 numerous factors, most of which have nothing to do with
22 water conditions in the Northwest. Because pipelines
23 allow natural gas to be transported throughout North
24 America, gas prices now tend to rise or fall in unison.
25 Prices in the Northwest can be affected by a prolonged
CASE NO. IPC-E-08-10
10/24/08 1172 STERLING, R (Di) 6
STAFF
.1 cold snap in the Midwest, for example, by tropical storms
2 and hurricanes in the Gulf, or by unusual demand in
3 California. Underground gas storage levels, drilling
4 acti vi ty, market speculation and economic conditions also
5 significantly affect prices. Gas demand, wherever it
6 occurs in the country, can affect prices nationally.
7 Regional supply interruptions seem to be one of the few
8 factors that can still significantly affect regional gas
9 prices.
10 Q.Have you examined any data or performed any
11 analysis to support your conclusion that gas prices and
12 Northwest hydro conditions are not related?.13
14
A. Yes ~ I have. I performed regression analysis
using historical Henry Hub and Sumas gas prices as
15 reported by the Intercontinental Exchange and historical
16 water conditions represented by hydro shaping factors
17 used in AURORA. The hydro shaping factors used in AURORA
18 reflect monthly and annual scaling factors used to
19 accurately replicate historic hydro conditions in areas
20 throughout the Northwest. The source for the hydro data
21 used in AURORA is the Northwest Power Pool. Staff
22 Exhibit No. 102 shows the results of the correlation
23 analysis on a monthly basis for hydro conditions from
24 2001 through 2006 at Hells Canyon, Southern Idaho,.25 run-of-ri ver plants on Idaho Power's system, the Oregon-
CASE NO. IPC-E-08-10
10/24/08
1173 STERLING, R (Di) 7
STAFF
.
.
.
1 Washington-Northern Idaho area, British Columbia and
2 Montana. As shown by the exhibit, there appears to be no
3 correlation whatsoever between Northwest hydro conditions
4 and Sumas gas prices on a monthly basis. The results are
5 similar for Henry Hub gas prices.
6 Q.Are you saying that neither gas prices nor
7 hydro conditions affect power supply costs?
8 A.No, I am not suggesting that gas prices and
9 hydro conditions do not affect power supply costs.
10 Clearly, both greatly affect power supply costs. They do
11 so independently, however. What I am saying is that gas
12 prices are unrelated to Northwest hydro conditions.
13 Q. What gas prices did you consider using for the
14 power supply analysis in AURORA?
15 A.I believe it is reasonable to use gas prices
16 representative of 2009, the year when the rates
17 determined in this case will be effective. To obtain
18 prices representative of 2009, I considered several
19 forecasts available to Staff. First, I considered the
20 August 2008 forecast prepared by Global Insight because
21 it was more recent than the March 2008 Global Insight
22 forecast used by Idaho Power in developing the Company's
23 gas price forecast. I also considered the Department of
24 Energy/Energy Information Administration's (EIA) Annual
25 Energy Outlook forecast that was released in June 2008.
CASE NO. IPC-E-08-10
10/24/08 1174 STERLING, R (Di) 8
STAFF
.
.
1 In addition, I considered EIA' s Short Term Energy Outlook
2 forecasts released monthly in 2008 from January through
3 October. In addition to these forecasts, I considered
4 the most recent 12 months of NYMEX spot market prices and
5 NYMEX forwards prices for 2009. I also reviewed recent
6 forecasts made by gas industry experts as reported
7 quarterly in the publication Na tural Gas Week.
8 Q.Do you consider these sources to be superior to
9 those used by Idaho Power?
10 A.All of the forecasts I considered were more
11 recent than the forecast information used by Idaho Power.
12 I had an advantage in my analysis because all of the gas
13 price information I considered was simply not yet
14 available at the time the Company prepared its case.
15 Q.Were gas price forecasts for 2009 reasonably
16 consistent throughout the past year?
17 A.No, gas price forecasts for 2009 and 2009 gas
18 forwards prices were extremely variable during the past
19 year. Exhibit No. 103 shows how dramatically 2009 gas
20 forwards prices varied throughout 2008.
21 Q.Why did 2009 gas forwards prices vary so much
22 during the year?
23 A.There were several extremely unusual events in
24 2008 that had major impacts on 2009 forwards prices..25 First, oil prices began climbing in the first half of the
CASE NO. IPC-E-08-10
10/24/08 1175 STERLING, R (Di) 9
STAFF
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1 year, eventually reaching record levels. Natural gas
2 prices followed a similar trend until July 1, when winter
3 2009 forwards prices peaked at over $14 per MMBtu. In
4 less than a month and a half, prices plummeted to the $8
5 per MMBtu range. Two maj or hurricanes in the Gulf during
6 September also affected prices. Finally, the recent
7 economic crisis and Wall Street bailout plan have lowered
8 forecast prices even further due to expectations of a
9 global economic downturn. These highly unusual events
10 have made it extremely difficult to forecast prices even
11 one year into the future. Selecting gas prices in recent
12 months for use in power supply modeling has truly been a
13 case of chasing a moving target.
14 Q. What gas prices do you believe should be used
15 for power supply modeling in AURORA?
16 A.My recommendation is to use a gas price of
17 $7.75 per MMBtu for all 80 water years based on the
18 natural gas price forecast contained in the Energy
19 Information Administration's October 2008 Short Term
20 Energy Outlook. That is the forecasted price for 2009
21 (in year 2008 dollars).
22 Q.Why did you decide to rely on just one recent
23 forecast rather than using a blend of forecasts like
24 Idaho Power or using an average of several forecasts
25 prepared at different times during the year?
CASE NO. IPC-E-08-10
10/24/08 1176 STERLING, R (Di) 10
STAFF
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.
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1 A.Because of the extreme events during the past
2 year, gas forecasts prepared early in the year could not
3 take into account the effect of recent events. The
4 extreme rise and fall in oil and natural gas prices and
5 the economic credit crisis, in particular, are two events
6 whose effects can only be reflected in very recent price
7 forecasts. I chose to use the freshest forecast
8 available at the time I prepared my testimony. Because
9 mul tiple recent forecasts were not available, blending
10 forecasts was not an option. Furthermore, blending
11 forecasts prepared at different points in time when
12 economic conditions are extremely different would be
13 inadvisable.
14 Q. Why do you propose to use the same gas price
15 for all 80 water years?
16 A.I believe it is appropriate to use the same gas
17 price for all 80 water years because I have found no
18 evidence to suggest that gas prices vary based on water
19 conditions. The purpose of using 80 different water
20 years is to simulate normal water conditions during the
21 test year. Normal gas prices for the test year can be
22 simulated with only a single estimate because gas prices
23 are unrelated to water conditions.
24
25
Q.What net power supply cost do you calculate
using AURORA with the $7.75 per MMBtu gas price you
CASE NO. IPC-E-08-10
10/24/08 1177 STERLING, R (Di) 11
STAFF
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1 believe should be used?
2 A.Using a gas price of $7.75 per MMBtu for all
3 water years, AURORA calculated a net power supply cost of
4 $77.6 million. Net power supply costs are comprised of
5 four accounts: 447 System Opportunity Sales; 501 Fuel
6 (Coal); 547 Fuel (Gas); and 555.1 Purchased Power.
7 Staff's proposed totals for each account are shown on
8 Exhibit No. 104, and are also compared to Idaho Power's
9 proposed amounts. Staff's most significant adj ustment is
10 a $6.4 million increase in account 447 System Opportunity
11 Sales.
12 Q.The $7.75 per MMBtu gas price that you used for
13 AURORA modeling is only one cent higher than the price
14 Idaho Power used for its modeling. Why did such a small
15 difference in gas price cause your power supply costs to
16 be $11.2 million lower than Idaho Power's?
17 A.The extremely small difference in annual gas
18 price assumptions is not a significant reason for the
19 substantial difference in net power supply costs. The
20 primary reason why my results differ so much from Idaho
21 Power's is because I did not assume a correlation between
22 water conditions and gas prices, as I explained
23 previously. Idaho Power assumes that the highest gas
24 prices (thus the highest electric prices) will occur in
25 the lowest water years. In those low-water /high-price
CASE NO. IPC-E-08-10
10/24/08 1178 STERLING, R (Di) 12
STAFF
.
.13
14
1 years, Idaho Power will have little or no surplus power
2 to sell, and instead will likely need to buy power at
3 those high prices. Idaho Power assumes the opposite
4 si tuation in high water years, i. e., that in years when
5 it has a lot of surplus power to sell, gas and electric
6 prices will be low. Compared to my assumptions, the
7 Company's assumptions produce lower revenues in
8 high-water years and higher costs in low-water years.
9 Q.Did you make any other changes to the AURORA
10 input assumptions that are different from those used by
11 Idaho Power?
12 A.Yes, I made two changes that had a
comparatively minor effect. First, I decreased the gas
price basis differential between Henry Hub and Danskin.
15 Idaho Power used a basis differential of $0.27 per MMBtu.
16 I performed analysis of Henry Hub to Sumas basis
17 differentials using NYMEX forwards prices, then accounted
18 for delivery costs from Sumas to Danskin, and determined
19 that a basis differential of $0.13 is more appropriate.
20 Second, I modified the "monthly shape factors"
21 for the gas prices used in AURORA. Monthly shape factors
22 are basically multipliers that are used to convert an
23 annual gas price (in this case $7.75 per MMBtu) to a
24 series of twelve different monthly prices. My.25 modification was based on analysis of 2009 monthly gas
CASE NO. IPC-E-08-10
10/24/08 1179 STERLING, R (Di) 13
STAFF
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20
1 forwards prices as quoted daily by NYMEX for the past
2 twel ve months.
3 Except for these two changes, I used all of
4 Idaho Power i s other assumptions in AURORA. A summary of
5 the results of this AURORA simulation is presented in
6 Staff Exhibit No. 105.
7 Q.Have you prepared an exhibit comparing your net
8 power supply cost recommendations to Idaho Power's?
9 A.Yes, Staff Exhibit No. 106 compares my
10 recommendation for net power supply cost to Idaho
11 Power's. The exhibit also shows the PURPA costs that are
12 added to get total power supply cost, as well as the
13 normalized power supply costs adopted in the Company's
14 last general rate case. Note that even under Staff's
15 recommendation, net power supply costs are more than
16 double what they were in the Company's last general rate
17 case.
18 Q.Did. you make any AURORA runs using gas prices
19 from Idaho Power's own gas forecast?
A.No, I did not. I did not use Idaho Power's own
21 forecasted gas prices for 2009 because all of the
22 forecasts used by Idaho Power were made in March - before
23 the extreme run-up in prices prior to July, before the
24 precipitous drop in prices in July and August, before
25 hurricanes Gustav and Ike, and before the credit crisis
CASE NO. IPC-E-08-10
10/24/08 1180 STERLING, R (Di) 14
STAFF
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1 in October. I do not believe any forecasts for 2009 that
2 were made in March 2008 should be relied upon for power
3 supply modeling. Idaho Power's forecasted price for 2009
4 was $8.89 per MMBtu. I believe that price is clearly too
5 high. Such high gas prices produce net power supply cost
6 resul ts that are unrealistically low. Using my other
7 assumptions, a price of $8.89 per MMBtu would have
8 produced a net power supply cost of approximately $64.5
9 million.
10 Q.Have you prepared an exhibit to compare Idaho
11 Power's net power supply recommendation, your
12 recommendation, and other net power supply results
13 obtained using other possible gas price assumptions?
14 A. Yes, I have. Staff Exhibit No. 107 shows the
15 effect of various gas price assumptions on net power
16 supply costs and compares my recommended result to the
17 Company's. As the results show, my recommended net power
18 supply cost is below the Company's recommendation, but
19 higher than it would be if several other gas forecasts
20 were used. Compared to the results obtained using other
21 possible gas prices, I believe my recommendation is
22 conservative.
23 Q.What happens if Idaho Power's actual net power
24 supply costs turn out to be different than those adopted
25 in this general rate case?
CASE NO. IPC-E-08-10
10/24/08 1181 STERLING, R (Di) 15
STAFF
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1 A.If actual power supply costs in the future are
2 different than those adopted in this general rate case,
3 then the difference will be considered in the annual
4 Power Cost Adj ustment (PCA) until the Company's next
5 general rate case. Under the PCA, 90 percent of the
6 difference between the annual proj ected power cost and
7 the Commission approved base power cost as established in
8 this case wiii be credited to or collected from
9 customers. Consequently, Idaho Power will never be at
10 risk for more than 10 percent of the difference between
11 projected power supply costs and the base power supply
12 costs.
13 Q. Can you validate the AURORA model by comparing
14 predicted results to actual net power supply costs from
15 prior years, say for 2007?
16 A.Although it is possible to compare simulated
1 7 results to actual historical results, the two will
18 probably never be equal even if historical gas prices and
19 hydro conditions are replicated. Actual electric market
20 prices are affected by many things besides just hydro
21 condi tions and natural gas prices. Many factors that
22 affect actual power supply costs simply cannot easily be
23 replicated on an actual basis in AURORA, such as weather,
24 plant outages, fuel supply interruptions, and market
25 speculation. The 2007 water year results from the "base
CASE NO. IPC-E-08-10
10/24/08 1182 STERLING, R (Di) 16
STAFF
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.
.
19
20
21
22
23
24
25
1 case" used to determine power supply costs in this case
2 will not match actual 2007 power supply costs because the
3 "base case" for 2007 only differs from the other 79 years
4 used in the analysis by the hydro conditions. The base
5 case for 2007 does not use actual gas prices in 2007,
6 actual demand in 2007, or any other actual data from
7 2007. The 2007 results only reflect 2007 water
8 conditions and nothing more.
9 Q.Does this conclude your direct testimony in
10 this proceeding?
11 A.Yes, it does.
12
13
14
15
16
17
18
CASE NO. IPC-E-08-10
10/24/08 1183 STERLING, R (Di) 17
STAFF
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1
2 open hearing.)
(The following proceedings were had in
4 wi tness for cross-examination.
MR. PRICE: I would now present this3
5 COMMISSIONER SMITH: Okay, thank you.
6 Mr. Bruder, do you have any questions?
7
8
MR. BRUDER: I have none. Thank you.
9 you have questions?
COMMISSIONER SMITH: Mr. Richardson, do
10
11 Madam Chair.
12
13
14
15
16
MR. RICHARDSON: No questions,
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: No questions.
COMMISSIONER SMITH: Mr. Ward.
MR. WARD: No questions.
COMMISSIONER SMITH: Who are we missing?
17 Mr. Olsen. That must be a no questions. All right,
18 Mr. Kline.
19
20 Madam Chairman.
21
22
23
24 BY MR. KLINE:
25 Q
. MR. KLINE: I do have some questions,
CROSS-EXAMINATION
Mr. Sterling, in your testimony, Staff is
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1184 STERLING (X)Staff
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1 proposing normalized net power supply expenses in the
2 amount of $77.6 million; is that correct?
3 A That is correct.
4 Q And the Company is proposing normalized
5 net power supply expenses in the amount of $88.4 million;
6 is that correct?
7 A That's my understanding, yes.
8 Q Isn't the difference between these two
9 numbers $10,800,000 rather than the $11.2 million that
10 are shown on page 2, line 9 of your testimony?
11 A No, the difference between those numbers,
12 you are probably correct, but if you would look at one of
13 my exhibits, and I can tell you which one, Exhibit 106,
14 if you'll notice in the far right column labeled Total,
15 there's a $10.8 million difference, but if you read the
16 footnote below that table, when we include transmission
17 losses, that brings the difference to 11.2.
18 Q Okay, thank you. Now, were you here when
19 Mr. Said testified yesterday?
20
21
A Yes, I was.
Q And in his testimony and in the
22 cross-examination of Mr. Said, there was a number of
23 questions regarding the interaction between gas prices
24 and the normalized net power supply expenses that come
25 out of the AURORA model. Do you recall that testimony?
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17
1 A Yes, I do.
2 Q I'd like to direct your attention to page
3 11 of your testimony and we'll start on line 9 and there
4 you're talking about gas forecasts. Are you there?
5 A Yes.
6 Q Okay, and actually starting on line 7 is
7 where it starts. You say, "I chose to use the freshest
8 forecast available at the time I prepared my testimony,"
9 and the forecast that you're talking about there is gas
10 prices; is that correct?
11 A Yes, that's true.
12 MR. KLINE: I'd like to approach the
13 witness if I could, please, Madam Chairman.
14 COMMISSIONER SMITH: Yes.
15 (Mr. Kline approached the witness.)
16 COMMISSIONER SMITH: Mr. Ward?
MR. WARD: Madam Chair, if I may, I didn't
18 hear the last question and answer because of the static
19 on the mic. Can Connie read it back?
20 COMMISSIONER SMITH: Sure.
21 (The last question and answer were read
22 back by the court reporter.)
23
24
25
MR. WARD: Thank you, I apologize.
Q BY MR. KLINE: Now, what I've handed to
you, Mr. Sterling, is a copy of an Order recently issued
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1186 STERLING (X)
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1 by this Commission in an Intermountain Gas case and this
2 was a case where Intermountain Gas was asking permission
3 of the Commission to decrease its rates; is that
4 correct?
5 A It appears to be that, yes.
6 MR. KLINE: And for purposes of the
7 record, Madam Chairman, I believe that the Commission can
8 take official notice of this Order. There's no reason to
9 make it an exhibit and so it wouldn't be my intention to
10 do so. I'm just going to use it for cross-examination.
11 COMMISSIONER SMITH: That is true, we can
12 take official notice of our Orders.
13 MR. KLINE: Thank you.
14 Q BY MR. KLINE: Now, looking at this Order,
15 it's Order No. 30676, Mr. Sterling, it shows that
16 Intermountain Gas originally asked to have rates put into
17 place and the Commission did in fact allow them to do so
18 based on a weighted average cost of gas based on a 2009
19 forecast of 78.5 cents per therm; is that correct? Do
20 you see that?
21
22
A Yes, I do see that.
Q Okay, and they asked to reduce it to 67.5
23 cents per thermo Do you see that?
24
25
A Yes, I do.
Q All right, and that is based on a 2009
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1187 STERLING (X)Staff
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1 forecast of natural gas that they presented to the
2 Commission; correct?
3 A I believe that's the case. I didn't work
4 on this case, so I'm not familiar with which forecast
5 they used, but I think that's probably true.
6 Q Well, are you familiar with how -- I'm
7 sorry, in your testimony, you talk in terms of MMBtu' s,
8 in other words, $7.84 per MMBtu; is that correct?
9 A Yes.
10 Q And are you familiar with the method for
11 converting therms to MMBtu' s?
12 A I wouldn't trust my numbers just to sit
13 here.
14 Q Would you accept, subj ect to check, that
15 all you really have to do is multiply the therm number by
16 10?
17 A That's roughly true. It's close enough to
18 for our purposes here, I believe.
19 Q Okay, thank you. Really hoping you didn't
20 ask me to go through that math. After the conversion,
21 then, in the IGC case, the IGC 67.5 cents per therm would
22 then be converted to roughly $ 6. 75 per MMBtu; correct?
23
24
25
A Yes.
Q All right. Now, wouldn't this Commission
approved number or forecast for 2009 gas prices be the
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1188 STERLING (X)Staff
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1 freshest gas price forecast that would be available to
2 the Commission at this time?
3 A No, I don't think so. There's probably
4 even fresher forecasts than were used here, I'm certain
5 of that.
6 Q Are there any that are fresher that the
7 Commission has looked at and in fact approved a dollar
8 amount based on a 2009 forecast that you're aware of?
9 A Well, I don't know if the Commission
10 exactly approves forecasts, I guess, as you described it,
11 but a purchased gas cost adjustment is really the only
12 instance I know of where the Commission takes an explicit
13 action involving a gas forecast.
14 Q If you look at this Order, I -- strike
15 that. Okay, no, look at the Order on page 2 and it talks
16 about Staff compared the WACOG, under Comments, under the
17 heading of Comments it says, "Staff compared the WACOG
18 requested by Intermountain Gas to the NYMEX Futures
19 Index, Global Insights Forecast, and the Energy
20 Information Administration's outlook," and those are all
21 forecasts of natural gas prices, are they not?
22 A Global Insights is a forecast and so is
23 EIA. NYMEX is actually futures prices that, in my mind,
24 is different than a forecast. It's what you could buy
25 gas for in the future if you bought it today for future
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1189 STERLING (X)
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1 delivery.
2 Q And in the next section under the main
3 heading Discussion, the Commission says that they
4 reviewed the record, including the Staff's comments. Do
5 you see that?
6 A Yes, I do.
7 Q And they go on to approve the natural gas
8 prices as requested by Intermountain Gas. Wouldn't it be
9 logical to assume that they were approving the forecast
10 at the same time?
11 A I think they were approving the forecast
12 for use in this particular purpose.
13 Q All right. Well, let me ask you this: If
14 you used the $ 6. 75 price that is contained in this Order
15 in the AURORA model, you ran it through using the same
16 methodology that you are proposing here in this case and
17 if all other things were equal, would your normalized
18 power supply expense estimate, how would that change
19 it?
20 A It would be higher.
21 Q And would it go up perhaps as high as the
22 $88 million figure proposed by Mr. Said in his direct
24.25
23 testimony?
A Wi thout doing some calculation, I couldn't
really sit here and say how much it would go up. I do
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1190 STERLING (X)Staff
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1 know that it would go up. Exactly how much is difficult
2 to say.
Q Would that be a difficult exercise for you3
4 to perform using the AURORA model?
5 A No, it would not be particularly
6 difficul t. To make a run like that using AURORA, it's
7 about a 12- or 14-hour run time, but it's not difficult
8 to do.
9 Q I mean, you just have to change the input
10 and push the button; is that right?
11 A That's right.
And then the computer takes 12 to 14
13 hours, you don't do 14 hours of work?
A
Q
A
Q
A
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14 A That's right.
Mr. Sterling, now I'd like to ask you a
16 couple of questions about Dr. Peseau' s testimony. Do you
12 Q
15 Q
17 have that with you?
18
19
20
21
22
23
No, I do not.
Could you get it?
If someone could provide it to me, please.
(Mr. Price approached the witness.)
THE WITNESS: Okay, I do have it now.
BY MR. KLINE: I'd like you to turn to
24 page 15 of Dr. Peseau' s testimony.
25 I'm there.
1191 STERLING (X)
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1 Q And specifically, the answer that begins
2 on line 19 there on the bottom of page 15. Are you
3 there?
4 A Yes, I'm there. Give me a second to read
5 the line, please.
6 Q You bet. I need you to read the whole
7 answer.
8 A You want me to read it out loud?
9 Q No, no, I mean just get familiar with it.
10 A Okay. I've read the answer.
11 Q All right. In that answer, Dr. Peseau
12 testifies that he thinks that it's his opinion that
13 PURPA prices are a surrogate for electric market prices.
14 Do you read that?
15 A Yes.
16 Q Do you agree with Dr. Peseau that the
17 surrogate avoided resource or SAR methodology that we use
18 here in Idaho to set avoided costs replicates market
19 prices?
20
21
A No, I don't agree with that.
Q What does the surrogate avoided resource
22 methodology give us in the PURPA context?
23 A It's simply the cost of a combined cycle
24 combustion turbine, fixed costs, capital costs, O&M
25 costs, fuel costs.
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17
18
19
1 Q And to use it as a --
2 MR. WARD: Excuse me, if I may.
3 COMMISSIONER SMITH: Mr. Ward.
4 MR. WARD: Let's read the answer. I f I
5 may, I'LL read Dr. Peseau' s answer. It says, "Because
6 current natural gas prices are relatively close to the
7 prices the Commission used to determine PURPA rates by
8 using a modeled combined cycle natural gas generator as a
9 surrogate for market prices." He didn't suggest natural
10 gas was a surrogate for market prices. He talks about
11 the combined cycle.
12 MR. KLINE: Is that an objection?
13 THE WITNESS: I'd remind both parties this
14 is not my testimony and maybe you ought to cross-examine
15 Dr. Peseau.
16 COMMISSIONER SMITH: So are you --
MR. WARD: That's all I wanted to ask.
COMMISSIONER SMITH: Mr. Kline.
MR. KLINE: I think -- well, I thought the
20 question I asked you was, is a combined cycle natural gas
21 generator a surrogate for market prices using the avoided
22 cost model that we use in Idaho.
23 MR. PRICE: Then I'll go ahead and obj ect
24 right here. I think it's beyond the scope of
25 Mr. Sterling's direct testimony.
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1193 STERLING (X)
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1 COMMISSIONER SMITH: Mr. Kline.
2 MR. KLINE: I think he already answered it
3 prior to the testimony from Mr. Ward.
4 MR. PRICE: Better late than never.
5 COMMISSIONER SMITH: So what is your
6 response to the obj ection?
7 MR. KLINE: My obj ection -- my response is
8 that Mr. Sterling is probably the preeminent expert in
9 the State of Idaho as to how we compute avoided costs and
10 the use of the surrogate avoided resource and whether or
11 not it constitutes a surrogate for market prices.
12 COMMISSIONER SMITH: Mr. Price.
13 MR. KLINE: I think he's capable of
14 answering it.
15 MR. PRICE: I think that Mr. Kline can ask
16 him a question relating to his expertise, but based
17 solely upon his testimony, not upon another party's
18 testimony.
19 MR. KLINE: I think as an expert, I'm
20 entitled to ask his opinion as to this testimony that's
21 been presented in this case.
22 COMMISSIONER SMITH: Okay, I'm going to
23 overrule the obj ection and allow the question. If he has
24 an opinion, he can provide it..25 Q BY MR. KLINE: And is it your opinion that
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1194 STERLING (X)Staff
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18
1 the PURPA rates as approved by this Commission are a
2 surrogate for market prices?
3 A No, I don't believe they are.
4 Q All right. Now, also on page 15 of
5 Dr. Peseau' s testimony, take a look up on, starting on
6 line 15 and there Dr. Peseau says, "I am sure, however,
7 that use of the current natural gas prices in the net
8 power supply expense model would eliminate all or a very
9 substantial portion of the forecasted increase in net
10 power supply expenses." Let's assume the $ 6.75 IGC price
11 rather than the $7.75 price that you have used, all other
12 things being equal, and you plug in that $6.75 price,
13 which is a lower price, a more current price, into the
14 AURORA model,' what do you get? Do you get higher prices
15 or lower prices?
16 A You would get a higher net power supply
17 cost.
Q So in looking at Mr. Peseau' s testimony,
19 is he correct or incorrect in his statement when he says
20 "I am sure"?
21
22
23
A No, I don't believe he is correct.
MR. KLINE: That's all I've got.
COMMISSIONER SMITH: Thank you, Mr. Kline.
24 Do we have any questions from the Commissioners?
25 COMMISSIONER REDFORD: No.
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1 COMMISSIONER SMITH: Do you have any
2 redirect, Mr. Price?
3 MR. PRICE: We do have some redirect.
4 Thank you, Madam Chair.
5
6 REDIRECT EXAMINATION
7
8 BY MR. PRICE:
9 Q Going back to the Order No. 30676, do you
10 have that in front of you?
11 A Yes, I do.
12 Q And the question was asked regarding the
13 WACOG mechanism that was used in that Order. Isn't it
14 true that the WACOG doesn't include Intermountain's gas
15 hedges and gas purchased as part of their strategy?
16 A I believe that is true.
17 Q And it doesn't include -- it does include
18 the gas purchased in storage for Intermountain Gas?
19
20
21
A Tha t I do not know.
Q But WACOG isn't a forecast; correct?
A No, the WACOG is an adj ustment. The WACOG
22 itself is not a forecast.
23 Q . And did you have access to these numbers
24 when you were preparing your testimony, the numbers that
25 are contained here in Order No. 30676?
CSB REPORTING
[phone]
1196 STERLING (Di)Staff
.
.
.
14
1 A This particular Order came out on November
2 12th. My testimony was filed on October 24th and,
3 obviously, prepared prior to October 24th, so it very
4 well could have been different numbers.
5 Q Okay, and even if they had been available,
6 would you have used them in your written testimony, those
7 numbers?
8 A Not necessar£ly. I may have looked at the
9 numbers. Whether I would have used them or not would
10 have taken some consideration on my part. You know, I
11 think the one point that I would make is this year has
12 been probably the most unusual year in terms of natural
13 gas prices, maybe ever, and for those of you who don't
follow natural gas prices on a daily basis, maybe you
15 follow gasoline prices, but they may be one price today,
16 they may be a different price tomorrow, they may be a
17 different price a month from now. You know, I bought my
18 last tank of gas for $1.50 a gallon, but I don't believe
19 that's what I'm going to pay for it next year. Despite
20 whatever forecast somebody makes today, it mayor may not
21 be what prices turn out to be.
22
23
MR. PRICE: Thank you. That's all.
COMMISSIONER SMITH: Thank you,
24 Mr. Sterling.
25 COMMISSIONER REDFORD: Thank you very
CSB REPORTING
[phone]
1197 STERLING (Di)
Staff
.
.
.
1 much.
2
3
4 obj ection.
MR. PRICE: May this witness be excused?
COMMISSIONER SMITH: He may, if there's no
5 (The witness left the stand.)
6
7
MR. PRICE: Staff calls Mr. Lynn Anderson.
8 LYNN ANDERSON,
9 produced as a witness at the instance of the Staff,
10 having been first duly sworn, was examined and testified
17
18
19
20
11 as follows:
12
13
14
15 BY MR. PRICE:
16 Q
A
Q
A
Q
21 Commission?
22
23
A
Q
DIRECT EXAMINATION
Can you please state your name?
Lynn Anderson.
And who is your employer?
The Idaho Public Utili ties Commission.
And what is your job title at the
Economist.
And did you have occasion to prepare
24 wri tten testimony, direct written testimony, in this
25 case?
CSB REPORTING
[phone]
1198 ANDERSON (Di)Staff
.
.
.
1 A Yes.
2 Q Including Exhibit Nos. 150 through -- I'm
3 sorry, 148 through 150?
4 A Yes.
5 Q And do you have any corrections or
6 addi tions to that testimony?
7 A No.
8 Q And if I were to ask you the same
9 questions that are contained in your written direct
10 testimony today, would your answers still be the same?
11 A Yes.
12 MR. PRICE: I would move at this time to
13 admit Mr. Anderson's testimony, including Exhibit Nos.
14 148 through 150 on to the hearing record as if read.
15 COMMISSIONER SMITH: If there is no
16 obj ection, we will spread the prefiled testimony as if
17 read and identify Exhibits 148 through 150.
18 (The following prefiled direct testimony
19 of Mr. Lynn Anderson is spread upon the record.)
20
21
22
23
24
25
CSB REPORTING
[phone]
1199 ANDERSON (Di)
Staff
.
.
.
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Lynn Anderson and my business
4 address is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utili ties
7 Commission as a Staff economist.
8 Q.What are your duties with the Commission?
9 A.Currently, my primary duties are evaluating
10 energy efficiency policy, opportunities, barriers,
11 efforts and cost-effectiveness, the results of which are
12 used to make recommendations to the Commission and other
13 enti ties. Additional duties include investigating
14 utili ty applications, customer petitions and conducting
15 general research.
16 Q.Would you please outline your academic and
- 17 professional background?
18 A.I have a Bachelor of Science degree in
19 government and a Bachelor of Arts degree in sociology,
20 both from Idaho State University where I also studied
21 economics and architecture. I studied engineering at
22 Northwestern Uni versi ty and Brigham Young Uni versi ty and
23 public administration and quanti tati ve analysis at Boise
24 State University.
25 I have attended many training seminars and
conferences regarding utility regulation, operations,
CASE NO. IPC-E-08-10
10/24/08 1200 ANDERSON L.(Di) 1
STAFF
.
.
.
1 forecasting, marketing and program evaluation,
2 including Lawrence Berkeley Laboratory's Advanced
3 Integrated Resource Planning seminar in 1994, the
4 Northwest Public Power Association's Troubleshooting
5 Residential Energy Use course in 2001, and the
6 International Energy Program Evaluation conferences in
7 2003, 2005 and 2007.
8 I began my employment with the Commission in
9 1980 as a utility rate analyst. In 1983 I was appointed
10 to the position of telecommunications section supervisor
11 and in 1992 I was appointed to my present position as an
12 economist. In that capacity I have been a Staff
13 representati ve to the Northwest Energy Efficiency
14 Alliance, Avista Utilities' External Energy Efficiency
15 Board, Idaho Power's Energy Efficiency Advisory Group,
16 the Northwest Power and Conservation Council's Demand
17 Response Ini tiati ve, the Energy Efficiency and
18 Conservation Task Force of the Idaho Strategic Energy
19 Alliance, and' to subgroups working on issues within the
20 National Action Plan for Energy Efficiency.
21 Since 1999 I have served the Commission as a
22 policy strategist for electricity and telecommunications
23 issues on an as-needed basis.
24 From 1975 to 1980 I was employed by the Idaho
25 Transportation Department where I performed benefit/cost
CASE NO. IPC-E-08-10
10/24/08 1201 ANDERSON L.(Di) 2
STAFF
1 analyses of highway safety improvements and other.2 statistical analyses.
3
4 /
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6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1202 ANDERSON L.(Di)2a10/24/08 STAFF
.
.
.
1 Q.What is the purpose of your testimony?
2 A.The purposes of my testimony are to provide
3 information regarding Idaho Power's efforts to promote
4 energy efficiency (aka demand-side management or DSM) and
5 to recommend that the Commission defer a prudency finding
6 for Idaho Power's DSM expenses until such time that the
7 Company is able to provide a more comprehensive
8 evaluation package of its DSM programs and efforts.
9 I also present the Staff's recalculation of the
10 fixed cost adjustment (FCA) mechanism's fixed costs per
11 customer (FCC) and fixed costs per energy (FCE).
12 Prudency of Etficiency/DSM Expenses
13 Q. Does Idaho Power's Application or the pre-filed
14 testimony of any witness in this case ask the Commission
15 to determine prudency of the Company's past energy
16 efficiency or demand-side management (DSM) expenses?
17 A.No, there is no such request. However, Idaho
18 Power witness Theresa Drake, in pre-filed testimony and
19 exhibits, provided a general overview of the Company's
20 rapid expansion of energy efficiency personnel and
21 programs, its current energy efficiency programs, and
22 total annual energy and peak demand savings estimated to
23 have been achieved from DSM programs in 2007. Neither
24 the Application nor Ms. Drake provided much information
25 about cost-effectiveness or prior years' estimated DSM
achievements, although Ms. Drake did
CASE NO. IPC-E-08-10
10/24/08 1203 ANDERSON L.(Di) 3
STAFF
.
.
.
1 mention that Idaho Power's Demand-Side Management 2007
2 Annual Report was filed with the Commission on March 14,
3 2008.
4 Q.Were you able to evaluate prudency of Idaho
5 Power's 2003-2007 DSM expenditures based on the Company's
6 filing?
7 A.No, there was not sufficient information in the
8 filing to assess DSM prudency. Consequently, many
9 production requests and follow-up questions needed to be
10 asked, but it became apparent that the Company does not
11 yet have sufficient information to fully justify a
12 prudency determination by the Commission.
13 Q. On page 12, lines 12 and 13, of Ms. Drake's
14 pre-filed testimony are statements that Idaho Power's DSM
15 programs saved 91,145 megawatt-hours (MWh) and reduced
16 peak load by 57 megawatts in 2007. Are the veracities of
17 those numbers readily verifiable by Company information
18 provided in this case?
19 A.No. However, they are consistent with the
20 savings reported by Idaho Power on page 56 (in Appendix
21 3) of its DSM 2007 Annual Report. For clarification, it
22 is worth noting that the 91,145 MWh were the annual
23 savings reported as occurring due to program efforts in
24 2007, presumably less than 50% of which would actually be
25 saved in 2007. The reported energy savings occurring in
CASE NO. IPC-E-08-10
10/24/08 1204 ANDERSON L.(Di) 4
STAFF
1 2007 due to the Company's DSM efforts from 2003 through.2 2007 are probably close to,but less than,the sum of
3 each prior year's annual
4
5 /
6
7 /
8
9 /
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1205 ANDERSON L.(Di)4a10/24/08 STAFF
.
.
.
1 savings plus about one-half of 2007' s annual savings.
2 Those annual savings numbers are shown on page 70 of the
3 same 2007 DSM Report. The sum of 2003-2006' s savings
4 plus half of 2008' s total to about 190,000 MWh saved in
5 2007, reportedly as a result of Idaho Power's DSM efforts
6 from 2003 through 2007.
7 More to the point of the question though, is
8 whether Idaho Power has provided sufficient measurement
9 and evaluation documentation of its energy savings and
10 peak load reduction estimates. The answer to that
11 question is that the Company has completed a few
12 important program evaluations and, I believe, is
13 earnestly working on a more comprehensive overall
14 evaluation of programs. In response to Staff Production
15 Request No. 94, the Company stated that it hired a
16 full-time Energy Efficiency Evaluator in 2007 and" (p) art
17 of the duties associated with this position has been to
18 ini tiate a systematic review and evaluation of each
19 demand side m~nagement program Idaho Power offers." The
20 response continues with a description of the many
21 evaluations that are currently underway and concluded
22 with the statement "As factors change, or new data is
23 obtained, these (cost-effectiveness) studies are revised
24 and updated." Thus, although the new, full-time
25 evaluator was not hired until December 2007, it seems
CASE NO. IPC-E-08-10
10/24/08 1206 ANDERSON L.(Di) 5
STAFF
1 likely that wi thin the next year or so Idaho Power will.2 have substantially completed reasonably
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1207 ANDERSON L.(Di)5a10/24/08 STAFF
.
.
.
13
14
1 comprehensive evaluations of its DSM programs and
2 portfolio, which should facilitate verification of
3 cost-effecti veness and prudency of planning,
4 implementation and evaluation.
5 Q.Is reasonable proof of DSM cost-effectiveness
6 compared to the least-cost supply-side resource both
7 necessary and sufficient for determination of the
8 Company's prudency in planning, implementing and
9 evaluating its programs?
10 A.No. While substantially proving actually
11 achieved cost~effectiveness is an important goal, it is
12 generally recognized that some prudent utility DSM
programs will not achieve this standard, due to
circumstances beyond utility control or other factors.
15 Furthermore, while achieving DSM cost-effectiveness
16 vis-a-vis supply-side alternatives is important, it is
17 just as important that the DSM al ternati ves as
18 implemented be as cost-effective as practicable from the
19 utili ty perspective. This does not mean that other goals
20 (e.g. customer class equity, intra-class distribution,
21 and total resource, participant and non-participant
22 cost-effectiveness) are not also important, but rather
23 that within the bounds of due consideration of all goals,
24 the least-cost DSM implementation al ternati ve is the most
25 prudent. In other words, it is not prudent to pay more
CASE NO. IPC-E-08-10
10/24/08 1208 ANDERSON L.(Di) 6
STAFF
1 for a DSM resource than is necessary..2 Q.Putting aside the question of prudency,are
3 Idaho
4
5 /
6
7 /
8
9 /
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1209 ANDERSON L.(Di)6a10/24/08 STAFF
.
.
1 Power's DSM programs cost-effective compared to
2 supply-side resources?
3 A.I believe that most of the Company's DSM
4 programs will likely prove to be cost-effective compared
5 to supply-side resources. Idaho Power generally selects
6 its DSM programs based, in part, on expected
7 cost-effectiveness from the total resource and utility
8 perspectives. Exhibit No. 148, from the Company's
9 response to Staff's Production Request No. 96, shows
10 preliminarily cost-effectiveness analyses from those two
11 perspectives, compared only to supply-side resources
12 (i.e. not compared to alternative DSM costs). It is
13 important to note that Staff considers these analyses as
14 preliminary and in need of further refinement. For
15 example, it is not entirely clear in these analyses how
16 net-to-gross factors were included in the benefit
17 calculations, or whether non-electricity savings are
18 included, or whether tax credits are assumed to reduce
19 total resource costs. Staff expects such intricacies of
20 actual achieved program cost-effectiveness will become
21 more transparent as many of the Company's formal program
22 evaluations are completed.
23 Q.Gi ven your recommendation that the Commission
24 defer its determination regarding Idaho Power's DSM.25 prudency, why is it important to discuss
cost-effectiveness and prudency issues?
CASE NO. IPC-E-08-10
10/24/08 1210 ANDERSON L.(Di) 7
STAFF
.
.
.
1 A. As the costs of supply-side resources have
2 risen, the value of demand-side resources has also risen,
3 the consequence being that utili ties are spending many
4 millions of dollars more on DSM programs. Gi ven the much
5 higher level of DSM expenditures, it is increasingly
6 important that the utili ties, other parties and the
7 Commission have clear concepts of what constitutes DSM
8 prudency.
9 Idaho Power's original and supplemental
10 responses to Staff's Production Request Nos. 99 and 100
11 demonstrate the need for "prudency" clarification. For
12 example, in response to Staff's request that Idaho Power
13 provide examples where the Company chose least-cost DSM
14 alternatives, the Company did not provide any such
15 examples. Instead, it said that it considers al ternati ve
16 demand-side costs and reiterated its prior response that
17 priori ties in addition to cost-effectiveness are that DSM
18 programs have a customer focus, be equitably distributed,
19 and be earnings neutral.
20 Q.Is earnings neutrality an important DSM goal of
21 the Commission?
22 A.Not exactly. The lack of earnings neutrality
23 was recognized by the Commission as a DSM concern in its
24 approval of Idaho Power's 3-year pilot for a fixed-cost
25 adj ustment (FCA) mechanism, but I'm not aware of any
CASE NO. IPC-E-08-10
10/24/08 1211 ANDERSON L.(Di) 8
STAFF
1 Commission Orders stating utility DSM programs should be.2 earnings neutral.In fact,in Order No.22299 issued in
3 1989,the Commission said
4
5 /
6
7 /
8
9 /
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1212 ANDERSON L.(Di)8a10/24/08 STAFF
.
.
.
1 "We certainly do not obj ect to considering lost revenue
2 as one of the many variables to be considered in
3 determining (DSMJ price, but we reject it as a
4 controlling factor." (p. 16).
5 Q.Does Idaho Power currently have a formal
6 business plan for implementing DSM programs?
7 A.No. Idaho Power's last formal business plan
8 for DSM is dated April 15, 2003. In response to Staff's
9 Production Request No. 115, the Company explained its
10 "multi-dimensional approach to DSM business planning,"
11 which includes DSM potential studies, long-term IRP
12 planning, strategic planning, budget planning,
13 consul tation with the Energy Efficiency Advisory Group
14 (EEAG), and concluding with "governance by the Energy
15 Efficiency Guiding Council." This final decision-making
16 Council is comprised of Idaho Power's senior management
17 and representatives of the Energy Efficiency Department.
18 Although the Company provided some, but not all, minutes
19 of EEAG meetings, it provided no similar records of
20 Energy Efficiency Guiding Council meetings where the
21 final DSM decisions are actually made. While the lack of
22 a current, formal DSM business plan may not necessarily
23 be imprudent, that omission combined with the lack of
24 access to meeting minutes where final DSM decisions are
25 made, results in less decision-making transparency and
does raise some concerns.
CASE NO. IPC-E-08-10
10/24/08 1213 ANDERSON L.(Di) 9
STAFF
.
.
.
1 Q.What additional information are you providing
2 and why is it important?
3 A.Exhibi t No. 149, copied directly from Idaho
4 Power's Appendix 2 in its 2007 DSM Annual Report, shows
5 the Company's expenses and funding sources for its
6 various DSM efforts in 2007. This exhibit provides an
7 indication of program magnitudes and an appreciation for
8 the various and sometimes mixed funding sources, two of
9 which are not under the regulatory authority of the Idaho
10 Commission. However, the amounts shown are neither
11 entirely complete nor 100% accurate. For example, a
12 significant missing piece is the additional $380,000
13 amount due to the Northwest Energy Efficiency Alliance
14 (NEEA) that was credited from Idaho Power funds being
15 held by NEEA (IPC' s 3rd Supplemental Response to Staff's
16 Production Request No. 89). And the Company noted that
17 relati vely minor corrections would be necessary in future
18 DSM Annual Reports (IPC' s 2nd Supplemental Response to
19 Staff's Production Response No. 89). Due in part to
20 Idaho Power's late responses to production requests and
21 other Staff priorities, the Company's DSM expenses from
22 2003 through 2007 have not yet been audited.
23 Exhibit No. 150 shows the Company's total
24 system annual direct DSM expenses (including direct
25 overhead), indirect overhead expenses, and total DSM
CASE NO. IPC-E-08-10
10/24/08 1214 ANDERSON L.(Di) 10
STAFF
1 expenses for each year from 2003 through 2007.This.2 exhibi t shows two
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1215 ANDERSON L.(Di)lOa10/24/08 STAFF
.
.
.
1 important trends. First, Idaho Power's DSM programs have
2 been increasing very rapidly - the total DSM expenses in
3 2007 are nearly six times higher than those in 2003.
4 Second, the indirect overhead program expenses increased
5 nearly 10-fold from 2003 to 2007. From just 2006 to
6 2007, indirect overhead expenses increased 147%, more
7 than four times faster than the 33% increase in direct
8 program expenses. Although the disproportionate indirect
9 overhead expense increases are not necessarily alarming,
10 they probably. warrant close monitoring.
11 As discussed earlier in my testimony, Idaho
12 Power has only recently begun a more thorough and
13 comprehensive program evaluation process. While this
14 process may further increase indirect as well as direct
15 overhead expenses, it should also provide necessary
16 information for Idaho Power and other parties to better
17 assess actual program implementation processes and
18 results, and for the Company to make improvements to
19 programs, processes and assumptions where the evaluations
20 show such changes are appropriate.
21 Q.Do you have any other concerns regarding Idaho
22 Power's DSM prudency?
23 I have quite a few, mostly relatively minor,A.
24 questions and concerns, many or most of which I expect
25 will be addressed by the Company's completion of program
CASE NO. IPC-E-08-10
10/24/08 1216 ANDERSON L.(Di) 11
STAFF
1 evaluations,or which Staff can otherwise pursue outside.2 this rate case process.
3
4 /
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6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-~-08-10 1217 ANDERSON L.(Di)11a10/24/08 STAFF
.
.
.
1 Q.Please summarize your recommendations regarding
2 the prudency of Idaho Power's expenses for its energy
3 efficiency efforts from 2003 through 2007.
4 A.Staff recommends that the Commission defer
5 determination of prudency until such time that Idaho
6 Power has sufficiently evaluated its DSM programs and
7 processes and files a request for prudency determination.
8 This filing could occur wi thin a general rate case
9 application, a tariff rider application, or a stand-alone
10 application.
11 Staff further recommends that the Idaho Power
12 should be expected to provide with its filing a
13 reasonable, appropriate and credible evaluation of each
14 DSM program, and an overall evaluation of the Company's
15 DSM decision-making processes, including its use of
16 program evaluations to improve programs and processes.
17 Transparency of financial accounting, data, assumptions,
18 calculations and decision-making is paramount for Staff's
19 and the Commission's investigation of prudency.
20 Fixed-Cost Adjustment (FCA) Recalculation
21 Q.Has the Staff recalculated the fixed cost per
22 customer (FCC) and fixed cost per energy (FCE) for
23 residential and small commercial customer classes as
24 required for continuation of the fixed cost adjustment
25 (FCA) pilot mechanism?
A. Yes, this has been done using Staff's proposed
CASE NO. IPC-E-08-10
10/24/08 1218 ANDERSON L.(Di) 12
STAFF
.
.
.
21
22
23
24
25
1 revenue requirements and rate designs for Schedules 1, 4,
2 5 and 7 and Idaho Power's model for these calculations as
3 presented by Idaho Power witness Tim Tatum's Exhibit No.
4 71 and explained in his pre-filed testimony on pages
5 54-60.
6 For residential customers (Sch. 1, 4 and 5),
7 Staff's recalculated fixed cost per customer (FCC) is
8 $428.01 per year and the fixed cost per energy (FCE) is
9 3. 3045ç per kilowatt-hour.
10 For small commercial customers (Sch. 7),
11 Staff's recalculated FCC is $282.05 per year and the FCE
12 is 4.6167 ç per kilowatt-hour.
13 Q. Does this conclude your direct testimony in
14 this proceeding?
15 A.Yes, it does.
16
17
18
19
20
CASE NO. IPC-E-08-10
10/24/08
1219 ANDERSON L.(Di) 13
STAFF
.
.
.
1
2 open hearing.)
(The following proceedings were had in
4 for cross-examination.
MR. PRICE: And I now present this witness3
5 COMMISSIONER SMITH: Okay. Let's see,
6 Mr. Ward, do you have questions?
7
8
9
10
11
12
13
14 Madam Chair.
15
16
17
18 Mr. Kline.
19
20
21
22
23 BY MR. KLINE:
24
25
Q
MR. WARD: I do not. Thank you.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No, Madam Chairman.
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: No questions. Thanks.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions,
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: No questions. Thank you.
COMMISSIONER SMITH: It's all down to you,
MR. KLINE: Thank you, Madam Chairman.
CROSS-EXAMINATION
Mr. Anderson, in your testimony, you
recommend that Idaho Power make some kind of a new filing
CSB REPORTING
[phone]
1220 ANDERSON (X)
Staff
.
.
.
19
20
1 and ask for a prudency review of its energy efficiency
2 and demand response programs; is that accurate?
3 A Yes.
4 Q And in that proceeding, is it your
5 understanding that Staff and intervenors would have an
6 opportuni ty to look at the expenditures that the Company
7 had made for DSM, energy efficiency and if at the
8 conclusion of that review they recommended to the
9 Commission that some expense was not prudent that that
10 expense could then result -- then that recommendation if
11 the Commission agreed with it, that could result in
12 revenue being denied to the Company to recover its costs
13 for DSM?
14 A If the Commission agreed with it, then
15 that is what would happen.
16 Q All right. Now, on page 12 of your
17 testimony, starting on line 10, you describe -- I' II wait
18 until you get there. Ready?
A Yes.
Q On page 10, line 12 -- I'm sorry, page 12,
21 line 10, you describe what you expect that Idaho Power
22 would provide in this new filing that it would make and
23 you talk about financial accounting, materials, data,
24 assumptions, calculations, and in that response, you
25 refer to decision making two times.
CSB REPORTING
[phone]
1221 ANDERSON (X)Staff
.
.
.
1 A Yes.
2 Q What does decision making mean in the
3 context of evaluating the Company's DSM programs?
4 A The first time I use it I'm referring to
5 an overall evaluation of the Company's DSM decision
6 making and what I envision is just what I say there,
7 someone, some entity evaluating how Idaho Power makes its
8 DSM decisions. That could be an outside consultant that
9 Idaho Power hires or it could be just someone wi thin the
10 Company, but some analysis of how these decisions are
11 being made, because the decisions aren't entirely
12 transparent to outsiders such as the Commission Staff.
13 Q Well, let me follow up on that a little
14 bit.If a DSM program, energy efficiency or demand
15 response program, is cost effective compared to a supply
16 side resourcer if it passes the TRC and the UC tests that
17 you define and discuss in your testimony, if the Energy
18 Efficiency Advisory Group looks at the program, they like
19 it, they tell the Company that they think they ought to
20 move forward with it, they move forward and the customers
21 like it and it's a very successful program, but during
22 the after-the-fact prudency review the Staff has a
23 quarrel with the decision making part of the equation,
24 would that be grounds for exclusion of the Company's
25 expenses incurred as being imprudent?
CSB REPORTING
[phone]
1222 ANDERSON (X)Staff
.
.
1 A I guess it's possible if it was revealed
2 that the decision making process was faulty.
3 Q But if it passed all the tests for
4 reasonableness that we have?
5 A Idaho Power doesn't look at all the tests
6 for reasonableness. It looks at two.
7 Q Okay, but it also takes it to the Energy
8 Efficiency Advisory Group, correct, and they look at
9 it?
10 A It does after Idaho Power has
11 predetermined that it would like to pursue this.
12 Q Well, suppose it went through all of those
13 steps, is it still possible that Staff would come in and
14 say well, it's working very well, the customers like it,
15 it went through all these steps and yet, we don't like
16 the decision making process that you used to come up with
17 it in the first place, would that be grounds for denying
18 the expenses as being imprudent?
19 A Speaking for myself, if I was pleased with
20 it, the progr~m, and it passed all the tests, including
21 the non-participant test, then I can't imagine that I
22 would be displeased with the decision making process.
23 Q Because that's a pretty subj ecti ve
24 standard to subject the program to, wouldn't you agree?.25 A What is that?
CSB REPORTING
[phone]
ANDERSON (X)Staff1223
.
.
.
1 Q The decision making process, whether it
2 was a good one or a bad one.
3 A Yes, all of these are pretty subj ecti ve.
4 All the points of evaluation are somewhat subj ecti ve.
5 Q Well, is the TRC and UC tests
6 subjective?
7 A Yes.
8 Q And they don't come up with a cost/benefit
9 ratio as a result of those tests being applied?
10 A They do. They're based on forecasts.
11 Q But it's a mathematical computation based
12 on forecasts?
13 A That are subjective, yes. I think the
14 prior witness discussed forecasts a little bit.
15 Q But isn't that the basis on which you make
16 a decision on the front end of a decision making process,
17 you look at what you think is going to happen and then
18 you make a decision to proceed with it and I guess the
19 concern, the question that I've got is what obj ecti ve
20 standards is the Staff going to apply or the intervenors
21 in this new proceeding to determine whether or not
22 something has been imprudent?
23 A Well, actually, I made a list of these
24 just a few minutes ago, if you want me to read those, if
25 that's okay.
CSB REPORTING
[phone]
1224 ANDERSON (X)Staff
.
.
.
1 Q Yeah, we really are trying to get a sense
2 of that here.
3 A First, I would look to see if there was a
4 post-implementation evaluation done and if there wasn't,
5 that's a red flag, and in fact, I'd probably suggest
6 in fact, I have 10 years ago, I recommended that one of
7 Idaho Power's programs be partially disallowed because it
8 didn't do an impact evaluation, but other things I would
9 look for are good contract management for programs and
10 evaluations, current, accurate and appropriately targeted
11 marketing, pre- and post-implementation
12 cost-effectiveness evaluations which I've already
13 mentioned from several perspectives. I'd prefer four,
14 Idaho Power looks at two, the Commission required three
15 of Idaho Power. I'd look for reasonable utility cost
16 control, including incentives and overhead, control of
17 fraud and waste, use of post-implementation evaluations
18 to improve programs, communications between implementers
19 and evaluators and evaluations that adjust for baseline
20 savings.
21 Q Well, I would certainly have to agree with
22 your prior statement that a number of those are certainly
23 subjective kinds of analyses, but it's good to have a
24 list. Are you familiar with the process that Idaho Power
25 goes through whenever it asks this Commission for a
CSB REPORTING"
[phone]
1225 ANDERSON (X)Staff
.
.
.
1 certificate of convenience and necessity for a power
2 plant?
3 A Somewhat. I've not been involved in one
4 directly.
5 Q Well, let me describe it to you and
6 certainly, people in the room can tell me if I'm wrong if
7 I don't accurately portray it, but when the Company needs
8 to get a certificate of public convenience and necessity
9 from this Commission to build a power plant, it goes to
10 the Commission, it presents the cost data, the analysis
11 that it's done to justify the construction of a power
12 plant, and it presents the best information it has at the
13 time as to the cost of it and the need for it and whether
14 when it's built there will be sufficient load for it or
15 sufficient need for it and in its Orders granting
16 certificates of public convenience and necessity, the
17 Commission, the routine language that we see in those
18 Orders is that based on the information that was
19 presented to the Commission at the time, based on the
20 analysis that the Company has presented to them, in the
21 normal course of business there is a -- it is likely that
22 the utility will be able to recover its costs in rates,
23 so it's saying based on what we know today, this is a
24 prudent decision, go ahead and spend the money.
25 Now, we' ii look at it in the future for
CSB REPORTING
[phone]
1226 ANDERSON (X)Staff
.
.
.
1 prudency, but unless you really screw up, you're going to
2 be able to recover your money for this power plant.
3 Would you say that putting this in the context of DSM
4 programs when the Company does its evaluation on the
5 front end, it presents the program to the EEAG, it passes
6 the tests based on what we think is going to happen, the
7 UC and the TRC tests, that ought to be equivalent to the
8 order that we get from the Commission on a certificate of
9 public convenience and necessity, based on what we know
10 today, looks good, go ahead and spend the money?
11 A That sounds reasonable. I doubt that the
12 Commission Order on a CPCN says up front that it's
13 prudent to do like you've just said a moment ago.
14 Q If I did, I misstated, they don't say
15 that. They do say in the ordinary course of business,
16 the utility can expect to recover its costs.
17 A Okay.
18 Q And you'd be okay with the same
19 applying that same kind of process or analysis to DSM
20 programs?
21 A I believe so.
22 Q Now, yesterday in some discussions that
23 Commissioner Kempton had with the Power Company's witness
24 Theresa Drake, they discussed some of your testimony on
25 page 6, line 21. Are you there?
CSB REPORTING
[phone]
1227 ANDERSON (X)Staff
.
.
.
1 A Yeah.
2 Q Okay, and there's a discussion in there
3 about, again, what you, I believe, are expecting to see
4 in the way of a cost-effectiveness analysis, and focusing
5 on line 21, you're talking about -- and towards the end
6 of that line it says, "the least-cost DSM implementation
7 alternative is the most prudent," and that's the one
8 Commissioner Kempton picked up on as well. I want to
9 make sure what you mean by that sentence because it
10 wasn't clear to us.
11 A I apologize if my writing was deficient.
12 All I meant was what I mentioned just a minute ago,
13 actually, that once Idaho Power is implementing a program
14 that it choose the incentives that it pays customers that
15 are the least amount to get the desired effect and that
16 it operate its programs, that the administration is least
17 cost to get the desired effects and that's all I meant by
18 that.
19 Q Okay; so you're not talking about
20 comparing excuse me, you're not talking about
21 comparing one DSM program to another and if the Company
22 chose one program that was slightly less cost effective
23 than another, then that selection would be deemed to be
24 imprudent?
25 A No.
CSB REPORTING
[phone]
ANDERSON (X)Staff1228
.
.
20
21
1 Q Now, you talked about a post-evaluation as
2 being a critical component of the prudency review and
3 that, in fact, in a prior case the lack of a
4 post-evaluation review was, you believe, grounds for
5 holding the program to be imprudent; is that what you
6 said?
7 A Yes.
8 Q Okay; so again talking in terms of almost
9 like the certificate of convenience and necessity, let's
10 suppose the program, everybody moves forward in good
11 faith thinking this program is going to be a great one
12 and then in the end the post-evaluation shows that it
13 wasn't as good as we thought it was going to be going in,
14 would that be grounds for eliminating those expenses as
15 being imprudent?
16 A No. In fact, on that same page of my
17 testimony
18 Q What page is that?
19 A Page 6.
Q Okay.
A Starting on line well, the end of line
22 10 and going to the next couple or three lines, I
23 specifically address that.
24.25
Q Okay. Mr. Anderson, I don't know if
you'll know the answer to this, but for ratemaking
CSB REPORTING
[phone]
1229 ANDERSON (X)Staff
.
.
.
1 purposes, it's true, is it not, that the Company only
2 collects its DSM expenditures dollar for dollar as an
3 expense? There's no economic upside to the Company for
4 pursuing DSM programs from a ratemaking standpoint.
5 A I think that's generally true. There
6 might be some small exception, but I can't think of it
7 right now.
8 Q I'm sorry , it's not like putting the costs
9 in rate base and earning a ,return, we just collect them
10 dollar for dollar?
11 A That's true. It hasn't always been true
12 and may not be true in the future, I don't know.
13 Q But currently that's the situation?
14 A Yes.
15 Q And so to the extent that the Company's
16 expenditures are deemed to be imprudent, they're gone;
17 right?
18 A That would be correct.
19 MR. KLINE: That's all I have.
20 COMMISSIONER SMITH: Do we have questions
21 from the Commission? Commissioner Kempton.
22
23
24
25
CSB REPORTING.
[phone]
1230 ANDERSON (X)Staff
.
.
.
1 EXAINATION
2
3 BY COMMISSIONER KEMPTON:
4 Q Madam Chairman, Mr. Anderson, has the
5 Commission every deemed any of the Idaho Power DSM
6 proj ects imprudent?
7 A Yes.
8 And what were they?Q
9 Do you want the case number or the dollarA
10 amount?
11 No, just the general response to formulateQ
12 an idea of how many of these there may have been.
13 A Just one and it was for about two years of
14 a five-year program, as I recall. It was 2 or $300,000,
15 but the Commission did invite Idaho Power to reapply for
16 a prudency. I'm not sure exactly what the terminology
17 was, but Idaho Power did do that and subsequently the
18 Commission did rule that it was prudent a few months or a
19 year later.
20 Q And, Mr. Anderson, was the test of
21 prudency based on the TRC and UC evaluation methods, in
22 other words, the cost ratio to benefit being equal to one
23 or better?
24 For that particular program?A
25 Yes.Q
CSB REPORTING
[phone]
1231 ANDERSON (Com)Staff
.
.
.
1 A The stated benefi t/ cost ratio by Idaho
2 Power was greater than one. What Idaho Power did not do
3 was a post-implementation evaluation of the program and
4 the Commission found that that was imprudent, but, like I
5 said, did invite the Company to reapply.
6 Q Mr. Anderson, does a program have to be
7 completed before there can be a post-implementation
8 evaluation?
9 A No, there should be continuous
10 evaluation.
11 Q When you requested in Staff Production
12 Request No. 91, Theresa Drake responded and since I don't
13 have a copy, I'll read this in its entirety. It's about
14 three lines. "In response to Staff Production Request
15 No. 91, the Company made available copies of all
16 post-implementation evaluations of all Idaho-funded DSM
17 programs completed by or for Idaho Power from 2003 to
18 2008." Is that response adequate to you to the
19 production request in 91?
20 A I'm assuming the Company did provide all
21 of its evaluations. It provided not only the post-impact
22 evaluations but pre-impact evaluations, surveys with no
23 evaluations and a bunch of other stuff, so it did respond
24 to the question and then some, but what it did not do was
25 provide evaluations for all programs. There are some
CSB REPORTING
[phone]
1232 ANDERSON (Com)Staff
.
.
.
1 missing, but the response stated that Idaho Power had
2 recently hired a full-time evaluator and was in the
3 process of doing those evaluations.
4 Q So the question, Mr. Anderson, revolves
5 around the word "completed" and the question wasn't asked
6 to assign fault. It was to try and determine in my own
7 mind whether all programs should have post-implementation
8 checks and not just the ones that were completed as far
9 as information is passed forward.
10 Programs should be periodically evaluated.A
11 They may not ever be completed. They may go on for years
12 and years and you shouldn't do that without an evaluation
13 and there is at least one, perhaps more than one, for
14 Idaho Power that has never been evaluated and some that
15 are in sore need of evaluation and I think they're doing
16 those right now.
17 Okay, and if I could have just a secondQ
18 here. Another question that Theresa Drake responded to
19 is one that I' had identified and that is since my time on
20 the Commission has been relatively short, the one thing I
21 have noticed in these DSM programs was the Commission's
22 consistent advocacy for cost effectiveness that was
23 measurable, you know, information that came back that
24 responded to the ratio test criteria, that it be cost
25 effective, that you're going to acquire all
CSB REPORTING
(208) 890-519ß
1233 ANDERSON (Com)Staff
.
.
.
1 cost-effecti ve programs, cost efficiency. Ms. Drake
2 submi tted a comment and I'll read this one. It's a
3 couple of lines long. However, I believe that the
4 Commission expects that these tests, which are the TRC
5 and the UC tests, expects them to be used merely as
6 guidelines and should not be used to exclude projects
7 that may be desirable as good policy. Is that a -~ I
8 don't want to phrase it that way. Idaho Power provided
9 me with a copy of a 2001 Order that the Commission put
10 out that had exactly those words in it. I cannot fault
11 this statement. The question revolves around the issue
12 of good policy, because to me, that seems ambiguous and I
13 haven't seen it in any of the Orders and I'm a little
14 surprised to see it in the 2001 Order that a policy
15 undefined as to who makes that has been included as a
16 part of Commission Orders, and as a matter of fact, her
17 second point, that's the first point, that's the first
18 question, is that how you have addressed these issues
19 when you were in the EEAG, in the advisory group, I
20 should say, at Idaho Power, that policy was a factor in
21 determining a prudent proj ect?
22 If the Commission were to direct IdahoA
23 Power to do a program that it didn't think was cost
24 effective, I guess as a Commission employee I'd have to
25 say well, that's the policy you should follow, but the
.
CSB REPORTING
[phone]
1234 ANDERSON (Com)Staff
.
.
.
1 Commission has not done that. I'll shut up there.
2 Q In your work with the advisory staff, have
3 you advised the advisory group, I should say the
4 efficiency advisory group with Idaho Power, have you
5 advised that group when you have felt that there were
6 deficiencies in the way Idaho Power is identifying
7 programs or doing post-implementation effort? And I'll
8 just leave the question at that. Have you identified
9 before the group when those deficiencies are there?
10 A I've been quite vocal at Idaho Power's
11 EEAG meetings and via e-mail and phone calls on
12 occasion.
13 Q Mr. Anderson, do you feel that those
14 concerns have been adequately addressed by Idaho Power,
15 specifically addressed in that group?
16 A I think Idaho Power generally listens to
17 me and other members of the group.
18 COMMISSIONER KEMPTON: That's all my
19 questions, Madam Chair.
20 COMMISSIONER SMITH: Thank you. Mr.
21 Price.
22 MR. PRICE: Yes, I have a few questions.
23
24
25
CSB REPORTING
[phone]
1235 ANDERSON (Com)Staff
.
.
.
1 REDIRECT EXAMINATION
2
3 BY MR. PRICE:
4 Q Going back to the example that Mr. Kline
5 gave of the CPCN process and whether or not you would be
6 in favor of a CPCN-type process for the approval of DSM
7 programs, if the Company were to engage in this type of
8 process and apply for the approval of a DSM program via
9 that type of process, wouldn't it have to come before the
10 Commission?
11 A Yes, and I wasn't actually taking it that
12 far. I don't know that it would be a good idea for
13 the -- for Idaho Power or any other utility to bring
14 every program before the Commission and ask for some kind
15 of pre-sanctioning. Utili ties do do that when they feel
16 a special need, but in general, the utility should be in
17 charge of their programs and manage them prudently and go
18 forth and do them.
19 Q But hypothetically speaking, if that were
20 the process that were made available for the approval of
21 a DSM program, would that application have to come before
22 the Commission?
23
24
25
A Yes.
Q And finally, wouldn't -- with that
application, wouldn't the Company need to submit a
CSB REPORTING
[phone]
1236 ANDERSON (Di)Staff
.
.
.
1 commitment estimate with that application?
2 A I would assume so.
3 Q And they would have to commit to not
4 exceed that commitment estimate?
5 A Again, I would assume so.
6 Q And would the Company also need a
7 post-implementation analysis with that application after
8 the fact?
9 A I don't know if they currently need to do
10 that with a CPCN application. I don't know.
11 Q And just following up on Commissioner
12 Kempton's question regarding your participation in EEAG,
13 specifically, have you ever expressed the need, during
14 your meetings at the EEAG, have you ever expressed to the
15 group the need for a post-implementation study?
16 A I can't recall specifically. I know I
17 have in testimony filed before the Commission that Idaho
18 Power was
19 Q Ei ther that or been present when somebody
20 else expressed the need for a post-implementation
21 application?
22 A It's such standard practice that I don't
23 think anybody. generally says it needs to be evaluated.
24 That's just what everybody in the industry does.
25 MR. PRICE: Okay, I'll leave it at that.
CSB REPORTING
[phone]
1237 ANDERSON (Di)Staff
.1 Thank you.
2 COMMISSIONER SMITH: Thank you for your
3 help, Mr. Anderson.
4 (The witness left the stand.)
5
6 un til 3: 30 .
COMMISSIONER SMITH: Let's take a break
7 (Recess. )
8 COMMISSIONER SMITH: All right, I think
9 we're ready to go back on the record. Mr. Price.
10 MR. PRICE: Yes, Staff calls Mr. John
11 Nobbs to the stand.
.12
13
14
JOHN NOBBS,
produced as a witness at the instance of the Staff,
15 having been first duly sworn, was examined and testified
16 as follows:
17
18
19
20 BY MR. PRICE:
21 Q
22 your name?
23
24.25
A
Q
A
DIRECT EXAMINATION
Good afternoon. Could you please state
My name is John Nobbs.
And who is your employer?
I am employed by the Idaho Public
CSB REPORTING
[phone]
1238 NOBBS (Di)Staff
.
.
1 Utilities Commission.
2 Q And what is your job title?
3 A I'm a financial specialist.
4 Q And on October 24th of this year did you
5 have occasion to prepare written direct testimony,
6 including Exhibit Nos. 108 through 112 for this case?
7 A Yes.
8 Q Do you have any corrections or additions
9 to that testimony?
10 A No.
11 Q And if I were to ask you the same
12 questions contained in your written direct testimony
13 today, would your answers be the same?
14 A Yes.
15 MR. PRICE: I would now move that
16 Mr. Nobbs' testimony, including Exhibit Nos. 108 through
17 112, be spread across the hearing record as if read.
18 COMMISSIONER SMITH: If there is no
19 objection, we. will spread the prefiled testimony across
20 the record as if read and identify Exhibits 108 through
21 112.
22 (The following prefiled direct testimony
23 of Mr. John Nobbs is spread upon the record.)
24.25
CSB REPORTING
[phone]
1239 NOBBS (Di)Staff
.
.
.
1 Q.Please state your name and business address for
2 the record.
3 A.My name is John Nobbs. My business address is
4 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission (Commission) as an auditor in the Utilities
8 Division.
9 Q.What is your education, experience and
10 background?
11 A.I received a Bachelor of Science degree in 1971
12 from Fresno State College, with thirty units in
13 accounting. In 2000, I received a Master of Science
14 degree, with twelve units in accounting and taxation. I
15 completed the National Association of Regulated Utility
16 Commissioners' Annual Regulatory Studies Program, in
17 2007.
18 I have worked on budgets, forecasts, inventory
19 accounting, cost accounting and on currency transactions.
20 I have drawn trial balances and developed financial
21 statements from those trial balances. I performed
22 financial analysis. I have worked as a Chief Accountant,
23 Internal Auditor, Assistant Controller and as a
24 Controller. r was a Medicaid auditor.
25 During the time I have worked at the Idaho
CASE NO. IPC-E-08-10
10/24/08
1240 NOBBS, J. (Di) 1
STAFF
1 Public Utilities Commission,I have worked as an auditor.2 in the Utilities Division.
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1241 NOBBS,J.(Di)1a
10/24/08 STAFF
.
.
.
1 Q.What is the purpose of your testimony in this
2 case?
3 A.The purpose of my testimony is to explain the
4 resul ts of auditing FERC Account 920, Administrative and
5 General Salaries; 921, Office Supplies and Expenses; 923,
6 Outside Services Expense; 924, Property Insurance
7 Expense; 928, Regulatory Commission Expenses; and
8 930.200, Miscellaneous Expenses.
9 Q.What did you find during your audit of FERC
10 Account 920?
11 A.Account 920 - Administrative and General
12 Salaries, contains entries for administrative salaries,
13 employee benefits , incentive pay and similar expenses.
14 These charges are recorded in subaccounts. For example,
15 subaccount 920.001 contains entries for incentive pay.
16 Subaccount 920.350 contained four entries
17 identified as Executive Deferred Compensation for 2007,
18 totaling $459~ 524. These charges are for contributions
19 to or other charges related to a Rabbi Trust.
20 Q.What is a Rabbi Trust?
21 A.A Rabbi Trust is a type of grantor trust,
22 recei ving specific tax treatments under the Internal
23 Revenue Code.
24 According to the IRS website, this type of
25 trust is often used by businesses to provide "Golden
Parachutes"
CASE NO. IPC-E-08-10
10/24/08
1242 NOBBS, J. (Di) 2
STAFF
.
.13
14
1 or other forms of deferred compensation to a limited
2 group of employees.
3 In tax terminology, deferred compensation is
4 income which is not recognized until a later date.
5 Typically, that date is after retirement. This is
6 desirable for the employee because income is generally
7 subj ect to lower tax rates then.
8 The Internal Revenue Service has a model trust
9 agreement and explanations on its website at www. irs. gov.
10 As explained there, generally, contributions to a grantor
11 trust which benefit another person are taxable to that
12 person when contributed under the tax doctrines of
"Constructive Receipt" or "Economic Benefit."
A Rabbi Trust has a "safe harbor", precluding
15 taxation at the time of contribution. If the terms of
16 the trust document meet the requirements of the model
17 trust, Section 1 (d), the "Safe Harbor" will be recognized
18 by the Internal Revenue Service.
19 One effect of the "Safe Harbor" is to make
20 contributions to the trust available to satisfy the
21 claims of the donor's creditors if the donor becomes
22 insol vent or files for bankruptcy. These contributions,
23 in the hands of the trust, are called "corpus." Because
24 creditors can exercise a prior claim on trust corpus, the.25 trust beneficiaries bear a "substantial risk of
forfei ture. "
CASE NO. IPC-E-08-10
10/24/08
NOBBS, J. (Di) 3
STAFF
1243
.
.
1 Simply put, contributions can be taken back until they
2 are given to the employee. According to Treasury
3 Regulation Section 1-451-2 (a), this "risk of forfeiture"
4 estabiishes the "safe harbor", preventing contributions
5 from being income as if they were paid in the form of
6 wages or salary.
7 A second effect could occur if IDACORP
8 contributed its own stock to assist Idaho Power Company
9 with its deferred compensation plan. If all corpus was
10 not distributed, the remainder could revert to IDACORP
11 even though the expenses representing the the
12 contributions were originally recorded by Idaho Power
13 Company.
14 Q. What is the position of Staff on this type of
15 deferred compensation and related expenses?
16 A.Staff believes that charges for contributions
17 to Rabbi Trusts and related expenses should not be
18 included in rates; these expenses should be borne by
19 stockholders. Staff also believes that the Commission
20 should direct Idaho Power Company to record charges for
21 trust contributions, administrator's fees, accounting
22 fees and other expenses related to this type of
23 non-qualified deferred compensation, in a specific
24 account for below-the-line expenses..25 Q.Why does Staff believe below-the-line treatment
CASE NO. IPC-E-08-10
10/24/08
1244 NOBBS, J. (Di) 4
STAFF
1 is appropriate?.2 A.First,a Rabbi Trust is a form of non-qualified
3 deferred compensation similar to a golden parachute.The
4
5 /
6
7 /
8
9 /
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1245 NOBBS,J.(Di)4a10/24/08 STAFF
.
.
.
1 benefi ts of the trust accrue to the top officers of the
2 Company but do not benefit customers. This plan is not
3 available to all employees. It is a benefit available
4 only to a limited group of highly compensated employees.
5 Second, specific terms in the trust document
6 create a "Safe Harbor"; this gives creditors a prior
7 claim upon trust corpus. Since creditors can exercise
8 this prior claim upon corpus, contribution alone does not
9 immediately transfer ownership or monetary values to
10 beneficiaries in exchange for employee services. In
11 contrast, payment of salaries or wages would transfer
12 ownership of cash from the Company to the employee.
13 Third, employees do not recognize income when
14 contributions are made.
15 Fourth, employees recognize income only if
16 trust assets are available after satisfying prior claims,
17 and if they are distributed.
18 Fifth, it should be recognized that if IDACORP
19 contributed its own stock to the trust, trust corpus may
20 be available to creditors of both IDACORP and Idaho Power
21 Company. Also, in the future previous contributions
22 which remain undistributed could revert to IDACORP, even
23 though Idaho Power Company recorded the expense.
24 Staff recommends these charges totaling
25 $459,524, shown in Exhibit No. 108, be removed from 2007
CASE NO. IPC-E-08-10
10/24/08
NOBBS, J. (Di) 5
STAFF
1246
.
.
.
1 base year expenses and revenue requirement.
Q.What did you find during your audit of Account
921 ?
A.Account 921 -Office Supplies and Expenses,is
used to record office supplies,travel,and similar
2
3
4
5
6 expenses. This account contains numerous entries from
7 Accounts Payable One Card (P-card) transactions as most
8 expense accounts do. Staff witness Vaughn will discuss
9 these in her testimony.
10 Q.What did you find in your examination of
11 Account 923?
12 A.Account 923 - Outside Services Expense,
13 contained many entries for P-card charges, which Staff
14 witness Vaughn will address in her testimony.
15 This account also contained charges for legal
16 services with descriptions suggesting these services may
17 be for stockholder services or for the parent company of
18 Idaho Power Company (IDACORP) or for the non-qualified
19 deferred compensation plan. Staff witness Leckie will
20 discuss these' in his testimony.
21 I also found three entries totaling $36,375 for
22 Archi tects' Services, which should have been capitalized
23 rather than expensed. None of these were included in
24 adjustments shown in Smith Exhibit No. 30, page 9, for
25 Account 923. Staff recommends this $36,375 be removed
from
CASE NO. IPC-E-08-10
10/24/08 1247 NOBBS, J. (Di) 6
STAFF
.
.
.
1 2007 base year expenses and revenue requirement, subject
2 to a small adj ustment for depreciation. See Exhibit No.
3 109.
4 Q.What did you find during your examination of
5 FERC Account 924?
6 A.Account 924 - Property Insurance Expenses,
7 contains many entries whose descriptions are incomplete
8 or cryptic. However, Staff was able to satisfy itself by
9 testing and other audit methods. Staff believes that the
10 amount claimed is a reasonable representation of broker's
11 fees, insurance premiums and other insurance related
12 expenses for the base year 2007.
13 Q.What did you find in your audit of Account 928?
14 A.Account 928 - Regulatory Commission Expenses
15 contains fees for regulatory licenses and assessments,
16 legal fees for cases before regulatory commissions and
17 similar expenses. These expenses are classified and
18 recorded in subaccounts such as 928.101, 928.102, etc.
19 During my audit of subaccount 928.101 - FERC
20 Order No. 472, I found two accruals recorded in 2007
21 containing out-of-period charges totaling $163,901. Each
22 accrual covered a one-year period.
23 The first accrual consisted of twelve entries
24 totaling $392,956. These twelve entries covered the
25 period October 1, 2006 through September 30, 2007. Out
CASE NO. IPC-E-08-10
10/24/08
1248 NOBBS, J. ( Di ) 7
STAFF
.
1 of period accruals included the three months of October,.2 November and
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1249 NOBBS,J.(Di)7a10/24/08 STAFF
.
.
.
1 December of 2006. If equal charges for each month were
2 accrued, charges for these three months would be $98,239.
3 The second accrual, totaling $87,549, consisted
4 of four entries. This total covered the period October
5 1, 2007 through September 30, 2008. Charges for the nine
6 out-of-period months of January 2008 through September
7 2008 using equal accruals would be $65,662.
8 This subaccount was examined for entries to
9 remove these out-of-period charges. None were found and
10 no entry was found with a dollar amount large enough to
11 remove such charges. Smith Exhibit No. 29, pages 6 and 8
12 and Schwendiman Exhibit No. 41, page 6, both refer to
13 Account 928, or subaccount 928 .101. Neither exhibit
14 shows an equivalent adj ustment. The sum of these two
15 adjustments for out-of-period charges reduces total
16 expenses and revenue requirement for the 2007 base year
17 by $163,901 as seen in Exhibit No. 110.
18 What did you find during your examination ofQ.
19 Account 930. 200?
20 A.Account 930.200 - Miscellaneous Expenses
21 contains expenses not properly classified in other
22 accounts.
23 During my examination I found numerous charges,
24 which were paid via Company P-card. Staff witness Vaughn
25 will provide testimony on P-card charges.
I also found entries for Directors' Fees and
CASE NO. IPC-E-08-10
10/24/08
NOBBS, J. (Di) 8
STAFF
1250
.
.
.
1 related expenses or entries which appear to be
2 shareholder expenses. Staff witness Leckie will cover
3 these in his testimony.
4 In addition, there were entries described in
5 Smith testimony, Exhibit No. 30, pages 2 and 3. These
6 exhibi t pages identified certain charges by specific
7 account number and removed them from expenses for the
8 2007 base year, complying with previous Commission
9 Orders.
10 Lastly, I found entries described as being for
11 a travel alarm clock and for candy. These expenditures
12 appear to be personal, a contribution or frivolous.
13
14
Also, four entries described as donations to Caldwell
Economic Development, Eastern Oregon Visitors, the Idaho
15 Economic Development Association and the Pocatello Men's
16 Basketball League were found. These donations were not
17 listed among the contributions removed by Idaho Power
18 Company, as shown on pages 2 and 3 of Smith Exhibit No.
19 30. Staff was unable to identify adj ustments to Account
20 928.200 that removed these amounts from the year-end
21 balance and none could be identified as P-card entries.
22 Staff recommends the amounts for the contributions, alarm
23 clock and candy reduce 2007 base year expenses by a total
24 of $7,150 as seen in Exhibit No. 111.
25 Exhibit No. 112 summarizes the total
CASE NO. IPC-E-08-10
10/24/08
1251 NOBBS, J. (Di) 9
STAFF
1 recommended adj ustments for my testimony.All.2 adj ustments reduce 2007
3
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6 /
7
8 /
9
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12.13
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24.25
CASE NO.IPC-E-08-10 1252 NOBBS,J.(Di)9a10/24/08 STAFF
.
.
20
21
22
23
24.25
1 base year expenses and revenue requirement by a total of
2 $666,950.
3 Q.Does this conclude your direct testimony in
4 this proceeding?
5 A.Yes, it does.
6
7
8
9
10
11
12
13
14
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17
18
19
CASE NO. IPC-E-08-10
10/24/08
NOBBS, J. (Di) 10
STAFF
1253
.1
2 open hearing.)
(The following proceedings were had in
MR. PRICE: And I will present this
4 wi tness for cross-examination.
3
5 COMMISSIONER SMITH: Mr. Richardson, do
6 you have questions?
.
7
8 Madam Chair.
9
10
11
12
13
14
15
16
17
18 BY MR. WARD:
19 Q
MR. RICHARDSON: I have no questions,
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: None for me. Thanks.
COMMISSIONER SMITH:Mr. Olsen.
MR. OLSEN: None, Madam Chair.
COMMISSIONER SMITH: Mr. Ward.
MR. WARD: I have to.
CROSS-EXAMINATION
How did the Rabbi Trust get that name?
20 A Its history begins with a Jewish
21 congregation.' The congregation wished to provide for its
22 Rabbi a post-retirement plan which was not taxable to him
23 during the years of his employment. The trust was
24 designed by a good lawyer within the congregation who.25 understood the practicalities of the constructive receipt
CSB REPORTING
[phone]
1254 NOBBS (X)Staff
.
.
.
1 principle wi thin the Internal Revenue Code. It was
2 tested by the IRS and the congregation prevailed and
3 subsequently became codified wi thin the code.
4 MR. WARD: Thank you. That's all I have,
5 in the interest of continuing legal education.
6 COMMISSIONER SMITH: Can we get credit?
7 MR. WARD: I hope so.
8 COMMISSIONER SMITH: Mr. Bruder.
9 MR. BRUDER: I have no questions,
10 Madam Chairman.
11 COMMISSIONER SMITH: That leaves you,
12 Ms. Nordstrom.
13 MS. NORDSTROM: No questions.
14 COMMISSIONER SMITH:Does the Commission
have any questions?
COMMISSIONER KEMPTON:No questions.
COMMISSIONER REDFORD:No questions.
COMMISSIONER SMITH:Nor 1.No redirect?
15
16
17
18
19 MR. PRICE: No redirect on that.
20 COMMISSIONER SMITH: Boy, you got off easy
21 there, Mr. Nobbs.
22 (The witness left the stand.)
23 COMMISSIONER SMITH: If you were here last
24 night, you would have heard me say it's not appropriate
25 to have outbursts from the audience.
CSB REPORTING
[phone]
1255 NOBBS (X)Staff
.
.
.
1
2 to the stand.
MR. PRICE: The Staff calls Mr. Joe Leckie
4 JOE LECKIE,
3
5 produced as a witness at the instance of the Staff,
6 having been first duly sworn, was examined and testified
7 as follows:
8
9
10
11 BY MR. PRICE:
12 Q
DIRECT EXAMINATION
Please state your name.
Joe Leckie.
And who is your employer?
The Public Utili ties Commission.
And what is your job title?
I'm an auditor.
And on October 24th of this year did you
19 have occasion to prepare written direct testimony,
13 A
20 including Exhibit Nos. 113 through 118 for this case?
21
22
14 Q
Yes.
Do you have any corrections or additions
23 to that testimony or exhibits at this time?
24
25
15 A16 Q17 A18 Q
A
Q
A
Q
Yes, I do.
Would you please explain?
CSB REPORTING
[phone]
1256 LECKIE (Di)Staff
.
.
.
1 A Yes. There is one sequence of a question
2 and answer that I would like to withdraw. That question
3 begins on page 13, line 20. The answer begins on line 22
4 and goes through line 24 of page 14.
5 Q Did you also prepare a revised direct
6 testimony page?
7 A Yes, that page is page 14 and the changes
8 that were on that page related to the testimony that I
9 would ask to withdraw.
10 Q Thank you very much, and if I were to ask
11 you the same questions today that were asked in your
12 prepared written direct testimony, would your answers be
13 the same?
14 A Yes.
15 MR. PRICE: I would now move that
16 Mr. Leckie's testimony, including Exhibit Nos. 113
17 through 118, and the revised direct testimony be spread
18 upon the record as if read.
19 . COMMISSIONER SMITH: I just want to
20 clarify that you want us to strike from your testimony
21 from line 20 on page 13 through line 24 on page 14?
22 THE WITNESS: That's correct.
23 COMMISSIONER SMITH: All right. Without
24 obj ection, we will then spread the prefiled testimony of
25 Mr. Leckie as revised upon the record and identify
CSB REPORTING
[phone]
1257 LECKIE (Di)Staff
1 Exhibits 113 through 118..2 (The following prefiled direct testimony
3 of Mr.Joe Leckie is spread upon the record.)
4
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8
9
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11
12.13
14
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24.25
CSB REPORTING 1258 LECKIE (Di)
(208 )890-5198 Staff
.
.
.
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Joe Leckie. My business address is
4 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission (Commission) as an auditor in the Utilities
8 Division.
9 Q.What is your educational and experience
10 background?
11 A.I graduated from Brigham Young Uni versi ty with
12 a Bachelors of Science degree in Accounting. I worked
13 for the accounting firm Touche Ross in its Los Angeles
14 office for approximately one year. I then attended law
15 school and graduated from the J. Rueben Clark School of
16 Law at Brigham Young University with a Juris Doctorate
17 degree. I am licensed to practice law in the State of
18 Montana. I practiced law in the State of Montana for
19 approximately 25 years. I have been employed at the
20 Commission as an auditor since March 2001. I have
21 attended the annual regulatory studies program sponsored
22 by the National Association of Regulatory Utili ties
23 Commissioners (NARUC) at Michigan State University in
24 August of 2001. I have attended several other training
25 courses sponsored by NARUC on regulatory accounting and
audi ting.
CASE NO. IPC-E-08-10
10/24/08 1259 LECKIE, J. (Di) 1
STAFF
.
.
1 Q.What is the purpose of your testimony?
2 A.The purpose of my testimony is to present and
3 discuss adj ustments to Idaho Power Company's financial
4 information that have an effect on the revenue
5 requirement recommendation in this case. I will present
6 adj ustments in miscellaneous service revenues, payroll
7 expense, employee incentive compensation, 2009 salary
8 structure adjustment, rate base, depreciation expense,
9 attorney fees, and director fees. I will also discuss
10 the escalation of rate base additions valued at less than
11 two (2) million dollars and the Company's cost
12 curtailment programs.
13 Q. What adjustment are you proposing for Account
14 451- Miscellaneous Service Revenues?
15 A.In the Company's case this account was reduced
16 by 13.99%, which resulted in a reduction of $566,667.
17 Miscellaneous revenue is recorded in Account 451. The
18 Company in its Methodology Manual (Company Exhibit No.
19 34, page 2) describes the revenues that are recorded in
20 this account:
21
22
23
24.25
Description - Account 451 includes revenues for
all miscellaneous services and charges billed
to customers who are not specifically provided
for in other accounts. This includes fees for
changing, connecting or disconnecting services,
and profit on maintenance or installations on
customers' premises. Miscellaneous service
revenues include continuous service reversion
charges, field visit charges; return trip
charges, returned check fees, service
CASE NO. IPC-E-08-10
10/24/08 1260 LECKIE, J. (Di) 2
STAFF
.
.
18
19
20
21
22
23
24.25
1 connection charges, service establishment
charges, and application and processing fees
2
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/
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/
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/
8
9
10
11
12
13
14
15
16
17
CASE NO. IPC-E-08-10
10/24/08 1261 LECKIE, J. (Di) 2a
STAFF
1.2
collected for new permits, new leases or
requests for easement relinquishments.
3 The Company used a three-year Compound Annual
4 Growth Rate (CAGR) applied to 2007 actual revenues
5 resul ting in the reduction of 13.99%, and attributes the
6 reduction to slower customer growth anticipated in 2008.
7 The Company recorded $4,050,513 in revenues in 2007 (See
8 Exhibit No. 113). The Company reduced this amount by the
9 13.99% or $566,667, and used the difference of $3,483,846
10 as the amount of miscellaneous service revenue in 2008.
11 I do not agree with this reduction of revenues
12 and I am recommending that the reduction in service.13 revenue not be allowed. Therefore, revenues received by
14 the Company in 2008 should be increased by $566,667 and
15 the revenue deficiency of the Company should be reduced.
16 The reasons for my recommendation are based on
17 the actual history of this account. The Company has
18 received more than $3,483,846 in service income for the
19 last four (4) years. The average amount received by the
20 Company over the last eight (8) years is $4,067,043.
21 The. reason given by the Company for its
22 proposed reduction is attributed to slower customer
23 growth. This reduction is not supported by any evidence
24 that slower customer growth will reduce this type of.25 revenue. The actual revenues for January to June 2008
CASE NO. IPC-E-08-10
10/24/08 1262 LECKIE, J. (Di) 3
STAFF
1 are shown in Exhibit No.114.This Exhibì t shows that as.2 of June 2008,
3
4 /
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8 /
9
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11
12.13
14
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22
23
24.25
CASE NO.IPC-E-08-10 1263 LECKIE,J.(Di)3a10/24/08 STAFF
.
.
1 the total revenues for the first half of the year booked
2 to Account 451 are 49.9% of the total revenue booked to
3 Account 451 in 2007.
4 Staff believes that even under conditions of
5 slower growth that the annual service revenue should at
6 least be at 2007 levels. Therefore, Account 451,
7 Miscellaneous Service Revenue should not be reduced.
8 Q.What adjustment are you proposing to payroll
9 expenses?
10 A.I do not agree with the magnitude of the
11 Company's annualized payroll adjustment increasing
12 payroll expense by $2,593,733. The Company used a
13 forecasted December 2008 payroll of $10,995,625 (this is
14 based on two '(2) pay periods) and then annualized this
15 amount (multiplied by 13 to account for 26 pay periods
16 annually) to calculate the annual payroll amount of
17 $142,943,119.
18 I used the actual payrolls for August and
19 September 2008 with 2 pay periods in each month. I
20 determined the average payroll per pay period during
21 these two (2) months is equal to $5,419,365 or
22 $140,903,490 ?nnually. This is $2,039,629 less than the
23 Company's forecast. See Exhibit No. 115.
.24
25
Because the payroll expense is less than the
Company's forecast, the payroll tax burden is also
reduced by $172,587.
CASE NO. IPC-E-08-10
10/24/08 1264 LECKIE, J. (Di) 4
STAFF
1 The Company divides and allocates the payroll.2 costs to Operating Expenses (64.93%) and capitalized
3 Construction Work in Progress (CWIP). I recommend an
4 adj ustment to the Operating Expenses. Therefore the
5 total reduction between the Company's position and what I
6 am recommending is the sum of $2,039,629 and $172,587
7 times the expense allocation percentage of 64.93%, or
8 $1,436,301. See Exhibit No. 116.
9 I believe using the annualized average of the actual
10 payrolls for August and September 2008 is a better
11 representation of the actual payroll costs the Company
12 will incur than the Company's forecast of December 2008.13 payroll annualized. August and September payrolls are
14 the highest payrolls to date in 2008. The basic
15 difference between the Company's calculation and my
16 calculation is the starting point of the annualization.
17 I have used the actual, known amounts of the payroll
18 expense for August 2008 and September 2008, and the
19 Company used a forecasted December 2008 starting point.
20 The opportunity to overstate the amount of the annualized
21 payroll amount is greater with forecasted numbers than
22 wi th actual numbers.
23 Q.Did. you make any adjustments to the incentive
24 expense?.25 A. Yes. The Company included in its request forincenti ve compensation, an incentive rate of 4%. The
CASE NO. IPC-E-08-10
10/24/08 1265 LECKIE, J. (Di) 5
STAFF
.
.
.
1 Company testified that calculating the incentive at this
2 rate would remove incentive amounts above the normalized
3 incenti ve target rate. I calculated the incentive rate
4 at 2% and determined that at 2%, the normalized incentive
5 expense would be reduced by $2,999,492. The payroll tax
6 burden on this amount is $253,808, resulting in a total
7 of $3,253,300. The Company does not pay incentive on its
8 entire payroll, but on only 98.64%, therefore the total
9 of $3,253,300 must be multiplied by this percentage to
10 determine the total decrease in incentive expense. The
11 total decrease to the incentive expense is $3,208,964.
12 See Exhibit No. 116.
13 The Company accrued $9,423,443 of incentive
14 expenses in 2007 and then used an annualizing growth
15 factor of 9.41% to calculate the proj ected accrual for
16 incentive expense for 2008 of $10,309,981. The Company
17 in Exhibit No. 31, page 2 determined its 2008 incentive
18 expense is expected to be $6,418,111. Since the accrual
19 of $10,309,981 exceeds the expected expense of
20 $6,418,111, the Company reduced the operating expense
21 increase for the 2008 annualized payroll and the 2009
22 salary structure adjustment by the difference of
23 $3,838,832. When my recommended adjustment of a decrease
24 in the incentive expense of $3,208,964 is added to the
25 Company's reduction
CASE NO. IPC-E-08-10
10/24/08 1266 LECKIE, J. (Di) 6
STAFF
.
.
.
16
17
18
19
20
21
22
23
24
25
1
2
of $3,838,832, the total reduction in operating expense
should be $7,047,796, leaving $3.2 million
3
4
5
6
7
8
9
10
11
12
13
14
15
CASE NO. IPC-E-08-10
10/24/08 1267 LECKIE, J. (Di) 6
STAFF
.
.
.
1 in the test year for incentive pay.
2 I believe the incentive rate should be 2%
3 instead of the 4% proposed by the Company for the
4 following reasons: First, the Company and Staff were both
5 parties to a Stipulation filed in a previous case by the
6 Company that addressed the inclusion/exclusion of
7 incenti ve pay for employees. Pursuant to the Stipulation
8 filed in Case No. IPC-E-05-28, the parties to that
9 Stipulation agreed as follows:
10 The Parties agree conceptually that it is
reasonable to include an employee pay-at-risk
or employee incentive component in test-year
rev~nue requirements so long as such incentive
component is based on goals that benefit
customers and the amounts payable for achieving
the goals are limited to reasonable "target" or
medium goals. Senior management pay-at-risk is
appropriately excluded from the test year
revenue requirement.
11
12
13
14
15
16 According to the information provided by the Company to
17 Audi t Request No. 77, the employees ' incentive
18 compensation is based on four (4) goals: Customer
19 Satisfaction, O&M Expenses, Network Reliability, and
20 Idaho Power Net Income. The qualifying payout for
21 achieving the target or medium goal in each of the goals
22 is as follows:
23
24
25
Customer Satisfaction 1.5%
O&M Expense 1.5%
Network Reliability
Idaho Power Net Income
1.0%
2.0%
CASE NO. IPC-E-08-10
10/24/08 1268 LECKIE, J. (Di) 7
STAFF
.
.
.
1 Since only those goals that benefit customers are
2 considered in determining incentive compensation, I have
3 excluded the payout percentages for O&M Expenses and
4 Idaho Power Net Income. In my calculation only the
5 payout percentages for Customer Satisfaction and Network
6 Reliabili ty are included. It is clear that the payout
7 percentage for Idaho Power Net Income should not be
8 included. I have excluded the qualifying payout for
9 maintaining or reducing O&M Expenses because it should be
10 a self-funding goal. When employees achieve that
11 particular goal of reducing O&M expenses, the savings to
12 the Company would be sufficient to fund the incentive
13 payout. This is true at least in the short run and
14 should be reflected especially during a period of
15 economic turmoil when everyone is expected to be
16 conservative.
17 If the target payout percentage is achieved in
18 both Customer Satisfaction and Network Reliability the
19 maximum percentage of incentive expense to include in
20 revenue requirement would be 2.5%. However, there is one
21 addi tional hurdle to the payment of this incentive
22 compensation. That hurdle requires earnings must be
23 sufficient for shareholders to receive a dividend payment
24 of $1.20 per year before the employees are entitled to
25 any incentive. pay. This additional hurdle creates an
CASE NO. IPC-E-08-10
10/24/08 1269 LECKIE, J. (Di) 8
STAFF
.
.
1 percentages; and the payment of the incentive is not
2 based solely on goals that benefit customers. I
3 therefore have reduced the incentive percentage by 1/2%
4 to the 2% that I recommend be included in incentive
5 compensation. Staff is concerned that the overriding
6 dividend restriction changes the customer benefits
7 recei ved from the incentive programs previously accepted
8 for inclusion in rates. If employee incentives are
9 eliminated under this restriction, the total program
10 solely benefits shareholders. Employee actions will then
11 focus on earnings as the Net Income incentive program
12 will be the only one that impacts the employee pay
13 structure. If that becomes the case, Staff will
14 recommend no incentives be included in rates since the
15 customer benefit has been removed.
16 Q.Do you propose any adj ustment to the Company's
17 request for a Salary Structure Adjustment (SSA) for 2009?
18 A.Yes, I have not included any increase for the
19 2009 SSA. The Company requested an additional $3,019,804
20 for the 2009 operating payroll. This increase represents
21 a 3% increase to 2008 gross payroll. The Company's
22 proposal violates long-standing ratemaking treatment that
23 post test year adj ustments be known and measurable. The
24 amount of the adjustment, if any, is neither known nor.25 measurable. In the past, the Company has foregone
CASE NO. IPC-E-08-10
10/24/08 1271 LECKIE, J. (Di) 9
STAFF
1 employee raises for reasons of economic prudency.This.2 is an area Staff expects the
3
4 /
5
6 /
7
8 /
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10
11
12.13
14
15
16
17
18
19
20
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23
24.25
CASE NO.IPC-E-08-10 1272 LECKIE,J.(Di)9a
10/24/08 STAFF
1 Company will closely monitor and limit under current.2 economic conditions, particularly those that have
3 developed since the Company filed this case. In Order
4 No. 29505, issued by the Commission in the Company's 2003
5 rate case, the Commission specifically addressed the
6 inclusion of an SSA:
7 The Company acknowledged that current
financial conditions do, and we believe8 they ought to; dictate a tightening of the
Company's belt so to speak with regard to
9 salaries. Because of this and the fact
that the SSA adjustment is neither known10 nor measurable at this time, the Commission
accordingly will remove $2,241,595 from test11 year expenses for the SSA.
12 Staff is also concerned with customers'.13 reaction when a company, particularly in a difficult
14 economy, is asking for additional revenues to give raises
15 at a time when it is also asking for an increase in
16 rates. I discuss later in my testimony my perception of
17 the Company's. minimal efforts to reduce its operating
18 costs. Therefore, I do not believe that it is
19 appropriate to fund in this case a 3% blanket increase in
20 employees' salaries for 2009.
21 Q.Is there any adjustment to rate base for that
22 portion of the payroll increase that is capitalized?
23 A.No. The Company divides and allocates the
24 payroll costs between the expense portion of the costs.25 (64.93%) and capitalized CWIP (35.07%). Those payroll
CASE NO. IPC-E-08-10
10/24/08 1273 LECKIE, J. (Di) 10
STAFF
1 costs that are capitalized in CWI P are recorded in the.2 individual work
3
4 /
5
6 /
7
8 /
9
10
11
12.13
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17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1274 LECKIE,J.(Di)lOa
10/24/08 STAFF
.
.
larders on an actual basis. Then when the CWIP is placed
2 in service, its total actual cost is capitalized.
3 Q.Did you review the Company's rate base amount
4 in its Application?
5 A.Yes, I reviewed the rate base accounts except
6 for the Materials and Supplies Account reviewed by Staff
7 wi tness Vaughn.
8 Q.What is the amount of rate base in the
9 Company's Application?
10 A.The Company is requesting a rate base of
11 $2,265, 781,563. This is the 2008 adj usted rate base
12 amount that includes all of the adj ustments proposed by
13 the Company.
14 Q. Have you recommended any adj ustments to this
15 amount?
16 A.Staff witness Vaughn has recommended an
17 adjustment for the Materials and Supplies Account. Other
18 than that adj ustment and the impact on Accumulated
19 Depreciation caused by the change in depreciation rates,
20 I do not recommend any adjustment to the Company's
21 proposed rate base amount. I discuss the methodology in
22 determining the 2008 amount for CWIP projects with a cost
23 less than $2 million later in my testimony but that
24 discussion does not result in a recommended adj ustment..25 Q. What adjustment did you propose fordepreciation
CASE NO. IPC-E-08-10
10/24/08 1275 LECKIE, J. (Di) 11
STAFF
.
.
.
1 expense?
2 A.The Company filed a case before the Commission
3 specifically addressing the issue of the annual
4 depreciation rates for the Company's assets, Case No.
5 IPC-E-08-6. That case was concluded when this Commission
6 issued Order No. 30639 on September 12, 2008. The
7 Commission adopted a Stipulation between the Company and
8 Staff setting forth the depreciation rates with an
9 effective date of August 1, 2008. Prior to the Commission
10 issuing Order No. 30630, the Company filed this rate case
11 reflecting the depreciation rates it had filed in the
12 depreciation case.
13 The rates adopted in Order No. 30630 are
14 different for some assets than those rates used by the
15 Company in its filing of this rate case. Therefore, an
16 adj ustment is made to update the depreciation expense to
17 include the rates adopted by Order No. 30639. The
18 depreciation expense should be reduced from a $471,026
19 increase (see Company's Exhibit No. 31, page 3 of 6) to a
20 $1,000,162 decrease (see Exhibit No. 117; Company's
21 answer to Aud~t Request No. 113). Thus, depreciation
22 expense should be reduced by $1,471,189.
23 Q.Does this adjustment affect any other accounts?
24 A.Yes, it will affect the Accumulated
25 Depreciation account or depreciation reserves. The
CASE NO. IPC-E-08-10
10/24/08
1276 LECKIE, J. (Di) 12
STAFF
1 Company included an increase in the reserve of $227,440.2 when it filed its rate case.With the reduction in
3 depreciation expense,the
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13.14
15
16
17
18
19
20
21
22
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24.25
CASE NO.IPC-E-08-10 1277 LECKIE,J.(Di)12a10/24/08 STAFF
.
.
.
1 corresponding reserve would decrease by a negative
2 $508,191. The net effect on the reserve account is a
3 decrease in the reserve account of $735,595. This
4 account reduces the Company's rate base; therefore, a
5 reduction in the reserve account will increase rate base
6 by $735,595.
7 Q.Did you review the Company's expenses for
8 attorney fees?
9 A.Yes.
10 Q.Did you make any adj ustments in these expenses?
11 A.Yes, I found that the Company expended $192,364
12 to the Dewey & Le Boeuf law firm (previously the Le Boeuf
13 Lamb and Green law firm) for services related to the
14 stock plans for Idaho Power Company and IDACORP. See
15 Exhibi t No. 118. These legal charges related only to the
16 stock plans of the companies and were separated from
17 other legal services that were provided by the same firm.
18 These charges are solely related to the shareholder
19 interests and not for customers' benefits. Therefore,
20 these expenses should be included below the line and not
21 part of the revenue requirement.
22 e.Did you have any adj ustment in the fees the
23 Company paid to the Company's directors?
24
25
A.Yes, the Company provides a plan '¡Jhere the
directors are allowed to defer any or all of their
CASE NO. IPC-E-08-10
10/24/08 1278 LECKIE, J. (Di) 13
STAFF
1 director' s fees earned.These fees are then deferred.2 until the director opts under the provisions of the plan
3 to have
4
5 ..
6
7 ..
8
9 ..
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1279 LECKIE,J.(Di)13a10/24/08 STAFF
1 the deferred fees paid to theæ. While the fees are.2 deferred under the provision of the plan, the fees earn
3 interest at a rate that is 3% over Moody's long teræ
4 eorporate bond yield average rate.
5 In 2007, the directors of Idaho Power earned
6 $337,676 in interest on deferred fees. Also in 2007, the
7 directors of IDACORP earned $ 18 6,721 in interest on
8 deferred fees. For the direetor fees for IDACORP, over
9 90% are allocated back to Idaho Pmver. Therefore, the
10 Coæpany has ineluded at least $505,724 of interest
11 eifpense that it paid to its directors for the deferred
12 directors' fees. The interest rate paid in 2007 for the.13 deferred aæounts ranged between 8.83% and 9.34%.
14 Custoæers should not be responsible for paying
15 a preæiuæ of 3% over Moody's long teræ eorporate bond
16 yield average rate to the directors. The directors
17 should not receive an interest rate greater than the
18 average rate the Coæpany '¡JQuld pay to any independent
19 third party for a siæilar aæount. Any interest above the
20 æarket rate for funds should be a belm; the line enpense
21 and not included in the revenue requireæent. Staff
22 therefore recoffends that the Coæpany' s enpenses for the
23 Board of Directors be reduced by 3% of the interest
24 earned on the deferred fees. This would equal $15,172.25 ($505,724 n 3%).
Q. Do you have any other concerns about the
CASE NO. IPC-E-08-10
10/24/08
1280 LECKIE, J. (Di) 14
STAFF
.
.
1 Directors' fees?
2 A.In 2008, the Company increased the annual
3 retainer for board members from $30,000 to $35,000 and
4 for the chairman of the board from $94,000 to $105,000.
5 The Company has not included this increase in a specific
6 known and measurable adj ustment for this rate case.
7 However, I would expect that this increase will be
8 reflected in subsequent cases. This is an area of
9 expenses that I also discuss in the cost containment
10 portion of my testimony.
11 Q.Did you recommend any adj ustment to the
12 Company's rate base annualization?
13 A. No, other than the impact on Accumulated
14 Depreciation, I do not recommend any adjustments to the
15 portion of rate base that I reviewed. I reviewed the
16 plant in service additions to rate base. Staff witness
17 Vaughn reviewed the Materials and Supplies portion of
18 rate base and has a recommended adjustment for that
19 account.
20 The Company includes in its current rate base
21 amount the cost of projects it expects to put into
22 service by the end of 2008. Those proj ects are divided
23 into two groups: those costing more than $2 million and
24 those costing less than $2 million. The Company has.25 included the projects costing more than $2 million by
CASE NO. IPC-E-08-10
10/24/08
1281 LECKIE, J. (Di) 15
STAFF
1 including the cost of the proj ect as a known and.2 measurable adj ustment.For those proj ects with capital
3 expendi tures less than $2
4
5 /
6
7 /
8
9 /
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1282 LECKIE,J.(Di)15a10/24/08 STAFF
.
.
.
1 million, the Company used a 6% increase to 2007 actual
2 CWIP closings to reflect its 2008 additions.
3 Al though I have not recommended any adj ustments
4 to the Company-proposed escalation in capital expenditure
5 of less than $2 million, I am not satisfied that this
6 methodology is reasonable going forward. I am
7 specifically concerned with regard to the CAGR
8 application to the previous year's numbers as the 2008
9 additions to rate base. This methodology will eventually
10 result in unreasonable compounding of additions to rate
11 base. While Staff recognizes the need for investment to
12 serve new customers, and does not oppose the escalation
13 in this case, the Company should not consider this
14 position as an agreement to the methodology. I believe
15 the Company and Staff should continue to evaluate more
16 appropriate known and measurable methods of establishing
17 rate base levels for this smaller category of
18 investments.
19 Q.Do you have any concerns about the Company's
20 cost containment efforts?
21 A.Yes. The Company-proposed cost containments in
22 the amount of $3,834,000 (Company's Exhibit No. 31, page
23 6 of 6). These containments are related to the delayed
24 filling of open employee positions, delayed training and
25 curtailed travel. This amount represents an approximate
CASE NO. IPC-E-08-10
10/24/08 1283 LECKIE, J. (Di) 16
STAFF
1 reduction of only 0.68%in the Company's 2008 operation.2 and
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1284 LECKIE,J.(Di)16a
10/24/08 STAFF
.
.
.
1 maintenance expenses. In the Company's case many 2007
2 O&M expense accounts, including A&G, are escalated by the
3 5-year growth rate. This occurs prior to the proposed
4 cost containment proposal being reflected. In other
5 words, the Company proposes a 9. 41 % increase in O&M
6 expenses and then scales back its proj ected increase by
7 0.68% as a cost-saving measure. In the current economic
8 environment, I believe the Company could be more active
9 in finding ways to reduce its growing expenses. As an
10 example, I indicated earlier in my testimony that I
11 thought the Company could do more to reduce payroll
12 expense and director fees.
13 My review of the Board of Director Meeting
14 Minutes revealed that the minutes for the Idaho Power
15 Company and IDACORP meetings were almost identical.
16 Rather than duplicating efforts, the Company should
17 explore ways to be more efficient in delivering the
18 necessary information to the directors, and ultimately
19 reduce overall costs.
20 Q.Are these the only areas you are recommending
21 as possibilities for cost containment?
22 A.No. Staff witness Vaughn discusses the need
23 for greater controls with P-cards and Staff witness Nobbs
24 also discusses potential ways to control costs in the 900
25 accounts. As stated above, I expect the Company will
CASE NO. IPC-E-08-10
10/24/08
1285 LECKIE, J. (Di) 1 7
STAFF
1 continue to evaluate opportunities for cost containment..2 Q.Does this conclude your direct testimony in
3 this proceeding?
4 A.Yes,it does.
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1286 LECKIE,J.(Di)18
10/24/08 STAFF
.1
2 open hearing.)
(The following proceedings were had in
MR. PRICE: I now present this witness for
4 cross-examination.
3
5 COMMISSIONER SMITH: Mr. Ward, do you have
6 any more good questions?
.
7
8
9
10
11
12
13
14 Madam Chair.
MR. WARD: No, I don't, Madam Chair.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: None.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions,
COMMISSIONER SMITH: That leaves you,
MR. KLINE: Thank you very much. I'm not
18 as nice as Ms. Nordstrom, so I probably won't get an
.
15
16 Mr. Kline.
17
19 applause.
20
21
22
23
24 BY MR. KLINE:
25 Q
COMMISSIONER SMITH: We knew that.
CROSS-EXAMINATION
Mr. Leckie, portions of your testimony are
CSB REPORTING
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1287 LECKIE (X)Staff
.
.
.
1 a little bit critical of the Company's cost containment
2 efforts and I want to focus on one specific example that
3 you cite. Look at page 17 of your testimony, lines 12
4 through 17 and -- are you there?
5 A Yes.
6 Q And in that part of your testimony, you're
7 cri tical of the fact that there is one set of minutes
8 kept by the Company for meetings of the board of
9 directors of IDACORP and a separate set of meetings
10 minutes for the meetings of the board of directors of
11 Idaho Power; is that correct?
12 A Yes.
13 Q And I take it from your testimony that you
14 view that that is a duplication of effort and wasteful?
15 A No. What I wanted to point out there is
16 that as you read those minutes, they were almost
17 identical in many respects. There were a few changes,
18 differences, but yet, it appeared to me that there was
19 the possibility that the Company could look at ways in
20 which it could reduce the time and the expenses necessary
21 for those director meetings as it related to the
22 directors of the two companies.
23 Q Well, are you aware, No.1, that IDACORP
24 and Idaho Powèr conduct one meeting for both boards of
25 directors?
CSB REPORTING
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1288 LECKIE (X)Staff
.1 A Well
Were you aware of that?
No, not from the minutes, I couldn't
Right, and are you aware that both Idaho
6 Power and IDACORP, of course, are separate Idaho
2 Q
Yes.
And are you aware that Idaho law requires
10 that each corporation have its own set of minutes?
.
3 A
Yes.
Okay, does it sound like, then, that
13 keeping a separate set of records for each of the two
16 A
4 determine that.
5 Q
14 corporations is duplicative?I mean, they have to do it
18 Q
7 corporations?
8 A
15 by law. How else can they do it, Mr. Leckie?
9 Q
They would have to have a set of minutes
17 for both corporations.
11 A
Okay.
And you'll notice I didn't propose any
20 kind of adjustment to any kind of expenses here. All I
12 Q
21 was looking at is the possibility of some cost savings in
19 A
22 that area.
23 Q Well, I'm trying to figure how you could.
24 If you have to keep two separate sets of minutes by law.25 and you have one board of directors meeting for the two
CSB REPORTING
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1289 LECKIE (X)Staff
.
.
1 corporations, where are you going to save the money?
2 A Maybe the minutes or the meetings could be
3 reduced to a single day. That would save time in terms
4 of director expenses.
5 Q Okay. On the bottom of page 8 of your
6 testimony, looking at lines 16 through 25, you discuss
7 your recommendation that the Commission reduce the
8 expenses associated with incentives that the Company's
9 employees can earn if the customer satisfaction and
10 service reliability targets are achieved by those
11 employees. Is that what's being discussed in that
12 section of your testimony?
13 A Yes, it is.
14 Q All right. Do you agree that improving
15 customer satisfaction and system reliability are
16 desirable goals?
17 A Yes.
18 Q Let me ask you another way. Do you think
19 reducing incentives to improve customer satisfaction and
20 service reliability will benefit customers?
21
22
A No.
Q Okay. Well, what is your concern with the
23 incentives that benefit customers?
24.25
A - My concern was that the incentives that
benefi t customers are secondary or cannot be paid unless
CSB REPORTING
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1290 LECKIE (X)Staff
.
.
.
1 there is a dividend paid to the shareholders first and
2 that there's a risk that those would not be paid even
3 though the employees receive those or achieve those
4 obj ecti ves.
5 Q Well, let's assume that the Company has
6 insufficient earnings one year to actually pay a
7 dividend. It's a scary thought, but let's assume that
8 and it can't afford to pay the incentives maybe just for
9 one year. That doesn't change the fact that the improved
10 customer satisfaction and service reliability will
11 benefit customers, does it?
12 A No, but the ratepayers should not be
13 responsible to pay for that incentive when in fact it
14 doesn't go down to the employees.
15 Q Well, they're not paying it, they're not
16 paying it because there's not enough money to pay
17 di vidends. Do you understand that?
18 A Well, I'm saying that the ratepayers are
19 being charged that in the revenue requirement that
20 they're required to pay through rates and a portion of
21 that revenue requirement would be incentive pay that's
22 included in the revenue requirement for achieving
23 customer satisfaction and reliability.
24 Q And your reason for reducing those is
25 there is a possibility the Company may not have
CSB REPORTING.
[phone]
LECKIE (X)Staff1291
.
.
20
21
1 sufficient earnings to pay dividends and then it might
2 not pay those incentive payments to employees and as a
3 resul t that that incentive should be eliminated or
4 reduced?
5 A Yeah, I didn't reduce it completely. The
6 total incentive payout for those is two-and-a-half
7 percent and I reduced it by a half a percent.
8 Q And that's just on the possibility that
9 the Company might not have enough money in earnings to
10 pay?
11 A No, that's to recognize the risk
12 associated with that incentive not being paid.
13 MR. KLINE: That's all.
14 COMMISSIONER SMITH: Mr. Bruder, did you
15 have any questions for this witness?
16 MR. BRUDER: I have none. Thank you.
17 COMMISSIONER SMITH: How about
18 Commissioner Kempton.
19 COMMISSIONER KEMPTON: No.
COMMISSIONER REDFORD: No.
COMMISSIONER SMITH: Any redirect, Mr.
22 Price?
23
24.25
MR. PRICE: Yes, thank you, Madam Chair.
CSB REPORTING
[phone]
1292 LECKIE (X)Staff
.1
2
3 BY MR. PRICE:
4 Q
REDIRECT EXAMINATION
Mr. Leckie, a fair amount of the
5 questioning at the end involved the dividend clause.
6 Isn't it true that the dividend clause makes it so
7 incentives that benefit customers are now focused on
8 earnings and not customer measures?
9 A Clearly it adds that focus, the
10 shareholder focus, into that, into those goals and
11 objectives.
.12
13
14
15
16
MR. PRICE: That's all I have.
COMMISSIONER SMITH: Thank you very much.
Thank you, Mr. Leckie.
(The witness left the stand.)
MR. PRICE: The Commission Staff now calls
17 Ms. Cecily Vaughn.
.
18
19
20
21
22
23
24
25
CSB REPORTING
(208) 890-519~
1293 LECKIE (Di)Staff
.1
2
CECILY VAUGHN,
produced as a witness at the instance of the Staff,
3 having been first duly sworn, was examined and testified
.
4 as follows:
5
6
7
8 BY MR. PRICE:
9 Q
DIRECT EXAMINATION
Can you please state your name for the
Cecily Vaughn.
And who is your employer?
Idaho Public Utili ties Commission.
And what is your job title now?
I'm an auditor.
And did you have occasion on October 24th
17 of this year to prefile written testimony, including
10 record?
11 A
18 Exhibits Nos. 119 through 127 for this case?
12 Q
Q
I did.
And do you have any corrections or
21 additions to that testimony?
13 A
Q
I do not.
And if I were to ask you the same
24 questions today that are contained in your prepared.
14 Q
25 testimony, written testimony, would your answers be the
CSB REPORTING
[phone]
15 A
16 Q
19 A
20
22 A
23
1294 VAUGHN (Di)Staff
.1 same?
2 A Yes, they would.
MR. PRICE: I would now move that
4 Ms. Vaughn's testimony be spread upon the record as if
3
5 read, including Exhibits Nos. 119 through 127.
6 COMMISSIONER SMITH: If there is no
7 obj ection, we will spread the testimony upon the record
8 as if read and identify the exhibits.
9 (The following prefiled direct testimony
10 of Ms. Cecily Vaughn is spread upon the record.)
.
20
21
22
23
24.25
11
12
13
14
15
16
17
18
19
CSB REPORTING'
[phone]
1295 VAUGHN (Di)Staff
.
.
1 Q. Please state your name and business address for
2 the record.
3 A.My name is Cecily Vaughn. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utili ties
7 Commission (Commission) as an auditor in the Utilities
8 Division.
9 Q.What is your educational and experience
10 background?
11 I graduated from Washington State Uni versi ty inA.
12 197 4 with a B~chelors of Science degree in Veterinary
13 Science; I received my degree as a Doctor of Veterinary
14 Medicine at the same time. I practiced as a veterinarian
15 in the State of Washington until approximately 1987.
16 From 1993 until 1996 I attended the College of Business
17 and Economics at the Uni versi ty of Arkansas in
18 Fayetteville, Arkansas. From 1996 until 1997 I studied
19 at the College of Business at Boise State Uni versi ty with
20 an emphasis in accounting. I passed the Uniform CPA exam
21 in the fall of 1997; I am currently a licensed CPA in the
.
22 State of Idaho.
23 I was employed as a financial analyst by
24 Hewlett Packard from 1998 until 2000. In this position I
25 provided sale' financial support for the HP test lab
CASE NO. IPC-E-08-10
10/24/08
VAUGHN, C. (Di) 1
STAFF
1296
1 located in Boise,a cost center with an annual budget in.2 excess of
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1297 VAUGHN,C.(Di)1a
10/24/08 STAFF
.1 $50 million. I was solely responsible for coordinating
2 the semi -annual budgeting process, for developing and
3 implementing the allocation system used to distribute
4 costs to multiple profit centers, and for ensuring that
5 costs incurred were appropriate and met budgetary goals.
6 During this time I also served as inventory analyst for
7 the Personal LaserJet Division, a $2 billion per year
8 profit center~ In this role, I was responsible for
9 accurate valuation of worldwide inventory and for removal
10 of intracorporate profit included in inventory value.
11 From 2000 until 2003 I was employed as Grants
12 Accountant (Financial Specialist) for the Center for.13
14
Geophysical Investigation of the Shallow Subsurface at
Boise State Uni versi ty; I was promoted to Senior
15 Financial Specialist in 2002. In this role, I was
16 responsible for all aspects of grant accounting for the
17 Center, including budgeting, submission, and ensuring
18 that grant funds were expended and accounted for in
19 accordance with funding agency regulations. I also
20 assisted in the preparation of the BSU F&A (Facilities
21 and Administration) request used to set the overhead rate
22 applied to all Federal Grants awarded the Uni versi ty.
23 I have been employed by the Commission as an
24 auditor since June 2007. I attended the annual.25 regulatory studies program sponsored by the NationalAssociation of
CASE NO. IPC-E-08-10
10/24/08
1298 VAUGHN, C. (Di) 2
STAFF
.
.
.
20
21
22
23
24
25
1 Regulatory Utilities Commissioners (NARUC) at Michigan
2 State Uni versi ty in August 2007.
3 SUMY
4 Q.Would you please summarize Staff's
5 recommendations in those areas of the rate case that you
6 personally reviewed?
7 A.Statf recommends use of a 2008 test year based
8 on adjustments to a 2007 base year. Staff's
9 recommendations in the areas I personally reviewed with
10 the effect on the revenue requirement are as follows:
11 (1) Idaho Power Company proposed using a 2008
12 forecast test year for this rate case. To
13 develop this test year, the Company escalated
14 2007 expenditures for Operations and
15 Maintenance (O&M) activity based upon a
16 calculated 5-year growth rate. However, it is
17 Staff's position that the forecast O&M is
18 overstated and should be reduced. The Company
19 requested an increase to O&M expense of
$15~ 985, 407. Staff recommends that O&M expense
be escalated by $1,750,020, thus decreasing
both expense and revenue requirement by
$14,235,387.
(2) In its forecast test year, Idaho Power
Company requested an increase of $6,617,514
CASE NO. IPC-E-08-10
10/24/08
1299 VAUGHN, C. (Di) 3
STAFF
.
10
11
12.13
14
15
16
17
18
19
20
21
22
1 for Plant Materials and Supplies. Staff
2 recommends maintaining the 2007 base year level
3 and removing this escalated amount from rate
4 base. This decreases revenue requirement by
5 $780,024.
6 (3) In this rate case, Idaho Power Company proposed
7 including a portion of the Construction Work in
8 Progress (CWIP) associated with the Hells
9 Canyon Relicensing Proj ect in rates. Staff
agrees that there is explicit evidence showing
that including the annual carrying charge on
CWIP in rates serves the public interest.
However, Staff believes that the amount to be
included in rates should be reduced by
$2,881,849.
(4) As a result of a series of FERC settlements
related to the 2003 billing, Idaho Power
Company received a credit in the amount of
$3,266,010. Staff recommends amortizing this
credi t over five years, thus decreasing the
annual revenue requirement by $653,202.
(5) Based on an audit of P-card expenditures, Staff
23 recommends reducing the 2007 base
.24 /
25 /
CASE NO. IPC-E-08-10
10/24/08
1300 VAUGHN, C. (Di) 4
STAFF
1 year expenses and revenue requirement by.2 $884,787 to remove expenditures that are either
3 excessi ve or that do not directly benefit the
4 customer.
5 Q.How were you able to determine the revenue
6 requirement effect of each of Staff's recommendations?
7 A.I determined what accounts in the rate case
8 would be changed by each adjustment. Using the
9 Jurisdictional Separation Study (JSS) and Revenue
10 Requirement Model, I then determined the effect on
11 revenue requirement resulting from each adj ustment.
12 Q.Are you sponsoring any additional testimony?.13 A. Yes. I am sponsoring testimony that summarizes
14 the adj ustments recommended by all Staff witnesses. In
15 addi tion, I am sponsoring testimony that describes the
16 Jurisdictional Separation Study, a model that develops
17 the Idaho revenue deficiency as well as the revenue
18 increase needed to meet that deficiency. The JSS shows
19 an Idaho Revenue Deficiency of $9,681,345 and results in
20 an Idaho required revenue increase of 1.44%
21 Q.Are you sponsoring any exhibits?
22 A.Yes, I am sponsoring Exhibit Nos. 119 through
23 127.
24 COST ESCATION OF OPERATIONS AN ~INTENANCE EXPENSES.25 Q.Please summarize the method used by Idaho Power
CASE NO. IPC-E-08-10
10/24/08
1301 VAUGHN, C. (Di) 5
STAFF
.1 to escalate 2007 O&M costs to develop the 2008 test year.
2 A. Idaho Power developed Compound Annual Growth
3 Rates (CAGR) that it applied to specific FERC O&M
4 "account groupings". These account groupings are (1)
5 Steam Power Production (Accounts 500-515), (2) Hydro
6 Power Production (Accounts 535-545), (3) Other Power
7 Production (Accounts 546-557), (4) Transmission (Accounts
8 560-574), (5) Distribution (Accounts 580-598), Customer
9 Accounting, Service, and Selling (Accounts 901-917
10 excluding DSM), and Administrative and General (Accounts
11 920-935). A different CAGR was calculated and applied to
12 each account grouping and was applied to all accounts.13 within that grouping with the exception of Accounts 501
14 and 547 (Fuel), 555.1 and 555.2 (Purchased Power), 565
15 (Transmission of Electricity by Others), 924 (Property
16 Insurance), and 928.101 (FERC Administrative &
17 Miscellaneous Expenses).
18 Q.How did you evaluate the reasonableness of this
19 escalation methodology?
20 A.I evaluated the escalation as follows:(1) I
21 looked at the accounts escalated to determine if
22 escalation of the specific accounts was reasonable; (2) I
23 looked at the development of the CAGR to determine if the
24 methodology was reasonable and tested the model using.25 data supplied by the Company; (3) I evaluated the data
provided
CASE NO. IPC-E-08-10
10/24/08
1302 VAUGHN, C. (Di ) 6
STAFF
.1 by the Company and determined which account groups showed
2 a consistent trend and developed a reasonable escalation
3 amount for those accounts.
4 Q.Did you have any concerns regarding escalation
5 of specific accounts or account groupings?
6 A.I had two maj or concerns regarding the
7 escalation of specific accounts and account groupings.
8 First, labor is included in many different
9 accounts in all account groupings. However, labor is
10 also escalated via the payroll annualization/structured
11 salary adjustment (SSA) as described by Ms. Smith in her
12 direct testimony at page 29, lines 12-17. Thus labor.13 costs are escalated by two different methods in the
14 Company's case. I believe it is inappropriate to escalate
15 labor costs using the CAGR when 2008 labor costs are more
16 directly escalated elsewhere. Payroll annualization and
17 SSA has been addressed previously by Staff witness Leckie
18 in his direct testimony.
19 Second, General and Administrative (G&A)
20 Accounts 920-935 are increased using a 5-year CAGR of
21 9.41 % . However, when the data used by the Company to
22 develop the CAGR for G&A expenses are examined, it is
23 apparent that G&A expense is essentially flat until 2006
24 with an average G&A expense of $73,500,068 for the period.25 2004-2006. However, G&A Expense in 2007 is equal to
CASE NO. IPC-E-08-10
10/24/08
1303 VAUGHN, C. (Di) 7
STAFF
1 $91,097,520, an increase of $17,597,452 from the ..2 2004-2006 average expense. This data is shown in Exhibit
3 No. 119, Columns 3-6, lines 72-77. This increase is
4 coincident with IDACORP divestiture of multiple
5 subsidiaries. This di vesti ture resulted in reallocation
6 of more corporate expenses to Idaho Power Company. Staff
7 believes it is unreasonable to further escalate G&A
8 expense when it is apparent that the growth in G&A is the
9 resul t of one-time corporate divestitures.
10 Q.Please describe how the Company developed its
11 escalation model?
12 A.Yes. Exhibi t No. 119 was provided by the.13 Company in response to Audit Request No. 53 and shows the
14 data used by the Company to develop its CAGR. This data
15 shows financial data organized by account group and by
16 cost element (Labor, Materials, Purchased Services,
17 Accounting Entries, and Other Expenses). This data is
18 provided for the years 2003-2007. The CAGR formula used
19 to analyze this data is shown in Exhibit No. 120. An
20 example of how the formula is applied is shown in Exhibit
21 No. 120 as well.
22 Q.Do you have any concerns regarding the method
23 used by the Company to develop the CAGR escalation model?
24 A.Yes. I have two maj or concerns regarding the.25 method used by the Company to develop its escalation
CASE NO. IPC-E-08-10
10/24/08
1304 VAUGHN, C. (Di) 8
STAFF
1 methodology..2 First, it is apparent from Exhibit No. 120 that
3 the formula applied to develop the CAGR is developed from
4 only two data points, the beginning and ending values.
5 There are an infinite number of formulas that can be used
6 to describe the relationship between two data points.
7 Choosing a Compound Annual Growth Rate to escalate
8 expenses is an arbitrary choice on the part of the
9 Company. From a mathematical modeling standpoint, the
10 CAGR is no more valid than any other escalation
11 methodology such as average growth rate.
12 Second, the Company did not test its model.13 against actual data. As stated by Ms. Smith in her
14 testimony at page 22, lines 17-18, the model as used
15 "smoothes out uneven amounts within these years."
16 However, it is apparent from casual inspection of the
17 data, that there is considerable variation in expenses
18 year-to-year.. For example, Materials Expense in Hydro
19 Production (Exhibit No. 119, line 15, Columns 2-10)
20 swings from $1.6 million in 2004 to $2.3 million in 2005
21 to $2.8 million in 2006 to $2.6 million in 2007. The
22 5-year CAGR shows a growth of 15.25% in this category,
23 but it is obvious from the actual data that there is no
24 consistent trend in growth..25 Q.How did you evaluate the data to determine a
CASE NO. IPC-E-08-10
10/24/08
1305 VAUGHN, C. (Di) 9
STAFF
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1 reasonable increase in O&M expense?
2 A.In consultation with Staff witness Carlock I
3 determined that the following method was most appropriate
4 to escalate 2007 O&M expense to develop the 2008 test
5 year. First I consolidated the data used by the Company
6 as shown in Exhibit No. 119 to eliminate labor and all
7 Administrative and General Expense. For the purpose of
8 this analysis, I combined Steam, Hydro, and Other Power
9 Generation to evaluate expense growth. This consolidated
10 data is shown in Exhibit No. 121.
11 I then examined the cost elements Materials,
12 Purchased Services, and Other Expenses for each account
13
14
group and determined whether year-to-year trending showed
consistent growth or whether there was no consistent
15 pattern. My determination is shown in Exhibit No. 121,
16 Column 12. The two cost elements that showed consistent
17 growth were Power Generation Other Expense and
18 Distribution Other Expense. In each case, I believe a
19 modest 5% growth escalation is reasonable because the
20 Company has some discretion over Other Expense spending.
21 Using this factor, the total gross escalation is
22 $2,876,561 (Exhibit No. 121, Column 12, line 42).
23 "Accounting Entries" is a cost element that
24 represents intracompany expense transfers and includes
25 such items as Amortization Expense. This expense
category
CASE NO. IPC-E-08-10
10/24/08
VAUGHN, C. (Di) 10
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1306
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1 is not directly related to any growth factors and any
2 change in the G&A account group does not appear to be
3 related to subsidiary di vesti ture by IDACORP. In order to
4 address this cost element group, I summed the total
5 Accounting Entries Expense for the years 2003 through
6 2007, averaged 3 years of year-to-year change, and
7 reflected this in the gross escalation. By accounting
8 convention, in this case the average Accounting Entries
9 adjustment to O&M escalation reduces the escalation
10 amount. (See Exhibit No. 122). As a result of these
11 calculations, the net escalation Staff believes is
12 reasonable and recommends be used to develop the 2008
13 test year is calculated to be $1,750,020.
14 PLAT MATERIALS AN SUPPLIES (RATE BASE-WORKING CAPITAL)
15 Q.Please summarize the method used by Idaho Power
16 to escalate 2007 Materials and Supplies to develop the
17 2008 test year.
18 A.Account 154 (Plant Materials and Supplies) is
19 the inventory of materials used for the construction,
20 operation, and maintenance of the entire utility plant
21 operated by Idaho Power. Account 163 is a clearing
22 account used to capitalize the expenses that are directly
23 related to inventory/storeroom maintenance. In its
24 development of the 2008 test year, the Company escalated
25 Account 154 using a 3-year CAGR equal to 16.38% and
CASE NO. IPC-E-08-10
10/24/08 1307 VAUGHN, C. (Di) 11
STAFF
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1 escalated Account 163 using a 3-year CAGR equal to 4.31%.
2 (See Smith Exhibit No. 34, page 15.) The total increase
3 in rate base using this methodology is equal to
4 $6,617,514.
5 Do you agree with this escalation?Q.
6 No. I believe that Plant Materials andA.
7 Supplies (including the portion due to stockroom
8 management) is dependent upon current conditions for
9 which there is no accurate predictor. Thus I believe
10 that the Company's proj ected increase cannot be
11 considered known and measurable with any degree of
12 certainty. Further, I believe that adequate planning,
13 ordering, and inventory management will allow inventory
14 levels to be maintained at 2007 levels. Therefore, I
15 recommend removing the $6,617,514 escalation from rate
16 base, thus decreasing revenue requirement by $780,024.
1 7 AFC ON THE HELLS CAYON RELICENSING PROJECT
18 Please describe the Company's proposal toQ.
19 include the current AFUDC portion of CWIP relative to the
20 Hells Canyon relicensing proj ect.
21 The' Company has requested recovery of theA.
22 currently accruing AFUDC for the Hells Canyon relicensing
23 proj ect as part of this rate case. AFUDC for this
24 project has accrued since 1999, but the Company is only
25 asking to include the AFUDC that is forecast to accrue in2009. In
CASE NO. IPC-E-08-10
10/24/08
VAUGHN, C. (Di) 12
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1308
1 large part, Staff agrees with the Company's proposal set.2 forth in direct testimony by Ms. Miller (Miller direct
3 testimony at page 3, lines 1-5)
4 "The purpose of my testimony is to request
that the Allowance for Funds Used During5 Construction ("AFUDC") component of
Construction Work in Progress ("CWIP") for
6 the Hells Canyon relicensing proj ect be
included in base rates."
7
8 This potential inclusion of CWIP /AFUDC in base rates is
9 an option the Commission may utilize based on a recent
10 change in Idaho Code.
11 In 1984 Idaho Legislature enacted Idaho Code §
12 61-502A to read.13 "Except upon its finding of an extreme
emergency, the (Public Utili ties)
Commission is hereby prohibited in any
order issued after the effective date of
this act, from setting rates for any
utili ty that grants a return on
construction work in progress... or property
held for future use and which is not
currently used and useful in providing
utility service."
14
15
16
17
18
19 However, in 2006 this section was amended to read
20 "Except upon its explicit finding that the
public interest will be served thereby,
the Commission is hereby prohibited in
order issued after the effective date of
this act, from setting rates for any
utili ty that grants a return on
construction work in progress or property
held for future use and which is not
currently used and useful in providing
utility service." (Emphasis indicates
amended language.)
21
22
23
24.25
CASE NO. IPC-E-08-10
10/24/08
1309 VAUGHN, C. (Di) 13
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1 Construction Work in Progress (CWIP) including
2 AFUDC may be considered in the determination of rates
3 upon a finding that the public interest will be served.
4 Staff believes that this case provides an appropriate
5 opportunity where the Commission can find that the public
6 interest will be served by the inclusion of the currently
7 accruing AFUDC on the Hells Canyon relicensing proj ect.
8 Staff agrees with the Company's concern that
9 AFUDC related to the Hells Canyon relicensing proj ect is
10 growing at an alarming rate. If AFUDC is allowed to
11 accrue using normal regulatory accounting procedures and
12 assuming no additional expenses are incurred during the
13 relicensing proj ect, the direct costs for the proj ect
14 would equal $67,682,931 and the AFUDC would equal
15 $42,703,648 by the end of 2009. By the end of 2012, the
16 direct costs of relicensing would still be $67,682,931
17 and the AFUDC. would have grown to $69,188,894. This
18 growth in AFUDC is clearly demonstrated in Exhibit No.
19 123. Staff believes that this enormous growth in AFUDC
20 provides the basis for an explicit finding that it is in
21 the public interest to include AFUDC in base rates using
22 the current annual AFUDC amount and thereby prevent the
23 further accumulation of AFUDC accruing on AFUDC.
24 Q.Did Staff adj ust the amount of AFUDC to be
25 included in based rates?
CASE NO. IPC-E-08-10
10/24/08
1310 VAUGHN, C. (Di) 14
STAFF
1 A.Yes.Staff calculated the amount of AFUDC to.2 be
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1311 VAUGHN, C.(Di)14a
10/24/08 STAFF
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1 included in base rates as follows: (1) First, the actual
2 AFUDC monthly rates were applied sequentially to the
3 prior month's ending CWIP balance. For example, the
4 January 2008 AFUDC rate of 6.6520% was applied to the
5 known and measurable December 2007 CWIP balance of
6 $95,642,535 resulting in the January 2008 ending CWIP
7 balance of $96,148,803. The February AFUDC rate of
8 5.5920% was then applied to the January 2008 ending CWIP
9 balance to arrive at the February 2008 ending CWIP
10 balance. The AFUDC rates for January through August of
11 2008 were supplied by the Company in response to Audit
12 Request No. 86 (d); the rate for September through
13 December of 2008 was estimated using the average rate for
14 the period January through August of 2008.(2) Second,
15 the December 2008 AFUDC of $396,191 was multiplied by
16 twelve in order to forecast the AFUDC for 2009. The
17 forecast AFUDC for 2009 was determined to be $4,754,292.
18 This resulted' in an adjustment of $2,881,849 and an
19 equi valent decrease in revenue requirement. See Exhibit
20 No. 124.
21 Q.Does Staff recommend any additional
22 modifications. to the Company's proposal?
23 A.Yes. Staff proposes the following to limit
24 escalation of AFUDC related to the Hells Canyon
25 relicensing proj ect.
(1) The Company proposes accounting for AFUDC
CASE NO,. IPC-E-08-10
10/24/08 1312 VAUGHN, C. (Di) 15
STAFF
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1 amounts recovered in base rates on the Hells Canyon
2 relicensing proj ect as an Account 254 Regulatory
3 Liability. (See Miller direct testimony at page 13,
4 lines 3-13.) For financial accounting purposes, AFUDC
5 will continue to accrue as CWIP using normal accounting
6 procedures. Once the Hells Canyon relicensing proj ect is
7 capitalized in rate base, the regulatory liability will
8 reduce the total amount of CWIP that is moved to electric
9 plant in service.
10 Staff agrees with the Company's proposal to
11 account for the funds related to recovery of AFUDC as a
12 Regulatory Liability. Additionally, Staff believes these
13 funds should accrue interest at the same rate as the
14 AFUDC booked as CWIP for financial accounting purposes.
15 This will prevent further compounding of AFUDC on the
16 accumulated proj ect costs. Accounting detail is shown in
17 the workpapers.
18 (2) Staff believes that including AFUDC in
19 base rates should be limited to the current rate case.
20 Even though compounding of AFUDC on accumulated project
21 costs will effectively cease December 2008, this new
22 mechanism for inclusion of AFUDC in base rates must be
23 examined. The FERC license on Hells Canyon may be issued
24 as soon as January of 2009 and the final accounting will
25 be examined in the next case. If the license has not
CASE NO. IPC-E-08-10
10/24/08
VAUGHN, C. (Di) 16
STAFF
1313
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1 been awarded, the Regulatory Liability and accounting
2 records for the CWIP and Regulatory Liability accounts
3 must still be examined to correct any flaws in the
4 methodology proposed in this case.
5 Q.Does Staff have any further recommendations
6 concerning overall cost control related to the Hells
7 Canyon relicensing proj ect?
8 A.Yes. Staff believes it is in the best interest
9 of customers to control the total cost of the Hells
10 Canyon relicensing project. If FERC grants a permanent
11 license in January 2009, costs will be finalized as soon
12 as the Hells Canyon relicensing project is placed in rate
13 base. Inclusion of the current AFUDC amount in base
14 rates provides the Co~?any with cash flow at a grossed-up
15 level. With the additional cash flow, the Company has
16 less of an incentive to push for completion of the
17 relicensing. To make sure the incentive for completion
18 remains as strong as it was before this case, Staff
19 recommends AFUDC stop at December 2009. All AFUDC
20 funding recovered in rates will continue to be booked as
21 a Regulatory Liability to offset Hells Canyon relicensing
22 CWIP once the proj ect is placed in rate base. Idaho
23 Power may file a separate case to request the Hells
24 Canyon relicerising project be evaluated for ongoing rate
25 treatment. This filing should provide sufficient
documentation and review of expenditures for
CASE NO. IPC-E-08-10
10/24/08
1314 VAUGHN, C. ( Di) 1 7
STAFF
.1 prudence prior to placing the proj ect in rate base.
2 Q. Why should the Commission consider allowing the
3 Hells Canyon relicensing proj ect to be placed in base
4 rates before a permanent license is granted by the FERC?
5 A.Al though there are limited situations where
6 public is served by placing CWIP in rate base, the Hells
7 Canyon relicensing proj ect is different from other
8 construction proj ects for several reasons. First,
9 "proj ect completion" is determined when the FERC grants a
10 permanent license. Because of the large number of
11 stakeholders involved in relicensing and because of the
12 ever-shifting political environment, proj ect completion.13
14
is largely beyond the Company's direct control. A
permanent license could be granted as early as January
15 2009 or it could be delayed for many years. Second, it
16 is unlikely that the permanent license will not be
17 granted. At the present time, Idaho Power is operating
18 the Hells Canyon dam complex under annual licensing.
19 Because the Hells Canyon complex is fully operational and
20 power generat~on is not curtailed, Staff argues that the
21 relicensing investment is essentially used and useful at
22 the present time, even in the absence of a permanent
23 license.
24 FERC CREDIT ADJUSTMNT.25 Q. Will you please explain the adj ustment to
revenue requirement related to the FERC credit?
CASE NO. IPC-E-08-10
10/24/08 1315 VAUGHN, C. (Di) 18
STAFF
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1 A.In 2006, Idaho Power Company received a series
2 of credits from a settlement involving both FERC
3 administration and Other Federal Agency (OFA) charges.
4 Based on data received from Idaho Power Company in
5 response to Audit Request Nos. 133 and 134 made during
6 general rate case IPC-E-07 -08, it was determined that the
7 total amount of the credits equalled to $3,266,010.
8 Since Idaho Power accrued these fees beginning in 2003,
9 they were included in rates paid by the customer in both
10 the 2003 and 2005 rate cases. Therefore, I believe that
11 the customer should receive benefit from the credit
12 received by Idaho Power. I believe that this credit
13 should be amortized over a five-year period since this
14 approximates the timeframe during which Idaho Power
15 over-accrued FERC/OFA fees. This results in a negative
16 adjustment to regulatory fee expense of $653,202, thus
17 decreasing revenue requirement by $653,202.
18 ACCOUNTS PAYABLE ONE CA (P-CA) ADJUSTMNT
19 Q.Will you please describe Exhibit No. 125?
20 A.Exhibit No. 125 lists amounts by FERC account
21 that should be moved below the line for ratemaking
22 purposes. The total adjustment is $884,787 and results
23 in a revenue requirement decrease of $884,787.
24 Q.How did you arrive at this adjustment?
25 A.In the spring of 2008, Staff conducted an
CASE NO. IPC-E-08-10
10/24/08
1316 VAUGHN, C. (Di) 19
STAFF
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1 extensive audit of expenditures charged to Accounts
2 Payable One Cards (P-cards) by Idaho Power employees.
3 Q.How are P-cards used by Idaho Power employees?
4 A.The Company uses P-cards issued to employees to
5 manage the purchase and reimbursement of relatively
6 small, business-related expenses. As of June 30, 2007,
7 the Company employed 1977 individuals; 1818 individuals
8 (92%) of these individuals were issued P-cards. In 2007,
9 the total amount of employee P-card expenditures was
10 approximately equal to $11,212,016. Each month,
11 individual employees reconcile their P-card expenditures
12 by entering a justification for each expenditure on-line
13 in "PassPort" and enclosing receipts or other supporting
14 documentation in a reconciliation envelope. These
15 envelopes are filed alphabetically by employee each
16 month; approximately 1500 P-card reconciliations are
17 filed each month.
18 What was the obj ecti ve of Staff's audit ofQ.
19 Idaho Power employee P-cards?
20 A.The obj ecti ves of the Staff audit were to
21 examine receipts for appropriate detail, to evaluate cash
22 control, and to determine whether those expenditures are
23 appropriately the responsibility of Idaho Power's
24 customers. This audit also allowed Staff to examine the
25 processes used to track P-card expenditures and to ensure
CASE NO. IPC-E-08-10
10/24/08
VAUGHN, C. (Di) 20
STAFF
1317
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.
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1 that expenditures were booked to the appropriate accounts
2 for ratemaking purposes. The audit allowed Staff to
3 evaluate Company policies that govern P-card expenditures
4 and to determine whether the expenditures were made for
5 prudent and reasonable business purposes that directly
6 benefi t the customer.
7 Q.How did Staff plan and conduct the audit?
8 A.The P-card audit conducted during the audit
9 associated with general rate case IPC-E-07-08 was limited
10 by time and resources. In order to fully evaluate the
11 propriety of P-card expenditures for ratemaking purposes,
12 a more extensive audit was employed for the purposes of
13 the current rate case. The audit was conducted as
14 follows:
15 (1). Approximately 75 envelopes were audited
16 for each month of 2007. The envelopes were chosen by
17 assigning each envelope a number from 1-1500
18 (approximately); the 75 envelopes were chosen by
19 generating 75 random numbers using Microsoft Excel~.
20 (2) Each envelope was examined for original
21 supporting documentation, adequate matching of on-line
22 (Passport) justification with the documentation contained
23 in the envelope, and to ensure that there was appropriate
24 approval of expenditures by a third party.
25 (3) The Company provided a Microsoft Excel~
CASE NO. IPC-E-08-10
10/24/08 1318 VAUGHN, C. (Di) 21
STAFF
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1 list of all P-card expenditures that included FERC
2 account, vendor, and business justification for each
3 expendi ture. A line-by-line examination of all
4 expendi tures was performed by Commission Staff. Each
5 expendi ture was classified by Staff as Gifts/Awards,
6 Restaurant, Cell Phone, Coffee/Water, Donations,
7 Political, SB.IPC, or "ok"; other expenditure
8 classifications were considered acceptable for the
9 purpose of this audit. "Gifts/Awards" included parties,
10 celebrations, greeting cards, gifts, and awards.
11 "Restaurant" included in-state restaurant meals, food and
12 related items purchased in grocery stores, and treats for
13 Company staff meetings; out-of-state meal purchases and
14 expenditures clearly identified as "per diem" were
15 classed as "ok." "Cell phone" included monthly cell
16 phone fees as well as cell phone accessories.
17 "Coffee/water" included bottled water purchased for
18 office locations, breakroom coffee supplies, and local
19 newspaper subscriptions; food purchases for cafeteria
20 resale were not included. "Donations" and "Political"
21 included various charitable donations and other
22 expendi tures that should have been moved below the line
23 for ratemaking purposes. "SB IPC" included expenditures
24 similar to those removed by the Company subsequent to its
25 "keyword" search as described in Ms. Smith's direct
testimony at pages 14-15 and detailed
CASE NO. IPC-E-08-10
10/24/08
VAUGHN, C. (Di) 22
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1319
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.
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1 in Company Exhibit 30, pages 2-9.
2 It should be noted that the Company removed
3 $195,563 in memberships and donations and $18,675 in
4 other expenditures from the 2007 base year. Staff made
5 every attempt to avoid duplication of these exclusions in
6 its audit of P-card expenditures.
7 It should also be noted that the classification
8 system used by Staff is purposely broad; as a result,
9 some expenditures were arbitrarily assigned to one
10 category rather than another. For example a celebration
11 dinner may have been assigned to the "restaurant"
12 category rather than "Gifts/Awards". Because the
13 indi vidual transactions were small, the impact of any
14 discrepancy in expenditure classification is immaterial.
15 I believe this audit addressed concerns
16 expressed by the Company in the prior rate case -
17 specifically (1) sample size, (2) selection methodology,
18 (3) incomplete evaluation of findings, (4)
19 monthly / seasonal variation, and (5) weighting percentage
20 of expenditures moved below the line based on total
21 dollar value audited.
22 Q.Please describe Exhibit No. 125.
23 A.Exhibi t No. 125 consists of two pages and lists
24 expenditures by FERC account and by expense
25 classification. Columns 1-8 list the expense
CASE NO. IPC-E-08-10
10/24/08 1320 VAUGHN, C. (Di) 23
STAFF
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1 classifications used by Staff; line 58 shows the amounts
2 for each classification that should be moved below the
3 line for ratemaking purposes. These amounts are (1)
4 $247,339 for Gifts/Awards, (2) $236,274 for restaurant
5 expenditures, (3) $306,475 for cell phone related
6 expenditures, (4) $61,729 for bottled water, coffee, and
7 newspapers, (5) $17,606 for charitable donations, (6)
8 $7,999 for political activity, and (7) $7,366 for
9 expendi tures that should have been removed by the Company
10 keyword search. The total amount that I believe should
11 be moved below the line is $884,787. The individual
12 expendi tures are provided electronically in the
13 workpapers.
14 Q. What criteria were used by Staff to classify
15 expenditures as "Gifts/Awards" as shown in Column 1?
16 A.Vendor and business justification were the
17 cri teria used to identify items classified as
18 Gifts/Awards . Expenditures classified as Gifts/Awards
19 included Christmas parties, gift certificates, greeting
20 cards, team celebrations, and flowers. Specific examples
21 include a $390 retirement gift, $200 in gift cards as an
22 appreciation gift, and $1800 for an adult Christmas
23 party. The total of all expenditures classified as
24 Gifts/Awards totals $247,339. I believe that these
25 expendi tures, though allowable as traditional business
expendi tures, do
CASE NO. IPC-E-08-10
10/24/08 1321 VAUGHN, C. (Di) 24
STAFF
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1 not benefit the customer and therefore 100% of the
2 expenditures for Gifts/Awards should be moved below the
3 line for ratemaking purposes. A complete list of
4 expendi tures classified as "Gifts/Awards" is shown in the
5 workpapers.
6 Q.What criteria were used by Staff to classify
7 expenditures as "Restaurant" as shown in Column 2?
8 A.Vendor and business justification were the
9 cri teria used to identify expenditures classified as
10 "Restaurant. " Expenditures included purchases made at
11 coffee shops, restaurants, and grocery stores located in
12 southern Idaho and western Oregon; similar purchases made
13 outside these areas were considered to be travel-related
14 and therefore were considered "ok." Cash advances
15 clearly identified as per diem and purchases for
16 cafeteria resale were also excluded from the "Restaurant"
17 category. Expenditures excluded by the Company were also
18 excluded from this category. Restaurant expenditures
19 totaled $472,547; $236,274 or 50% was moved below the
20 line for ratemaking purposes.
21 Q.Why did Staff move only 50% of the expenditures
22 classified as Restaurant below the line?
23 A.The total number of accounting entries exceeded
24 150,000 rows;. 17,787 lines of data were classified as
25 "Restaurant" expenditures. Because of this large amount
CASE NO. IPC-E-08-10
10/24/08 1322 VAUGHN, C. (Di) 25
STAFF
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1 of data, it was clearly impossible for Staff to review
2 all supporting documentation and to determine whether a
3 gi ven expenditure should be moved below the line for
4 ratemaking purposes. However, I do believe that the
5 total amount of expenditures classified as "Restaurant"
6 is excessive. Of course, many of these "Restaurant"
7 expendi tures were incurred in the course of in-state
8 travel and reasonably incurred business meals such as
9 those related to fire suppression. The 50% of all
10 expendi tures that Staff allowed as reasonable O&M expense
11 provides for these reasonable and prudent business
12 expendi tures. However, Staff also believes that many of
13 the expenditures were neither a reasonable nor necessary
14 expense for a regulated utility. Worrisome examples
15 include $41.64 at Elmers Pancake House for a team
16 meeting, $53.05 described as "meet with contractor",
17 $10.89 with another employee justified as "employment
18 review stuff", and $34.43 "coffee/cookies for meeting".
19 Staff does not believe it is necessary for customers to
20 provide food for meetings, to pay for a restaurant meal
21 for two Company employees, or to entertain a contractor
22 when the Company is not competing for business with
23 another supplier of power. Therefore, I moved 50% of all
24 expenditures classified as "Restaurant" below the line to
25 eliminate expenditures that are believed to be excessive.
CASE NO. IPC-E-08-10
10/24/08 1323 VAUGHN, C. (Di) 26
STAFF
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1 I do not contend that any of these
2 restaurant-type expenditures are violations of Company
3 policy; in fact, Company policy permits meal
4 reimbursement if Company business is conducted during the
5 meal. However, I believe that Company policy is overly
6 permissive regarding expenditures for restaurant meals
7 and other food provided for its employees. Since the
8 Company has put forth a cost containment ini tiati ve in
9 the current rate case as filed (see Smith direct
10 testimony at pages 29-30), I believe the Company should
11 consider tightening its policy regarding food-related
12 expense rather than continually increasing rates. Cost
13 containment is discussed further in Staff witness Joe
14 Leckie's testimony.
15 Q.What criteria were used by Staff to classify
16 expenditures as "Cell Phone" shown in Column 3?
17 A.Vendor and business justification were the
18 cri teria used to identify expenditures classified as
19 "Cell Phone." Expenditures included purchases for
20 monthly charges from known providers such as Verizon and
21 AT&T/Cingular, as well as expenditures for cell phone
22 holsters, headsets and similar accessories. Staff did
23 not include any employee reimbursement for personal cell
24 phone charges in this total. The total amount of "Cell
25 Phone" O&M expense was $539,959; I believe this amount is
CASE NO. IPC-E-08-10
10/24/08 1324 VAUGHN, C. (Di) 27
STAFF
.
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1 excessi ve and moved $306,475 below the line for
2 ratemaking purposes.
3 Q.Please discuss your rationale for this
4 adj ustment.
5 A.The total amount of "Cell Phone" expense
6 charged to P-cards was $793,855. Of this amount,
7 $539,959 was allocated to O&M expense and the rest was
8 allocated to construction or other accounts. I believe
9 this cell phone-related expense to be excessive for two
10 reasons.(1) The total expenditure of $793,855 was
11 calculated to pay for an estimated 1,300 cell phones
12 ($793,855 divided by 12 months divided by $50 per month);
13 in other words, the Company provides cell phones for an
14 estimated 66% of employees (1300 cell phones/2000
15 employees). I believe it is excessive to provide cell
16 phones for this many employees. (2) $145,981 (27%) of
17 the total O&M cell phone expense is charged directly to
18 A&G (FERC account 921, A&G Office Supplies and Expense) .
19 I believe it is excessive to incur this expense since
20 most A&G employees are employed at Company central
21 headquarters.
22 To adjust for this apparent excess, I removed
23 75% of the cell phone expense charged to A&G and 50% of
24 all remaining cell phone expense. I estimated $233,484.25 (43%) of the original $539,959 to be reasonable and
prudent O&M expense.
CASE NO. IPC-E-08-10
10/24/08 1325 VAUGHN, C. (Di) 28
STAFF
.
.
.
1 I recognize that cell phones are an important
2 aspect of every-day business communication. I also
3 recognize that, given the wide-spread and often remote
4 work areas of Company employees, reasonable cell phone
5 communication expense should be included in rates. I am
6 concerned that cell phone charges may be greater than
7 necessary because rates, providers, and calling plans
8 vary widely among employees. Gi ven the large total
9 expense incurred by the Company for cell phone-related
10 costs and because the Company stated in testimony the
11 importance of cost containment, I believe the Company
12 should investigate a cell phone practice that reduces
13 cost and is more equitable for the customer.
14 Q. What criteria were used by Staff to classify
15 expenditures shown in Column 4-7 of Exhibit No. 125?
16 A.Column 4 lists expenditures for bottled water,
17 coffee, newspapers, and other items that Staff considers
18 to be luxury items that do not directly benefit the
19 customer. The total amount classified as Coffee/Water is
20 $61,729. Although expenditure for these items are
21 generally allowed for business purposes, I believe these
22 expenses should be moved below the line for ratemaking
23 purposes since they do not directly benefit the customer.
24 Column 5 lists Donations totaling $17,606.
25 Column 6 lists various expenditures related to political
CASE NO. IPC-E-08-10
10/24/08 1326 VAUGHN, C. (Di) 29
STAFF
.
.
.
1 acti vi ty and lobbying in the amount of $7,999. These
2 expenses are traditionally moved below the line for
3 ratemaking purposes. These expenditures were coded to
4 the wrong expense account and were adj usted as a result
5 of Staff audit of all 2007 P-card expenditures.
6 Column 7 lists a number of expenditures that
7 were similar in nature to "keyword" adjustments made by
8 the Company. The total of these adjustments is $7,366.
9 Q.Please summarize the impact of the adjustment
10 to O&M expense resulting from the P-card audit.
11 A.The total of all O&M expenditures (FERC
12 accounts 500 through 935, excluding DSM and General
13 Advertising) made using Company P-cards was equal to
14 $6,585,793 in 2007. As a result of Staff's P-card audit,
15 $884,787 (13.43%) was moved below the line for ratemaking
16 purposes; add~tional expense of approximately $273,489
17 (4.15%) was removed by the Company. After removing these
18 recommended Staff adjustments plus the Company
19 adjustments, $5,699,390 in P-card purchases remain
20 included by Staff as O&M expense in the calculation of
21 the Company's revenue requirement.
22 Q.Did Staff observe adequate accounting controls
23 during its audit of P-card reconciliation?
24
25
A.During its audit of Company P-card
reconciliation practices, Staff learned that the Company
CASE NO. IPC-E-08-10
10/24/08 1327 VAUGHN, C. (Di) 30
STAFF
.1 makes every effort at the accounting level to ensure that
2 appropriate documentation and approval is provided for
3 every expenditure, particularly for cash advances.
4 In addition, although there is a Company policy
5 suggesting pre-approval in the case of questionable
6 expendi tures, Staff found no documentation supporting
7 such pre-approval attached to the P-card reconciliation.
8 For most purchases, it is my belief that the system is
9 based on approval after-the-fact. As a practical matter,
10 I believe it is much easier for an employee to provide
11 documentation. after-the-fact to justify an expenditure
12 than it is to obtain prior approval for the expenditure..13 Q. Do you have any additional concerns that are
14 related to P-card expenditures?
15 A.Yes. I have several specific areas of concern
16 related to the extensive use of P-cards at Idaho Power
17 Company.
18 First, the Company seems to have minimal
19 interest in effective cost containment in certain areas.
20 The amount spent on Gifts/Awards and food-related expense
21 is excessive. Additionally, the policy regarding meal
22 and other receipts seems lax. Receipts are not required
23 for meals costing less than $75 paid for by P-card or for
24 meals paid for with cash costing less than $25. Non-.25 itemized receipts, e.g. duplicate credit card receipts,
CASE NO. IPC-E-08-10
10/24/08 1328 VAUGHN, C. (Di) 31
STAFF
.1 are acceptable as a receipt with some written notation of
2 purpose. There is no evidence that this is an abuse of
3 Company policy in these areas because these expenditures
4 are either explicitly allowed in the Company handbook or
5 implici tly allowed due to supervisor approval. I believe
6 Gifts/Awards and Restaurant-type expenses offer fertile
7 ground for the Company to tighten policy and practice
8 effective cost containment.
9 Second, P-cards seem to be used in lieu of
10 standard business purchasing practices. For example,
11 office supplies are purchased with P-cards rather than
12 through a general Company account and/or rate that is.13 negotiated at the Company level by a qualified purchasing
14 professional. In addition, Cell Phone fees, phones, and
15 accessories are purchased and paid for by individuals
16 using Company. P-cards. If the current magnitude of cell
17 phone expense is truly a Company necessity, a Company
18 level contract should be professionally negotiated with a
19 cell phone service provider. I believe it is possible
20 that using established purchasing practices for large
21 Company-wide purchase contracts could result in
22 significant cost containment.
23 Third, it is possible for P-cards to be used
24 for personal expenses. Further, P-cards can be used for.25 cash advances without pre-approval, thus allowing
CASE NO. IPC-E-08-10
10/24/08 1329 VAUGHN, C. (Di) 32
STAFF
.
.
.
1 employees direct access to the most liquid of Company
2 assets: cash. It is evidence of poor cash management if
3 an employee can use his P-card for personal expenses or a
4 cash advance similar to a "payday loan". Although the
5 Company reconciles documentation for all cash advances,
6 this practice is essentially the equivalent of giving any
7 employee with a P-card unfettered access to a petty cash
8 fund of $5000 or more. I believe this exposes the
9 Company to unnecessary financial risk that could be
10 addressed by modifying the policies and practices related
11 to P-card use.
12 Q.In its audit, did Staff find any direct
13 evidence of employee abuse of the P-card system?
14 A. No. However, the widespread use of P-cards and
15 the ability for an employee to take cash withdrawals to
16 self-reimburse for expenditures prior to approval opens
17 the door to the possibility of employee abuse. It should
18 be noted that there are three conditions typically
19 present when examples of the type of employee abuse
20 described above have occurred: (1) motivation, (2)
21 opportunity, and (3) an attitude that rationalizes such
22 abusive behavior. Al though motivation is an individual
23 factor, the Idaho Power P-card practices in place provide
24 the opportunity for excessive spending using Company
25 P-cards. Further, the widespread use of P-cards for
Gifts/Awards,' meals, and
CASE NO. IPC-E-08-10
10/24/08 1330 VAUGHN, C. (Di) 33
STAFF
.
.
1 other expenditures that do not directly benefit the
2 customer certainly enables or creates an environment
3 where an employee could easily rationalize and/or justify
4 excessi ve spending behavior.
5 The Company has stated that a P-card review is
6 scheduled as part of its ongoing policy review. These
7 areas of Staff concern should be considered for
8 modification in the review process. I believe that if
9 the Company is truly committed to cost containment,
10 modification of policies and practices related to P-card
11 usage is clearly indicated. Staff witness Joe Leckie
12 addresses cost containment by the Company in his
13 testimony.
14 STAFF ADJUSTMNT SUMY AN RENU REQUIRENT
15 Q.Please describe the method by which Idaho Power
16 developed its forecast test year.
17 A.As described at length in Ms. Smith's direct
18 testimony, Idaho Power developed its 2008 test year based
19 on 2007 historical data in a series of sequential steps.
20 (1) 2007 actual data was modified by routine regulatory
21 and normalization adjustments to develop the 2007 base
22 year.(2) Various 2007 base year accounts were escalated
23 using various escalation methods to develop the 2008 base
.24
25
year.(3) The 2008 forecast test year was finally
developed by adding various normalizing and annualizing
CASE NO. IPC-E-08-10
10/24/08 1331 VAUGHN, C. (Di) 34
STAFF
.
.
.
1 factors to the 2008 base year data. The model for the
2 development of the historical test year is shown in the
3 electronic workpapers provided with this testimony.
4 Q.Please explain how Staff audited and made
5 adj ustments to the Company forecast test year.
6 A.The Company developed its 2008 test year using
7 the Jurisdictional Separation Study model (JSS). Because
8 of the multi-step method used by the Company to develop
9 its revenue requirement, Staff audited and adj usted the
10 JSS in two phases in order to develop Staff's recommended
11 revenue requirement. First, Staff audited the 2007 base
12 year data and made adjustments that were used to develop
13 the 2007 base year. Second, Staff tested the various
14 escalation factors as well as the various forecast data
15 supplied and made separate adjustments to the 2008 base
16 year in the JSS. The various adjustments are described
17 previously in testimony.
18 Sumary of Adjustments
19
20
Q.Please explain Exhibit No. 126.
A.Exhibi t No. 126 illustrates my calculation of
21 the revenue requirement and rate increase and compares
22 Staff's case to the case filed by Idaho Power. Staff's
23 revenue requirement is based on an Idaho rate base of
24 $2,087,973,882, total operating revenues of $816,477,779
25 and total operating expenses of $656,100,873 for the
CASE NO. IPC-E-08-10
10/24/08 1332 VAUGHN, C. (Di) 35
STAFF
.
.
1 Idaho jurisdiction. Column 3 shows Staff's calculated
2 results for the total system. Column 3, line 39, shows a
3 system revenue deficiency of $27,579,373; Column 3, line
4 41, shows a system revenue requirement of $737,651,947;
5 and Column 3, line 42, shows a required system increase
6 in revenues of 3.88%. Column 4 shows Staff's calculated
7 revenue deficiency, revenue requirement, and required
8 rate increase for the Idaho jurisdiction. Column 4, line
9 39, shows an Idaho revenue deficiency of $9,681,345;
10 Column 4, line 40, shows an Idaho revenue requirement of
11 $682,850,886; and Column 4, line 41, shows an Idaho
12 required rate increase of 1.44%.
13 Q.Please explain Exhibit No. 127.
14 A.Exhibit No. 127 summarizes the adjustments made
15 to the Company's 2008 forecast test year to obtain the
16 final numbers included in Staff's revenue requirement.
17 Lines 1-16 outline the proposed rate base on which the
18 Company should earn a return. Column 1 represents the
19 13-month average rate base presented by the Company in
20 its case. Column 2, line 7 shows a decrease in Allowance
21 for Accumulated Depreciation. Column 3, line 13 adjusts
22 working capital for escalated Materials and Supplies.
23 Staff witness Joe Leckie is the primary rate base witness
24 and the adjustment to Allowance for Accumulated.25 Depreciation is discussed in greater detail in his
CASE NO. IPC-E-08-10
10/24/08 1333 VAUGHN, C. (Di) 36
STAFF
.
.
.
1 testimony. I am the primary witness addressing
2 escalation factors and the adjustment to Materials and
3 Supplies as discussed previously in my testimony.
4 Q.What adjustments were made to the test year O&M
5 expenses?
6 A.The Company made a number of adj ustments to
7 develop the 2007 regulatory base year. These are the
8 standard Commission adjustments arising from previous
9 orders. In addition, the Company made a series of
10 annualizing adjustments as well as adjustments reflecting
11 known and measurable revenues and expenses that affect
12 2008 and 2009. Except as specifically noted in
13 testimony, Staff agrees with the Company on these
14 adj ustments. . The sum total of these adj ustments is
15 reflected on Exhibit No. 127, Column 1, lines 17-34;
16 Column 1, lines 17-34 summarizes net income components as
17 presented by the Company's case as filed.
18 Q.Did. Staff make additional adj ustments to the
19 Company's case as filed.
20 A.Yes. For ease of presentation, Staff
21 adjustments to both the 2007 base year and to the 2008
22 test year are combined. Combination of these two
23 adjustment components did not impact the final revenue
24 requirement.
25 Q.Please describe the adjustments shown in Column
CASE NO. IPC-E-08-10
10/24/08 1334 VAUGHN, C. (Di) 37
STAFF
.
.
.
19 3.
20
1 2 of Exhibit No. 127?
2 A.Adjustments shown in Column 2 include
3 adjustments to forecast 2008 revenues, to salary expense,
4 and to depreciation expense. Staff witness Joe Leckie
5 discusses these adj ustments in his testimony.
6 Q.What adjustments are made to revenues?
7 A.The Company reduced 2007 Miscellaneous Service
8 Revenues by 13.99% in its development of the 2008 test
9 year. Staff witness Joe Leckie removed this reduction,
10 thus increasing revenues by $566,667. This adjustment is
11 discussed in his testimony.
12 Q.What adjustments are made to O&M expense?
13 A.Staff witness Joe Leckie removed a total of
14 $7,872,605 from O&M expenses for payroll expense,
15 incenti ves, attorney fees and interest on directors'
16 fees. These adj ustments are discussed in great detail in
17 Mr. Leckie's testimony.
18 Q.Please describe the adjustments shown in Column
A.The adjustments to Operations and Maintenance
21 expense were made by me and are summarized in Column 3.
22 In total these adj ustments reduce O&M expense by
23 $15,774,714.
24
25
Q.Please describe these adjustments.
A.These adjustments consist of $14,236,725
CASE NO. IPC-E-08-10
10/24/08 1335 VAUGHN, C. (Di) 38
STAFF
.
.
1 related to reducing O&M expenses that were escalated in
2 forecasting the 2008 test year; $653,202 is due to
3 amortization of a credit that related to overbilling by
4 FERC; and $884,787 due to moving certain P-card
5 expendi tures below the line for ratemaking purposes.
6 These adj ustm~nts are discussed previously in detail in
7 my testimony.
8 Q.Please describe the adjustments shown in Column
9 4 of Exhibit No. 127.
10 A.Staff witness John Nobbs has removed $ 666,950
11 of miscellaneous administrative expenses from O&M
12 expense. Mr. Nobbs' adj ustments are discussed in detail
13 in his testimony.
14 Q. Please describe the adjustments shown in Column
15 5 of Exhibit No. 127.
16 A.Adj ustments to O&M Expense shown in Column 5
17 are the power supply adj ustments. Staff witness Rick
18 Sterling discusses the normalizing of power supply
19 expenses and Aurora modeling in his testimony.
20 Q.Please describe the adjustment shown on Exhibit
21 No. 127, lines 33-34, Column 3.
22 A.The Company requested that a portion of the
23 AFUDC related' to the Hells Canyon relicensing proj ect be
24 included in base rates. The Company showed this AFUDC as.25 a direct adj ustment to revenue requirement. I adj usted
CASE NO. IPC-E-08-10
10/24/08 1336 VAUGHN, C. (Di) 39
STAFF
.
.
.
17
18
19
20
21
22
23
24
25
1 the amount of AFUDC included in rates by $2,881,849; this
2 adj ustment is shown in Column 3, line 34.
3 CAPITAL STRUCTUR AN COST OF CAITAL
4 Q.Please summarize the capital structure and cost
5 of capital.
6 A.The capital structure of Idaho Power reflected
7 in the Staff's revenue requirement consists of
8 approximately 51% debt and 49% common equity. Staff uses
9 an overall cost of capital of 8.057 % to calculate the
10 Company's revenue requirement. This amount is based on a
11 cost of debt of 5.927%, and a return on equity of 10.25%
12 as mentioned previously. Staff witness Carlock addresses
13 these items.
14 Q. Does this conclude your direct testimony in
15 this proceeding?
16 A.Yes, it does.
CASE NO. IPC-E-08-10
10/24/08 1337 VAUGHN, C. (Di) 40
STAFF
.1
2 open hearing.)
(The following proceedings were had in
MR. PRICE: I would now present this
4 wi tness for cross-examination.
3
5 COMMISSIONER SMITH: Thank you.
6 Mr. Bruder, do you have questions?
.
18
7
8
9
10 Madam Chair.
11
12
13
14
15
16
17
MR. BRUDER: I have none.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: I have no questions,
MR. PURDY: No questions.
MR. OLSEN: No questions.
MR. WARD: No questions.
COMMISSIONER SMITH: Ms. Nordstrom.
MS. NORDSTROM: Thank you.
CROSS-EXAMINATION
19 BY MS. NORDSTROM:
20
21
22
Q
A
Q
23 testimony
24.25
A
Q
Good afternoon.
Good afternoon.
Turning your attention to page 3 of your
Direct?
Yes -- you state your belief that Idaho
CSB REPORTING
[phone]
1338 VAUGHN (X)Staff
.
.
1 Power has overstated its operations and maintenance
2 expense and revenue requirement by more than $14.2
3 million, more specifically Staff took issue with the use
4 of the 5.82 percent compound annual growth rate; is that
5 correct?
6 A I did not directly address the 5.82 annual
7 growth rate. What I did address was the methodology used
8 to develop the compound annual growth rate that was used
9 to escalate O&M expenses.
10 Q Have you read Ms. Smith's rebuttal
11 testimony?
12 A I have.
13 Q Given that Idaho Power's 2008 third
14 quarter O&M expense as described in Ms. Smith's rebuttal
15 testimony was. three-quarters of the amount indicated by
16 that compound annual growth rate, doesn't that
17 demonstrate that Idaho Power's O&M escalation value is
18 valid?
19 A It demonstrates that Idaho Power is
20 spending that much money. Whether or not all of those
21 expendi tures should be the responsibility of the
22 ratepayer is a different issue.
23 Q Is it your opinion that the compound
24 annual growth rate proposed by the Company is tracking.25 actual expenses based on that testimony and her
CSB REPORTING
[phone]
1339 VAUGHN (X)Staff
.
.
.
1 exhibits?
2 A The compound annual growth rate is an
3 escalation of the 2007 expenses and it was a methodology
4 for creating a forecast test year.
5 Q Isn't the 5.82 compound annual growth rate
6 that is proposed by the Company closer to the actual
7 expenses that the Company incurred than Staff's
8 escalation rate of .64 percent for the 2008 test year?
9 A Those are the -- that is the amount of
10 money that the Company has in fact expended and I have no
11 reason to doubt that that number is correct. That is
12 what has been recorded in those accounts, yes.
13 Q Did you have an opportunity to review the
14 growth rates of Idaho Power's Northwest peer utili ties
15 found in Exhibits 85 and 86 of Ms. Smith's testimony?
16 A I did look at those. I did not analyze
1 7 them, however.
18 Q In your opinion, do those exhibits support
19 the Company's growth rate?
20 A That in the methodology used, the
21 methodology was based on escalating the 2007 actuals into
22 the 2008 to create a forecast test year and my analysis
23 was based primarily on evaluating the methodology of
24 developing the forecast.
25 Q Based on what other utili ties in the
CSB REPORTING.
[phone]
1340 VAUGHN (X)
Staff
.
.
.
16
1 Northwest are experiencing for their O&M rates, do you
2 have an opinion about whether Idaho Power's growth rate
3 is a reasonable approximation of what other utilities in
4 the region are experiencing?
5 A I don't have an opinion based on that
6 because that is more of an economic analysis and that was
7 not my area of expertise.
8 Q You indicated that you didn't have any
9 doubt that Idaho Power actually incurred the expenses
10 through the third quarter of this year. Does that mean
11 that Staff wishes to change its recommendation with
12 regard to the $14.2 million disallowance?
13 A No.
14 Q So actual expenses are not a good
15 indicator of what Staff's recommendation is?
A Actual expenses are gross expenses and
17 those are adjusted for regulatory or ratemaking
18 purposes.
19 Q Did you attend the workshop on developing
20 the methodology for the 2008 test year that was held
21 earlier this year?
22
23
A No, I did not.
Q Was your testimony reviewed by people who
24 did attend that workshop?
25 A Yes, it was.
CSB REPORTING.
[phone]
1341 VAUGHN (X)Staff
.
.13
14
1 Q To your knowledge, what was the intent of
2 that workshop?
3 A To my knowledge, the intent of that
4 workshop was to discuss with Staff the possibility of
5 using a forecast test year for the next general rate case
6 which is this one.
7 Q So was there some intent for that workshop
8 other than to. create a methodology like what Idaho Power
9 has presented in this case?
10 A It is my understanding that no methodology
11 was agreed upon. It was simply to suggest that Staff
12 would consider developing a forecast test year was
reasonable or would be something they would consider.
Q So given that a methodology wasn't, the
15 specifics weren't agreed on for the compound annual
16 growth rates, but yet, the one that Idaho Power has
17 proposed for operations and maintenance expenses is
18 tracking perfectly or nearly perfectly according to
19 Ms. Smith's exhibits with the 2008 test year, would that
20 appear to be a valid predictor of the Company's 2008
21 expenses?
22 A It certainly is valid for what they have
23 actually spent; however, not all expenditures that are
24 recorded in those accounts should be considered.25 appropriate fbr ratemaking purposes and should perhaps
CSB REPORTING
[phone]
1342 VAUGHN (X)
Staff
.
.
.
16
17
1 not be the responsibility of the ratepayer or the
2 customer which is the purpose of the adjustments.
3 Q Do you believe that your $14.2 million
4 reduction will provide Idaho Power with the opportunity
5 to earn its authorized rate of return when those rates go
6 into effect?
7 A Authorized rate of return is really not my
8 decision and not part of my expertise. I would like to
9 defer to Staff witness Carlock or Staff witness Lobb
10 regarding that.
11 Q Turning to page 12 of your testimony, you
12 recommend leaving plant materials and supplies at 2007
13 levels because you feel that no accurate indicator
14 exists, no accurate predictor, excuse me. I believe
15 that's how you said it on line 9; is that correct?
A Yes, that's correct, that's what I said.
Q Has your opinion changed in light of Idaho
18 Power's third quarter actual plant materials and supplies
19 expenses?
20
21
A No.
Q On pages 47 and 48 of Ms. Smith's rebuttal
22 testimony, she indicated that the third quarter plant
23 materials and supplies expense already exceeded the
24 amount proposed by the Company in its 2008 test year. In
25 light of this fact, in light of these actuals, don't you
CSB REPORTING
[phone]
1343 VAUGHN (X)
Staff
.
.
.
17
1 agree that Staff should adjust its recommendation to
2 remove the Company's proposed $ 6.6 million escalation
3 from rate base?
4 A No, I do not and let me explain. First,
5 this is not an expense. These are materials purchased
6 for future use and they are captured in rate base. The
7 escalation recommended by the Company was 16.38 percent
8 and in light of the current economic turmoil, I don't
9 know that that will in fact be the year' s-end ending
10 balance which is what will be included for the rate base,
11 so because I feel based on what I know, I do not
12 believe -- I'm babbling here. I do not believe that
13 there is any way to accurately predict what an inventory
14 level will be for materials in stores because I believe
15 that purchases are based upon current conditions and I
16 don't believe that that can be predicted.
Q But current expenses through the third
18 quarter are already spent more than what the Company
19 predicted.
20 A These are not expenses. This is inventory
21 and this is what is captured in inventory. This could
22 easily go down and that would be reflected at the
23 year-end balance.
24
25
Q To your knowledge, if the Company does not
have enough inventory, is it allowed to not provide
CSB REPORTING
[phone]
1344 VAUGHN (X)
Staff
.
.
1 service to customers because it needs to order it or more
2 closely manage its inventory?
3 A The Company does need to provide service
4 to its customers, yes.
5 Q So running out of materials and supplies
6 is really not an option for the Company; correct?
7 A It is not; however, I do believe that
8 inventory is something that can be managed cost
9 effectively by the Company.
10 Q And have you heard prior testimony in
11 these proceedings that the Company is still adding
12 customers to its system?
13 A I have heard testimony to that extent,
14 yes.
15 Q Directing your attention to page 14 of
16 your testimony, you state that the current annual AFUDC
17 should be included in rate base for the Hells Canyon
18 relicensing project; is that correct?
19 A I believe that it should be included as a
20 revenue deficiency for the purposes of this rate case,
21 yes.
22 Q You are also recommending that the AFUDC
23 accrual be recalculated to be $2.9 million less than the
24 Company's 2008 AFUDC accrual figure; is that correct?.25 A Yes. In my testimony, that is what I
CSB REPORTING
[phone]
1345 VAUGHN (X)Staff
.1 recommended, yes.
2 Q By doing so, the reduction to rate base
3 under Staff's proposal is less than it would be under the
4 Company's proposal; correct?
5 A It does not affect rate base at all. It
6 is included as a revenue deficiency directly. It is not
7 placed in rate base.
8 Q If the size of the AFUDC accrual, annual
9 accrual, is a concern, which you've stated in your
10 testimony it is, wouldn't, it make sense to use an AFUDC
11 rate that creates a larger offset?
.12
13
14
A The purpose of this AFUDC was to estimate
the 2009 the amount of AFUDC that would be recovered
in rates each month during the year 2009. The best
15 estimate would be essentially the average of as much of
16 the current knowledge as possible using the 2008 known
17 AFUDC rates. I did that for the purposes of this case.
18 I used the rates that I knew at the time which was
19 through August, and when I used that, I calculated that
20 amount. I then calculated the December amount using the
21 average rate for September through December. When I
22 calculated the December amount, I used that to annualize
23 for 2009. I did not compound AFUDC during 2009 because
24 that will be compounded in the regulatory liability, so.25 the effect of that is that ratepayers do not pay interest
CSB REPORTING
[phone]
1346 VAUGHN (X)
Staff
.
.
1 on AFUDC.
2 Q So they don't really offset each other, do
3 they?
4 A Yes, they do.
5 Q Well, one is accruing interest,
6 compounding interest, and one isn't?
7 A No, they both are.
8 Q But you said that yours wasn't.
9 A No, it's accruing interest in the
10 regulatory liability which is where the AFUDC recovered
11 in rates is captured.
12 Q But won't the money in the account for
13 AFUDC continue to compound?
14 A Which account?I'm sorry, could you
15 clarify, please?
16 Q In the regulatory liability account.
17 A It will compound, yes.
18 Q So that rate if you're going to calculate
19 that AFUDC offset needs to compound, also; correct?
20
21
A No, I don't believe so.
Q One of the criticisms that you had of the
22 Company's calculation for AFUDC was using the 2007 full
23 year actual AFUDC rate. How is it more appropriate given
24 the volatility of short-term debt obligations to use less.25 than a full year of AFUDC rates like you did for 2008?
CSB REPORTING
[phone]
1347 VAUGHN (X)Staff
.
.
1 A I did -- we now have ten months and I
2 would be amenable to using the 10 months of known and
3 measurable rates because, again, considering the
4 volatili ty of the current market, I don't know that we
5 can forecast even for November and December what those
6 rates will be.
7 Q So wouldn't an '07 rate be better, then?
8 Well, it's higher and volatility lately has been higher
9 and the November 2008 AFUDC rate is higher, why not use
10 2007 actuals?
11 A I'm sorry, I believe that using the 2008
12 known rates would be better because they are more known
13 and measurable and we are annualizing into 2009.
14 Q So is it your recommendation that the
15 Commission use 2008 actual AFUDC rates for the entire
16 year once they become known and available?
17 A That would be my recommendation.
18 Q Very good. I know we've spent some time
19 talking about how we disagree on how the money is
20 calculated, but just from a larger perspective, isn't it
21 true that this CWIP proposal really reflects a timing
22 issue, that what customers do not pay now will end up in
23 rates later; do you agree?
24.25
A Yes.
Q Moving to pages 18 and 19 of your
CSB REPORTING
[phone]
1348 VAUGHN (X)Staff
.
.
1 testimony, you refer to a $3.3 million credit from the
2 FERC that Idaho Power received in 2006. Did the Company
3 book this credit to income in 2006?
4 A No.
5 Q What do you believe happened?
6 A I believe that it reduced accruals for
7 regulatory expense and it was in fact a credit to
8 regulatory expense which reduced that expense.
9 Q So it was a gain, a benefit to income?
10 A To net income, yes.
11 Q If I understand your testimony correctly,
12 you propose an out-of-period revenue adjustment that will
13 inflate the Company's revenue by more than $ 650,000 for
14 the next five years based upon a non-recurring event that
15 occurred prior to the test year; is that accurate?
16 A This is a regulatory adj ustment and I
17 believe that it should be reflected in rates because the
18 ratepayers or the customers did pay for that over accrual
19 in the years 2003 and 2005 when this was included for
20 ratemaking purposes.
21
22
23
Q So that's a yes?
A No.
Q So you're not recommending increasing
24 you're not recommending that the -- well, by reducing,.25 you're essentially imputing income for the next five
CSB REPORTING
[phone]
1349 VAUGHN (X)Staff
.
.
.
1 years going forward; correct?
2 A No, I am returning to ratepayers over
3 accrual that the Company -- over accrued expenses that
4 the Company credited in 2006. The customers need to -- I
5 believe the customers should have that money returned to
6 them because they paid for expenses that were not
7 actually incurred.
8 Q But this happened outside the test year;
9 correct?
10 A It happened prior to the test year, yes.
11 Q Isn't the purpose of a general rate
12 proceeding to capture what expenses and revenues will be
13 in effect when the new rates go into effect?
14 A Yes.
15 Q What has been the Commission's position on
16 out-of-period non-recurring adjustments to test years?
17 A That when I discussed -- because these
18 were -- this was discussed in the last rate case but not
19 addressed and in consultation with Staff witness Carlock
20 and Lobb, we decided, we decided to bring this forward
21 because since this was included in rates before, this
22 should be returned to the ratepayers in the next
23 li tigated rate case which is this one.
24 Q Well, I understand that that's Staff's
25 position, but are you aware of the Commission's
CSB REPORTING
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1350 VAUGHN (X)Staff
.
.
1 position?
2 A I am not going to address that. I don't
3 feel competent to address that.
4 MS. NORDSTROM: May I approach the
5 witness?
6 COMMISSIONER SMITH: Yes, you may.
7 (Ms. Nordstrom approached the witness.)
8 Q BY MR. KLINE: Ms. Vaughn, I just handed
9 you an excerpt from Commission Order No. 25880 issued in
10 Case No. IPC-E-94-5 which was Idaho Power's 1994 general
11 rate case. Could you please read the highlighted
12 portions on pages 8 and 9 with regard to the recovery of
13 non-recurring expenses from the Pacific Hide clean-up?
14 A "Test year adj ustments to expenses are
15 intended to represent costs the Company will likely incur
16 in the future. when new rates are in effect. It is
17 undisputed that Idaho Power Company will not incur
18 further expenses associated with the Pacific Hide
19 clean-up, and thus that particular expense is
20 non-recurring. and cannot be allowed."
21
22
Q And on page 9?
A "The al ternati ve the Company proposed to
23 recover the $7 million cost of the clean-up, recouping
24 the amount through rates over the next five years, would.25 violate the principle that rates must be prospective and
CSB REPORTING
[phone]
1351 VAUGHN (X)Staff
.
.
.
19
1 may not be used to recoup past losses."
2 Q Is it your recommendation that the
3 Commission authorize recovery of a non-recurring
4 out-of-period adjustment even when it has declined to do
5 so in the past?
6 MR. WARD: Madam Chair.
7 COMMISSIONER SMITH: Mr. Ward.
8 MR. WARD: It's not my witness, but I'm
9 going to obj ect. This is going to call for a legal
10 opinion no matter how you cut it. There are many, many
11 variations on this legal theme of out-of-period expenses
12 being recovered, so I think this is more properly briefed
13 by attorneys if the Company wishes to bring it up rather
14 than having Ms. Vaughn speculate on it.
15 COMMISSIONER SMITH: Ms. Nordstrom.
16 MS. NORDSTROM: I'LL withdraw the
17 question, but I would ask that the Commission take
18 official notice of this Order.
20 Thank you.
COMMISSIONER SMITH: Okay, we can do that.
21
22
MS. NORDSTROM: Thank you.
Q BY MS. NORDSTROM: Ms. Vaughn, to your
23 knowledge, did the Company over-earn or earn more than
24 its authorizeò rate of return in 2006?
25 A That was what I was told, that they did
CSB REPORTING
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1352 VAUGHN (X)Staff
.
.
1 not, in Ms. Smith's rebuttal.
2 Q Are you familiar with Mr. LaMont Keen's
3 Exhibit No.1?
4 A Yes.
5 Q And according to that exhibit, did the
6 Company over-earn in 2006?
7 A No, it did not.
8 MS. NORDSTROM: Thank you. I have no
9 further questions.
10 COMMISSIONER SMITH: Are there any
11 questions from the Commission?
12 COMMISSIONER REDFORD:No
13 COMMISSIONER SMITH: Commissioner
14 Kempton.
15
16 EXAMINATION
17
18 BY COMMISSIONER KEMPTON:
19 Q Madam Chair, Ms. Vaughn, I wonder if you
20 could help me understand a little bit on the CAGR formula
21 development and how you developed your analysis in
22 comparison to the CAGR. The information is provided from
23 2003 to 2007, so there's the data, there's data available
24 across four years before you get into the 2008 period..25 A That's correct.
CSB REPORTING
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1353 VAUGHN (Com)Staff
.
.
.
1 Q And you're saying that in 2008 that
2 al though the third quarter, the September time frame, is
3 in the proj ection with the CAGR matching Idaho Power's
4 expenses or the money that is into inventory, it's
5 speculative in the sense, as you see it, because there's
6 no verification in fact that it would follow the trend
7 line from 2003 to 2007; is that true?
8 A In the cases that I recommended, yes, that
9 is true.
10 Q Did you in fact develop a trend line from
11 2003 to 2007?
12 A For what areas?
13 Q For the materials, for costs of materials
14 and things like that.
15 A For costs of materials as materials
16 expense?
17 Q Yes.
18 A Yes, I did in several cases. There was no
19 trend line. They would go up or go down randomly. Well,
20 it wasn't random. It was dependent on circumstances and
21 I could not see a trend, so I did not feel that it was
22 reasonable to escalate the 2003 and 2007 numbers and
23 escalate those two points into 2008 simply because the
24 data between 2003 and 2007 didn't support the trend.
25 Q And they were so widely dispersed as data
CSB REPORTING
[phone]
1354 VAUGHN (Com)
Staff
.
.
18
19
1 points that there was no correlation that you could
2 establish that was reasonable, even a, say, 50 percent
3 correlation?
4 A That's correct.
5 COMMISSIONER KEMPTON: Well, then,
6 Mrs. Vaughn, I don't know where to go from there. I have
7 no more questions.
8 COMMISSIONER SMITH: Mr. Price, do you
9 have any redirect?
10 . MR. PRI CE : I do.
11
12 REDIRECT EXAMINATION
13
14 BY MR. PRICE:
15 Q Ms. Vaughn, as it pertains to your
16 disallowances on the compound annual growth rate, you did
17 allow for the escalation on some accounts; correct?
A Some account groupings, yes, I did.
Q And Staff also allowed rate base
20 adj ustments based on year-end data through 2008;
21 correct?
22 A They allowed escalated rate base through
23 the end of 2008, yes.
24.25
Q And despite that you had -- despite the
fact that you had eight months of AFUDC rates, you
CSB REPORTING
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1355 VAUGHN (Di)
Staff
.
.
.
1 calculated the amount for the full year; right?
2 A That is correct.
3 Q And to your knowledge, was the FERC credit
4 part of the last case, in testimony in the last case,
5 that was settled prior to this one?
6 A Yes, it was.
7 Q And was your recommendation equivalent to
8 amortization of a deferral that the Company did not
9 request deferral of?
10 A Could you restate, please?
11 Q Was your recommendation in your testimony
12 equivalent to amortization of a deferral that the Company
13 did not request deferral of?
14 A Yes.
15 Q And to make it clear, finally, did the
16 Company's compound annual growth rate method use all of
17 the four years of data?
18
19
20
A No, it did not.
MR. PRICE: That's all I have.
COMMISSIONER SMITH: Thank you very much
21 and thank you for your help.
22 (The witness left the stand.)
23 MR. PRICE: Staff now calls Mr. Keith
24 Hessing.
25
CSB REPORTING
[phone]
1356 VAUGHN (Di)
Staff
.1
2
KEITH HESSING,
produced as a witness at the instance of the Staff,
3 having been first duly sworn, was examined and testified
.
4 as follows:
5
6
7
8 BY MR. PRICE:
9
10
11
12
13 Commission.
Q
A
Q
A
Q
DIRECT EXAMINATION
Please state your name for the record.
My name is Keith Hessing.
And who is your employer?
I'm employed by the Idaho Public Utili ties
And what is your job title?
I'm a Staff engineer.
And on October 24th of this year did you
17 have occasion to prepare written direct and rebuttal
14
15 A
18 testimony for this case?
19
16 Q
A
20 testimony.
21 Q
On October 24th, I think it was my direct
Direct testimony. On December 3rd did you
22 prepare rebuttal testimony?
23
24.25
A
Q
Yes.
And those include Exhibits Nos. 129
through 134 of your direct testimony and Exhibit Nos. 151
CSB REPORTING
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1357 HESSING (Di)
Staff
.
.
17
1 through 153 of your rebuttal testimony?
2 A That is correct.
3 Q Do you have any corrections or additions
4 or adjustments to that testimony?
5 A I have a correction in my direct
6 testimony.
7 Q Can you please explain?
8 A On page 5, line 8, I reference an Exhibit
9 No. 125 and that should be 126.
10 Q Are there any other corrections?
11 A No.
12 Q And if I were to ask you the same
13 questions contained in your prepared written direct and
14 rebuttal testimony today, would your answers still be the
15 same?
16 A They would.
MR. PRICE: I would now move that
18 Mr. Hessing's direct and rebuttal testimony, including
19 Exhibits Nos. 129 through 134 and 151 through 153, be
20 spread upon the hearing record as if read.
21 COMMISSIONER SMITH: If there is no
22 obj ection, we will spread the prefiled direct and
23 rebuttal testimony upon the record as if read and
24 identify Exhibits 129 to 134 and 151 to 153..25
CSB REPORTING
[phone]
1358 HESSING (Di)Staff
1 (The following prefiled direct and.2 rebuttal testimony of Mr.Keith Hessing is spread upon
3 the record.)
4
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CSB REPORTING 1359 HESSING (Di)
(208 )890-5198 Staff
.
.
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Keith D. Hessing and my business
4 address is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utili ties
7 Commission as a Public Utilities Engineer.
8 Q.What is your education and experience
9 background?
10 A.I am a Registered Professional Engineer in the
11 State of Idaho. I received a Bachelor of Science Degree
12 in Civil Engineering from the Uni versi ty of Idaho in
13 1974. Since then, I worked six years for the Idaho
14 Department of Water Resources, and two years for
15 Morrison-Knudsen. I have been continuously employed at
16 the Commission since August 1983.
17 As a member of the Commission Staff, my primary
18 areas of responsibility have been electric utility power
19 supply, cost allocation, rate design and power cost
20 adjustment (PCA) mechanisms.
21 Q.What is the purpose of your testimony in this
22 proceeding?
23 A.I will address the areas of Jurisdictional
24 Separations, Customer Class Cost of Service, Revenue.25 Allocation and the Power Cost Adj ustment (PCA) Mechanism.
Q. Please summarize your testimony.
CASE NO. IPC-E-08-10
10/24/08 1360 HESSING, K (Di) 1
STAFF
.1 A. I accept the Company's Jurisdictional
2 Separations methodology and allocators and the results
3 they produce using Staff adj usted accounting information.
4 Those results are presented in Staff witness Cecily
5 Vaughn's testimony.
6 I accept the Company's proposal to change cost
7 of service methodology to the 3CP /12CP method from the
8 Base Case method that was approved in Case No.
9 IPC-E-03-13. Based on a 1.44 percent overall increase in
10 revenue, I propose that individual class increases be
11 capped at 4.9 percent and that no class receive a
12 decrease. I propose that classes not impacted by the cap.13 or floor be moved to full cost of service.
14 I propose that PCA computational factors, such
15 as base case power supply costs, energy amounts and the
16 jurisdictional energy allocator used in the Company's
17 Power Cost Adjustment (PCA) mechanism, be updated to
18 reflect Staff) s case. I propose that cloud seeding base
19 costs and revenues remain unchanged. I also propose that
20 the load growth adjustment factor used in the PCA remain
21 unchanged while the Commission processes Case No.
22 IPC-E-08-19 which addresses the methodology and proposes
23 a new load growth adjustment factor.
24 JUISDICTIONAL SEPARTIONS.25 Q. What is the purpose of JurisdictionalSeparations?
CASE NO. IPC-E-08-10
10/24/08 1361 HESSING, K (Di) 2
STAFF
.
.
.
1 A.The Jurisdictional Separations process
2 identifies the Idaho jurisdiction's share of total
3 Company costs and revenues and establishes the Idaho
4 jurisdictional revenue requirement.
5 Q.What causes the Idaho jurisdictional revenue
6 requirement to change between rate cases?
7 A.In general there are three items that can cause
8 the revenue requirement to change between rate cases -
9 changes in accounting information, changes in
10 jurisdictional characteristics (demand, energy and
11 customer numbers) and changes in separations methodology.
12 I will briefly discuss each of the three.
13 Account balances change every year. Some cost
14 categories increase and some decrease. Generally, costs
15 increase, but. so do revenues as new customers are added
16 to the system. Other Staff witnesses have testified
17 concerning accounting data and appropriate adjustments.
18 Account balances change between rate cases and those
19 changes appropriately drive changes in the Idaho
20 jurisdictional revenue requirement.
21 Jurisdictional characteristics also change
22 every year. These are things like coincident peak
23 demands, annual energy use and numbers of customers by
24 jurisdiction. The fact that these characteristics change
25 on a relative basis is important because they are used to
separate or
CASE NO. IPC-E-08-10
10/24/08 1362 HESSING, K (Di) 3
STAFF
.
.
.
1 allocate total Company costs to the various
2 jurisdictions. Staff Exhibit No. 129 demonstrates the
3 changes that have occurred in these characteristics over
4 the Company's four most recent general rate cases
5 including this one. For demonstration purposes only one
6 demand, one energy and one customer allocator are shown.
7 Each category has one or more other allocators that are
8 also used in the jurisdictional separations study. It is
9 significant that while energy and peak loads have grown
10 along with total system costs, the Idaho jurisdiction's
11 share of the Company's costs has changed very little
12 since the Company's last case. This can be observed by
13 the change from the last rate case to this rate case in
14 the major demand and energy allocators. The D10
15 allocator has not change from .950 and the E10 allocator
16 grew from .947 to .948. In other words, the Idaho
17 jurisdiction was allocated 95.0% of demand related costs
18 in the last rate case and in this case Idaho ratepayers
19 would again be allocated 95.0% of system demand related
20 costs.
21 As pointed out in Company testimony,
22 jurisdictional separations methodology has remained
23 largely unchanged for a very long period of time. When
24 Jurisdictional Separations methodology does not change
25 and major allocators change little, the accounting data
drives the changes in the Idaho Jurisdictional Revenue
CASE NO. IPC-E-08-10
10/24/08 1363 HESSING, K (Di) 4
STAFF
.
.
.
1 Requirement.
2 Q.Do you accept Idaho Power's Jurisdictional
3 Separations study?
4 A.I accept the methodology and allocation factors
5 proposed by the Company; however, other Staff witnesses
6 have proposed adj ustments to the accounting data and the
7 Return on Equity. Staff's Jurisdictional Separations
8 resul ts are presented as Staff Exhibit No. 126 to Staff
9 wi tness Cecily Vaughn's testimony. Staff proposes
10 an Idaho Jurisdictional revenue requirement of
11 $682,850,888 that requires an overall rate increase of
12 $9,681,348 or 1.44 percent
13 CLASS COST OF SERVICE
14 Q.What is the purpose of a Customer Class Cost of
15 Service Study?
16 A.A Customer Class Cost of Service Study divides
17 the Idaho Jurisdictional Revenue Requirement that results
18 from the Jurisdictional Separations Study among the
19 various Idaho rate classes.
20 The process is generally the same as previously
21 described in the Jurisdictional Separations discussion.
22 Costs are identified as energy, demand or customer
23 related and each rate class's percentage share of energy
24 use, demand use or number of customers is applied to the
25 costs to divide them among the various rate classes or
CASE NO. IPC-E-08-10
10/24/08 1364 HESSING, K (Di) 5
STAFF
.
.
1 rate schedules.
2 Q.Is the Company proposing to change the Cost of
3 Service method most recently accepted by the Commission?
4 A.Yes. In the IPC-E-03-13 general rate case the
5 Commission used a method that the Company calls "Base
6 Case" as a guide in allocating costs to the various rate
7 classes. In this case the Company is proposing a change
8 to a method that the Company calls "3CP /12CP" . The
9 IPC-E-05-28 general rate case that followed the
10 IPC-E-03-13 case was a settled case that spread costs to
11 classes on a uniform percentage basis and, therefore, did
12 not use cost of service results. Case No. IPC-E-07-8
13 that followed the 05-28 case was also a settled case that
14 used no specific cost of service study to allocate the
15 Idaho jurisdictional revenue requirement to customer
16 classes.
17 Q.What are the differences between the Base Case
18 method and 3CP/12CP method?
19 A.The differences are in the classification and
20 allocation of Production Plant. The Base Case method
.
21 classifies all production plant investment, except the
22 Company's gas fired peaking unit investment, as energy
23 and demand related based on the Idaho jurisdictional load
24 factor. The Idaho jurisdictional load factor is 59.38%..25 Therefore, approximately 59% of these costs were
CASE NO. IPC-E-08-10
10/24/08 1365 HESSING, K (Di) 6
STAFF
1 classified as energy related and allocated using an.2 energy allocator,
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1366 HESSING,K (Di)6a10/24/08 STAFF
.1 and approximately 41% were classified as demand related
2 and allocated using a demand allocator. Gas fired
3 peaking unit investment was classified as 100% demand
4 related. Both energy and demand allocators were based on
5 twel ve months of data weighted by the marginal cost of
6 energy or demand, respectively, from the Company's
7 marginal cost study.
8 The proposed 3CP /12CP cost of service method
9 classifies base load and intermediate load plant
10 investment, hydro and thermal generating resources, as
11 energy related and demand related based on the Idaho
12 jurisdictional load factor just as the Base Case method.13 does. The Company's peaking resource investment in
14 natural gas fired plant is classified as 100% demand
15 related as in the Base Case study. However, different
16 demand allocators are applied. Demand related peaking
17 uni t investment is allocated using an unweighted 3CP
18 allocator based on the Company's three summer peak months
19 of June, July and August. Other demand related
20 production investment associated with serving base and
21 intermediate load is allocated using an unweighted 12CP
22 allocator. The energy related portion of base and
23 intermediate load production plant investment is
24 allocated based on marginal cost weighted class energy.25 use.
CASE NO. IPC-E-08-10
10/24/08 1367 HESSING, K (Di) 7
STAFF
1 Q.What other changes in cost of service.2 methodology from IPC-E-03-13 is the Company proposing?
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1368 HESSING,K (Di)7a10/24/08 STAFF
.
.
.
1 A.The Company is proposing to classify Account
2 555 - Purchased Power costs (market purchases and PURPA
3 purchases) as energy and demand related based on the
4 system load factor. The IPC-E-03-13 rate case classified
5 purchased power costs as almost entirely energy related.
6 Another cost of service change that has
7 occurred since the 03-13 case is a change in the way
8 coincident peak demand allocators are determined. The
9 03-13 cost of service study used actual test year
10 coincident peak demands to determine the allocation
11 factor. Following that case workshops were held to
12 discuss a number of cost of service issues. As part of
13 that process the parties agreed to use a 5-year median
14 coincident peak demand to normalize the allocation
15 factor. The Company has applied this methodology in all
16 cases since the 03-13 case.
17 Q.What is the difference in study results between
18 the 03-13 Base Case method and the 3CP/12 CP method
19 proposed by the Company in this case?
20 A.Company witness Tatum presents the results of
21 three cost of. service studies that he prepared in Company
22 Exhibi t No. 69. The results of the Base Case study and
23 the 3CP /12CP study are included and show similar trends.
24
25
Q.Which method do you propose the Commission
accept?
A.I recommend that the Commission accept the
CASE NO. IPC-E-08-10
10/24/08 1369 HESSING, K (Di) 8
STAFF
.
.
.
17
1 3CP /12CP method proposed by the Company.
2 Q.Does your testimony include an exhibit showing
3 Cost of Service results using the 3CP /12CP method applied
4 to the Idaho jurisdictional revenue requirement proposed
5 by Staff?
6 A.Yes. Staff Exhibit No. 130 shows those
7 results.
8 Q.Do your results show the same general pattern
9 as the results presented by the Company in Exhibit No.
10 69?
11 A.Yes. The special contract customers, Micron,
12 Simplot and DOE, along with the Large Power customers
13 served under Schedule 19 and the Irrigation class show a
14 need for a much higher than average increase if their
15 rates are to be set at full cost of service. Residential
16 customers are' shown to deserve a decrease.
Q.Are these results similar to cost of service
18 resul ts from the IPC-E-03-13 case?
A.No. Cost of service results did not indicate19
20 higher than average cost increases for the high load
21 factor customer classes in that case.
22 Q.How do you explain the significant changes in
23 cost of service results that have occurred since the
24 IPC-E-03-13 case?
A.There are a number of circumstances that have25
CASE NO. IPC-E-08-10
10/24/08 1370 HESSING, K (Di) 9
STAFF
1 caused changes in cost of service results.Load growth,.2 substantially in the residential class,has occurred in
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1371 HESSING,K (Di)9a10/24/08 STAFF
.
.
.
1 record amounts. The cost of power supply to meet the
2 growing load, at approximately 6ç/kWh, has been much
3 higher than it used to be. Under cost of service
4 methodology a disproportionately larger share of all
5 costs, old and new, are allocated to the residential
6 class because the residential classes percentage share of
7 energy, peak demand and customers has increased.A mix
8 of old and new costs is also allocated to all other
9 classes even if they experienced no load growth. No
10 customer class is entitled to rates based on a
11 grandfathered. share of old costs. In the cost of service
12 model the residential class received credit for all of
13
14
the revenue from its load growth at near 6ç/kWh and a
portion of the production cost increases at about the
15 same rate. In the cost of service study the increased
16 revenues offset the increased costs and the Residential
17 Class is shown to deserve an increase below the Idaho
18 Jurisdictional average, or even a decrease as
19 demonstrated in Staff's results.
20 High load factor customer groups are situated
21 differently. They are allocated a reduced portion of all
22 costs, old and new, and have little or no new revenue to
23 offset the new costs. The new costs more than offset the
24 cost reduction due to the decrease in the allocation
25 percentages and without additional revenue rates go up.
Therefore, cost of service results indicate increases
CASE NO. IPC-E-08-10
10/24/08 1372 HESSING, K (Di) 10
STAFF
.
.
.
1 higher than the average.
2 Even if there were substantial growth in the
3 high load factor classes, their revenue at about 3ç/kWh
4 would not offset marginal power supply costs at about
5 6ç /kWh. The size of the increase may be decreased, but
6 there would still be an above average increase for high
7 load factor customers.
8 Q.Does your explanation explain cost of service
9 trends since the IPC-E-03-13 case?
10 A.There are many moving parts in a cost of
11 service study. The explanation that I have provided
12 addresses the cost trends for the large customer classes.
13 There are many other factors that are also driving
14 changes in cost of service results such as differences in
15 methodology, allocation factors, distribution and
16 transmission costs, etc.
17 The explanation that I have provided addresses
18 the trend of disproportionate increases to the high load
19 factor classes observed in the Company's three most
20 recent general rate case filings - IPC-E-05-28,
21 IPC-E-07-8 and the current case.
22 Q.Is there any reason to believe that the trend
23 will not continue?
24
25
A.No. It is largely driven by the high marginal
power supply cost of serving new load. I expect load to
CASE NO. IPC-E-08-10
10/24/08 1373 HESSING, K (Di) 11
STAFF
.
.
.
1 continue to grow and marginal costs to remain
2 significantly higher than high load factor customer
3 rates.
4 REVENU ALLOCATION
5 Q.How do you propose the Commission use the Cost
6 of Service results contained in Staff Exhibit No. 130?
7 A.In general, I propose that Cost of Service
8 resul ts be used as a guide in establishing class revenue
9 requirements for the various rate classes. I view Cost
10 of Service results as an imprecise science that is
11 appropriately used as a starting point in revenue
12 allocation.
13 Q. What customer class allocation of the Idaho
14 Jurisdictional revenue requirement do you recommend?
15 A.Staff's Cost of Service results are based on an
16 average Idaho' jurisdictional retail rate increase of 1.44
17 percent. However, some individual class increases vary
18 substantially from the average. For this reason I
19 recommend that cost of service results not be strictly
20 followed, but. that the results be used as a guide in
21 establishing class revenue requirements.
22 It is my recommendation that no class receive a
23 rate decrease and that increases be capped at 4.9
24 percent. All. customer classes in between would be moved
25 to full cost of service. This approach diminishes rate
shock and moves all classes toward cost of service.
CASE NO. IPC-E-08-10
10/24/08 1374 HESSING, K (Di) 12
STAFF
.
.
1 Q. Have you prepared an exhibit that shows the
2 resul ts of your proposal?
3 A.Yes. I have prepared Staff Exhibit No. 131.
4 As you can see, Schedules 19, 24, 42 and the special
5 contract customer schedules would receive the maximum
6 increase of 4~9%. Schedules 1, 7, 15, 40 and 41 would
7 recei ve no increase or decrease. Schedule 9 would be
8 moved to full cost of service.
9 Q.Have you prepared an exhibit that compares your
10 Revenue Allocation proposal to Idaho Power's Revenue
11 Allocation proposal?
12 A.Yes. Staff Exhibit No. 132 makes that
13 comparison.
14 POWER COST ADJUSTMNT (PCA) MECHAISM
15 Q.What Power Cost Adjustment (PCA) components are
16 established in a general rate case?
17 A.Company Exhibit No. 51 identifies most of the
18 "PCA Computational Factors" that are established in a
19 general rate case. The Company proposes that the PCA
20 computational factors be updated to the 2008 test year
21 leveL.
22 Q.Have you prepared a similar exhibit that
23 presents your' quantification of appropriate PCA
24 computational factors?.25 A.Yes, I have. Staff Exhibit No. 133 contains
CASE NO. IPC-E-08-10
10/24/08 1375 HESSING, K (Di) 13
STAFF
.
.
.
1 the information in the Company's proposal from Company
2 Exhibi t No. 51 along with my proposal. My proposal is
3 based on Staff's case.
4 Q.Please discuss the factors presented in your
5 proposal to the extent that they differ from the
6 Company's proposal.
7 A.The Company and Staff proposals for Normalized
8 Power Supply Expense differ because the expense amounts
9 come from the AURORA power supply model and Staff assumed
10 a different natural gas price input to that model than
11 the Company did. This difference is discussed in more
12 detail in Statf witness Rick Sterling's testimony. Also
13 the Staff proposes to continue the use of the Commission
14 ordered base revenue and cost amounts for cloud seeding.
15 These differences are also the cause of the difference in
16 the Normalized Base PCA Rate that is calculated using the
17 Normalized Power Supply Expense and Cloud Seeding expense
18 and revenue.
19 Q.Are there other PCA computational factors that
20 are normally established in a general rate case?
21 A.Yes. The load growth adjustment rate, also
22 called the Expense Adjustment Rate for Growth (EARG), and
23 the forecast equation.
24
25
Q.Please discuss your recommendation for the load
growth adj ustment rate.
CASE NO. IPC-E-08-10
10/24/08 1376 HESSING, K (Di) 14
STAFF
.
.
1 A.In the Company's most recent general rate case,
2 the IPC-E-07-8 case, the Commission accepted a settlement
3 stipulation. In that stipulation, the load growth
4 adjustment rate was based on a 2007 marginal cost
5 calculation of $62. 79/MWh and was applied to one-half of
6 the load growth. I propose that the currently approved
7 rate continue to be used and that it continue to be
8 applied to one-half the load growth.
9 Q.Have the Company and Staff calculated new
10 marginal costs that could be used to update the load
11 growth adjustment rate?
12 A.Yes. Company Exhibit No. 50 shows a 2008
13 marginal power supply cost of $56.48 per MWh. Staff
14 Exhibi t No. 134 shows a 2008 marginal power supply cost
15 of $54.07 per MWh. The difference is caused by different
16 assumptions in monthly natural gas prices.
17 Q.Why are you not proposing to update the load
18 growth adjustment rate?
19 A.The Commission currently has Case No.
20 IPC-E-08-19 before it which contains a stipulated
21 settlement that changes the computational method and the
22 rate. I believe that it is appropriate for load growth
23 adjustment rate changes to be considered in that case.
24.25
Q.You said that the PCA Forecast equation is also
normally updated in a general rate case. Please discuss
CASE NO. IPC-E-08-10
10/24/08 1377 HESSING, K (Di) 15
STAFF
.
.
.
18
19
20
21
22
23
24
25
1 the PCA forecast equation.
2 A.The Company filed an updated PCA forecast
3 equation. The calculations are shown on Company Exhibit
4 No. 49. The Staff has not prepared such a calculation
5 because Case No. IPC-E-08-19 also proposes to change
6 forecast methodology. If the Commission does not accept
7 the settlement proposed in that case, an updated
8 regression formula based on Commission approved power
9 supply costs could be prepared at that time.
10 Q.Does this conclude your direct testimony in
11 this proceeding?
12 A.Yes, it does.
13
14
15
16
17
CASE NO. IPC-E-08-10
10/24/08 1378 HESSING, K (Di) 16
STAFF
.
.
.
16
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Keith D. Hessing and my business
4 address is 472 W. Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utili ties
7 Commission as a Public Utilities Engineer.
8 Q.Are you the same Keith Hessing that previously
9 submi tted testimony in this proceeding?
10 A.Yes, I am.
11 Q.What is the purpose of your rebuttal testimony?
12 A.I w~ll address portions of the testimonies of
13 Mr. Anthony Yankel, Dr. Dennis Peseau, Dr. Don Reading,
14 and Dr. Dennis Goins.
15 Load Growth
Q.Mr. Yankel discusses load growth and its cost
17 of service impacts on the irrigation class in his direct
18 testimony. Please present your views concerning load
19 growth and class cost of service studies.
20 A.The cost of providing service to new customers
21 is almost always higher than the embedded cost of serving
22 existing customers upon which rates are based. Once the
23 costs of providing service to a new customer are booked
24 into the Company's accounting records, those costs are
25 mixed with other plant costs accumulated over many years
that are in
CASE NO. IPC-E-08-10
10/24/08 1379 HESSING, K (Reb) 1
STAFF
.
.
1 various stages of depreciation. Some of the costs are
2 growth related and others are associated with
3 replacements or relocations. Once current load growth
4 costs are mixed with all of the other costs in the
5 Company's accounting system, it is not possible to apply
6 any class characteristic that accurately or even
7 approximately separates growth related costs, for a given
8 time period, from the other costs in that account. All
9 costs in the accounts are blended or averaged. Rates
10 based on such an attempt to separate growth related costs
11 from other costs are probably grossly inaccurate and
12 cannot be considered fair or reasonable.
13 Q. Does the Company continue to incur costs to
14 serve the irrigation class even though its load may not
15 be growing?
16 A.Absolutely. Poles, wires, transformers and
i 7 generation equipment will fail or become obsolete and
18 require replacement. These costs will be incurred at
19 current levels and be booked to the same accounts that
20 all other like costs have been booked to over time.
21 These costs are higher than those recovered through
22 current rates but such investments are required to
23 continue to provide adequate service to existing
24 customers. To the extent that a customer class, such as.25 the irrigators with no growing load, do not pay these
costs other customers will.
CASE NO. IPC-E-08-10
10/24/08 1380 HESSING, K (Reb) 2
STAFF
1 Q. How does Mr. Yankel propose to weight the Base.2 Case cost of service method to incorporate load growth?
3 A.The method proposed by Mr. Yankel uses a
4 10-year class load growth projection from Idaho Power's
5 Integrated Resource Plan (IRP) to weight demand and
6 energy allocators.
7 Q.Is this an appropriate methodology to allocate
8 embedded costs?
9 A.Not in my opinion. No embedded cost of service
10 study included in the NARUC Electric Utility Cost
11 Allocation Manual allocates growth costs based on the
12 future growth of customer classes. When challenged to.13 find such a method in the cost of service workshops held
14 in Case No. IPC-E-04-23, the Company's search discovered
15 no such methodology. Neither did any other party.
16 When growth occurs in any customer class one or
17 more of the allocation factors based on energy use,
18 contribution to system peak or number of customers
19 increase in value and thus cause the allocation of more
20 costs to that class. In other words all costs are
21 averaged and allocated based on class usage
22 characteristics. Cost allocations increase
23 disproportionately for growing classes but do not
24 approximate the growth related costs incurred by the.25 class. All of the cost of service studies submitted in
CASE NO. IPC-E-08-10
10/24/08 1381 HESSING, K (Reb) 3
STAFF
1 this case allocate costs in this way.This is the.2 extent,under existing embedded cost of service
3 methodologies,to which
4
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11
12
13.14
15
16
17
18
19
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22
23
24.25
CASE NO.IPC-E-08-10 1382 HESSING,K (Reb)3a10/24/08 STAFF
.
.
.
1 growth related costs can be allocated to the cost causer.
2 Q.You have stated that it is your opinion that
3 the high cost of load growth cannot be accurately
4 allocated to the class in which the load growth occurred
5 once the costs are booked to the Company's accounts. Can
6 load growth costs be assessed before the costs are booked
7 to the Company's accounts?
8 A.Yes, to a limited degree. New connections can
9 be required to make a contribution to offset the
10 Company's costs prior to connection. This is currently
11 being done through the Company's Line Extension Rule.
12 Generally, the contribution only offsets a portion of
13 distribution investment. In some special circumstances a
14 portion of the cost of transmission is contributed. No
15 Generation costs are contributed. Past efforts by the
16 Commission to impose growth related fees on new customers
17 to recover generation or production costs have been
18 rej ected by the Idaho Supreme Court. The courts have
19 restricted the manner in which common costs can be
20 collected from customers based on a new customer, old
21 customer distinction. How much, if any, of the growth
22 related common costs can be recovered from new customers
23 and whether they can be recovered through up front
24 contributions or monthly electric rates is unclear.
25 However, it is clear to me that it is just as inequitable
to specifically allocate growth related costs to existing
CASE NO. IPC-E-08-10
10/24/08 1383 HESSING, K (Reb) 4
STAFF
.
.
.
1 customers in a customer class with growing load as it is
2 to assess those costs to existing customers in a class
3 where load is not growing.
4 Q.Are there customers other than irrigation
5 customers on Idaho Power's system whose loads are not
6 growing?
7 A.Yes.
8 Q.Is it fair to protect irrigation customers from
9 what I will call the spill-over costs of load growth
10 while other non-growing customers in other classes are
11 required to pay them?
12 A.No.
13 Load Factor Classification
14 Q. Would you summarize the variety of different
15 ways the parties in this case have proposed to classify
16 base load hydro and thermal production plant to demand
1 7 and energy?
A.Yes. The Company and Commission Staff18
19 recommend that hydro and thermal plant costs be split and
20 classified as energy and demand related based on the
21 Idaho Jurisdictional load factor. In this case the load
22 factor is 59.38%. The proposed methodology would
23 classify approximately 59% of these plant costs as energy
24 related and approximately 41% as demand related.
25 Dr. Peseau recommends that all hydro and
thermal production plant be classified as demand related.
CASE NO. IPC-E-08-10
10/24/08 1384 HESSING, K (Reb) 5
STAFF
1 Dr. Reading agrees with the Company and Staff.2 that the load factor split should be employed to classify
3 thermal production plant but he proposes a 75% demand/25%
4 energy classification of hydro production plant. This
5 classification is based on PacifiCorp' s demand/energy
6 classification used in its recent rate cases.
7 Mr. Yankel uses the Company-proposed load
8 factor split in his weighted 12CP method.
9 After stating his preference that all
10 production pl~nt be classified as demand related, Dr.
11 Goins proposes two weighted 12CP studies for Commission
12 consideration. His Exhibit No. 610 study splits thermal.13 and hydro production plant by the load factor as the
14 Company proposed and his Exhibit No. 611 study proposes
15 that hydro and thermal production plant be classified as
16 42.9% energy related and 57.1% demand related.
17 Q.Why does the Staff support the Company in its
18 use of the load factor classification of hydro and
19 thermal production plant?
20 A.First of all it is the method last accepted by
21 the Commission in the IPC-E-03-13 case. In addition to
22 that, the method is self adjusting to address changes in
23 system generation requirements.
24 Q.Please explain how the load factor.25 classification method is self adjusting?
CASE NO. IPC-E-08-10
10/24/08 1385 HESSING, K (Reb) 6
STAFF
1.A. The load factor is a descriptive characteristic
2 of the system. It is average demand, or energy, divided
3 by peak demand. It is the specific relationship between
4 energy and peak demand.
5 Over time energy and peak demand relationships
6 change, new customers are added, some drop off the system
7 and others change their peak or energy characteristics
8 ei ther on their own or as they are encouraged to do
9 through programs designed to encourage changes such as
10 the Peak Rewards program for irrigators or the Cool
11 Credi ts program for residential customers. As the
12 relationship between peak and energy changes so does the.13 system load factor. Dr. Peseau points out in his
14 testimony that in Idaho Power's 1994 general rate case
15 (IPC-E-94-5) the load factor was almost 68%. In that
16 case approximately 68% of production plant costs were
17 classified as energy related and approximately 32% were
18 classified as demand related. In this case the load
19 factor is approximately 59%. Therefore, hydro and
20 thermal production costs are being classified as
21 approximately 59% energy and 41% demand. Higher demand
22 percentages benefit high load factor customers. The load
23 factor changed as system characteristics changed and
24 energy and demand classifications were automatically.25 adjusted.
CASE NO. IPC-E-08-10
10/24/08 1386 HESSING, K (Reb) 7
STAFF
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.
.
16
17
18
19
20
21
22
23
24
25
1 Q.What would be the result of applying the load
2 factor classification methodology to a hypothetical
3 system
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10
11
12
13
14
15
CASE NO. IPC-E-08-10
10/24/08 1387 HESSING, K (Reb) 7a
STAFF
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1 wi th a 100% annual load factor?
2 A.The load factor classification method would
3 classify 100% of production plant as energy related.
4 Economics would dictate that the plant that served such a
5 system would be base load production plant constructed to
6 provide low cost energy.
7 Q.What would be the result of applying the load
8 factor classification methodology to a hypothetical
9 system with a near 0% annual load factor?
10 A.The load factor classification method would
11 classify nearly 100% of production plant as demand
12 related. A system with a very low load factor would
13 exhibi t one or more sharp short duration peak demands
14 over the course of the year and produce very small
15 amounts of energy. Economics would dictate that the
16 plant that served such a system would be a peaking plant
17 (or plants) constructed to provide low cost capacity or
18 demand.
19 The load factor classification method is self
20 adjusting and properly classifies costs, even at the
21 limits.
22 Q.What is Dr. Peseau' s position in this case
23 concerning growth and the Company's load factor?
24
25
A.In this case it is Dr. Peseau' s position that
incorrect price signals are being sent to growing classes
CASE NO. IPC-E-08-10
10/24/08 1388 HESSING, K (Reb) 8
STAFF
1 and that this is causing a "steady decline in Idaho.2 Power's load factor"(pg.41) .He implies that this
3 justifies an
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13.14
15
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17
18
19
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24.25
CASE NO.IPC-E-08-10 1389 HESSING,K (Reb)8a10/24/08 STAFF
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20
21
22
23
24
25
1 increased allocation of costs to the growing residential
2 class, an increase that justifies a significant change in
3 cost of service methodology. He supports his position
4 citing a 1994 load factor of 68% and a load factor in
5 this case of 59%.
6 Q.Do you agree with his position?
7 A.No. He is correct that the 1994 load factor
8 was approximately 68% and that it is currently
9 approximately 59%. However, the load factor change has
10 nothing to do with load growth and everything to do with
11 the loss of load. In 2001 the system lost the load of
12 its single largest customer, FMC Corporation. FMC was
13 also a high load factor customer. When FMC's load was
14 lost the Company's load factor declined. This is
15 evidenced by the Company's load factor in its 2003
16 general rate case which was 55.26%. Since that point in
17 time the Company's load factor has continued to improve
18 to its current level of 59.38% as shown in the table
19 below.
Case No.Load Factor
IPC-E-94-5 67.57%
IPC-E-03-13 55.26%
IPC-E-05-28 58.45%
IPC-E-07-8 58.53%
IPC-E-08-10 59.38%
CASE NO. IPC-E-08-10
10/24/08 1390 HESSING, K (Reb) 9
STAFF
.
.
.
13
14
1 There has been no decline in load factor
2 associated with system growth and therefore, no cost of
3 service methodology change can be justified on this
4 basis.
5 Q.Dr. Reading proposes that hydro production
6 plant be classified as 75% demand/25% energy at least
7 partially because that is the accepted classification in
8 Rocky Mountain Power's cost of service methodology. Do
9 you believe that the Commission should accept his
10 recommendation?
11 A.No. This classification mirrors the
12 jurisdictional separations methodology agreed to by
parties in PacifiCorp' s multi-state process (MSP). The
negotiated settlement in the MSP was not solely based on
15 cost of service principles.
16 Idaho's other major electric utility, Avista,
17 employs a cla~sification methodology that has been
18 accepted by the Commission for at least 25 years that is
19 on the opposite end of the spectrum from Rocky Mountain
20 Power. Avista uses an "Equivalent Peaker Method" as
21 identified in the NARUC Electric Utility Cost Allocation
22 Manual (pg. 52). Avista calls its methodology the Peak
23 Credit method. The Peak Credit method assumes that if a
24 utili ty needs capacity to meet demand, it builds a simple
25 cycle combustion turbine. To the extent that it pays more
CASE NO. IPC-E-08-10
10/24/08 1391 HESSING, K (Reb) 10
STAFF
1 to build or buy anything other than a combustion turbine,.2 it incurs those costs to
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9
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12
13..14
15
16
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18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1392 HESSING,K (Reb)lOa10/24/08 STAFF
.
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1 supply energy. The Company uses a ratio of the two costs
2 to classify base load plant to capacity and energy. In
3 its most recent filing, Case No. AVU-E-08-1, Avista' s
4 method classified 73.18% of hydro plant as energy related
5 and 66.43% of thermal plant as energy related. Of course
6 the remaining percentages of both were classified as
7 demand related. The load factor classification of demand
8 and energy as proposed by the Company and Staff in this
9 case is not extreme but middle ground.
10 Coincident Peak Methodology
11 Q.Dr. Reading proposes a change in the way that
12 coincident peaks are established in the development of
13 allocation factors used in the cost of service study. Do
14 you agree with his proposed change?
15 A.Yes. I believe that the current methodology
16 developed in 2004 that establishes coincident peak
17 demands that are used in developing class cost of service
18 allocation factors has unintended consequences.
19 Following Idaho Power's IPC-E-03-13 general
20 rate case the Commission required the parties to hold
21 workshops to discuss cost of service issues. A case was
22 opened, the IPC-E-04-23 case, and a report with
23 recommendations was filed with the Commission. One of
24 the recommendations accepted by the parties was designed
25 to weather normalize coincident peaks instead of using
actual coincident peaks
CASE NO. IPC-E-08-10
10/24/08 1393 HESSING, K (Reb) 11
STAFF
.
.
.
1 from the test year. The normalization technique was to
2 use the median value from 5 years of monthly data for
3 each month for each class. The logic was that if weather
4 caused higher than normal or lower than normal coincident
5 peaks over a 5-year period, the middle value would be the
6 most normal. My recollection of those workshops is that
7 there was no discussion of other non-weather related
8 factors that might cause systematic changes in coincident
9 peaks. Such systematic changes would build (or decline)
10 over a 5-year period and, in a normal weather situation,
11 would result in a 3-year-old median being selected.
12 Systematic changes can increase or decrease class
13 coincident peaks. On demand electric hot water
14 appliances could work to increase demands while the
15 irrigation peak rewards program and the residential cool
16 credits program work to reduce class peaks.
17 Q.Does the Company's filing recognize this
18 problem?
19 A.Yes, to some extent. The Company proposes
20 adjustments to irrigation peaks to include peak
21 reductions due to the peak rewards program for which the
22 irrigation class was not getting full credit.
23 Q.What methodology do you propose to be used in
24 the place of the 5-year median methodology?
25 A.I accept Dr. Reading's proposal to return to
CASE NO. IPC-E-08-10
10/24/08 1394 HESSING, K (Reb) 12
STAFF
1 the use of coincident peak data based on the single most.2 recent year.
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6 /
7
8 /
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10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1395 HESSING,K (Reb)12a10/24/08 STAFF
.
.
1 Q.Did you rerun the Staff cost of service
2 recommendation using the proposed methodology?
3 A.Yes. Those results are shown on Exhibit No.
4 151.
5 Q.Does this change the revenue allocation
6 proposal that you made in your direct testimony?
7 A.Yes, it changes my original proposal. My new
8 proposal is shown on Exhibit No. 152. Under my new
9 proposal the floor remains at no decrease, Schedule 9
10 moves to full cost of service with a 1.75% increase and
11 all other classes who would receive increases have their
12 increases capped at 3.89%.
13 Q. Have you prepared an exhibit that shows the
14 Company's proposal, your original proposal and your
15 proposal on rebuttal?
16 A.Yes. Exhibit No. 153 shows those results.
17 12CP Methodology
18 Q.In his testimony on page 43, Dr. Peseau
19 discusses concerns he has with the Company's 3CP/12CP
20 methodology. He says that classifying steam production
21 plant as energy and demand related and then applying a
22 12CP demand allocator to the demand portion is a "double
23 allocation of baseload steam production to energy". He
24 says that a 12CP demand allocator is essentially an.25 energy allocator. Please respond.
CASE NO. IPC-E-08-10
10/24/08 1396 HESSING, K (Reb) 13
STAFF
1 A.A 12CP demand allocator is composed of a.2 utility's 12 monthly coincident peak demands.It is
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13.14
15
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17
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24.25
CASE NO.IPC-E-08-10 1397 HESSING,K (Reb)13a10/24/08 STAFF
.
.
.
1 commonly used to allocate demand related production costs
2 even when a portion of those costs are classified as
3 energy related. This is exactly the case with Avista and
4 Rocky Mountain Power here in Idaho. The classification/
5 allocation method applied to steam production plant by
6 the Company in this case is not a double allocation to
7 energy and in fact is common practice.
8 Q.Why should base load capacity related costs be
9 allocated using a 12CP allocator in this case?
10 A.Cap~ci ty is required and has value in all
11 months. Idaho Power is a dual peaking utility with a
12 summer and winter peak. The off peak, spring and fall
13 shoulder months, provide the opportunity for the Company
14 to take plants down for necessary scheduled maintenance.
15 This circumstance can produce situations in shoulder
16 months where available capacity is as important as it is
17 in peak load months.
18 Q.Has the Idaho Commission ever accepted a Cost
19 of Service study in an Idaho Power rate case that did not
20 include some measure of coincident peaks in all 12 months
21 of the year in the development of coincident peak
22 allocators?
23 A.No. Even though there have been other
24 proposals, the Commission has always used a 12CP
25 methodology to allocate base load production costs.
CASE NO. IPC-E-08-10
10/24/08 1398 HESSING, K (Reb) 14
STAFF
1 Weighted 12CP methods have often weighted some months as.2 zero.When the Commission accepted such weighting,it
3 averaged the zero
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7 /
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11
12.13
14
15
16
17
18
19
20
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22
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24.25
CASE NO.IPC-E-08-10 1399 HESSING,K (Reb)14a10/24/08 STAFF
.
.
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1 weighted result with a 12CP allocator that included a
2 coincident peak demand value for all months. I believe
3 that the Commission's decisions are in recognition of the
4 fact that capacity has value in all months.
5 Q.Dr. Peseau says that the 12CP "Base Case"
6 method included in the Company's filing in this case is
7 not the method used as the starting point for cost
8 allocation in Case No. IPC-E-03-13. Please comment.
9 A.The Base Case method presented by the Company
10 in this case is substantially the method used by the
11 Commission as the starting point for cost allocation in
12 the IPC-E-03-13 case. There are two differences. The
13 Base Case method filed by the Company in this case used
14 coincident peaks based on a five-year median value
15 instead of the most recent year. I discussed this
16 difference earlier in my testimony. The other difference
17 is in the number of zero weighted months. In the
18 IPC-E-03-13 case as well as the Base Case cost of service
19 in this case,' zero weighted months are averaged with
20 non-zero coincident peaks to obtain the final allocator
21 used in the cost of service model. The cost shifts to
22 high load factor customers due to changes in Base Case
23 methodology that Dr. Peseau discusses in his testimony
24 simply did not occur.
25 Q.Since the Company and most parties to this case
CASE NO. IPC-E-08-10
10/24/08 1400 HESSING, K (Reb) 15
STAFF
1 are supporting some version of 3CP /12CP methodology, why.2 is
3
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12.13
14
15
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17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1401 HESSING, K (Reb)15a10/24/08 STAFF
.
.
1 it important to establish that the Base Case methodology
2 presented by the Company in this case is substantially
3 the same methodology used by the Commission as the
4 revenue allocation starting point in the IPC-E-03-13
5 case?
6 A.If it is substantially the same methodology
7 last used by the Commission, then the proposed change to
8 3CP /12CP methodology does not cause a radical change in
9 resul ts. This is demonstrated on Company Exhibit No. 69
10 where the two results are compared. Since both methods
11 show large increases to high load factor customers, the
12 proposed change in methodology is not driving those
13 results.
14 Seasonal Shapes included in Allocation Factors
15 Q.On page 38 of his direct testimony Dr. Peseau
16 includes two charts that show the effects of marginal
17 cost weighting. Please comment on the charts.
18 A.My only comment on the two charts relates to
19 the horizontal line that is called "non-weighted". My
20 concern is that someone might view the charts and
21 conclude that allocation factors include no shape except
22 that provided by marginal cost weighting. That is not
23 true. All of the energy and demand allocation factors
24 proposed for use in this case capture the monthly shape.25 of every individual class's energy and coincident peak
CASE NO. IPC-E-08-10
10/24/08 1402 HESSING, K (Reb) 16
STAFF
.
.
.
19
20
21
22
23
24
25
1 demand. The only time this is not true is if the monthly
2 weight is set at zero and the weighted and unweighted
3 allocators are not averaged.
4
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
CASE NO. IPC-E-08-10
10/24/08 1403 HESSING, K (Reb) 16a
STAFF
.
.
1 The Commission has never accepted such a proposal. Data
2 reflecting the shapes of the allocation factors, weighted
3 and unweighted, for the classes are shown for the Base
4 Case method on Company Exhibit No. 59. The weighted and
5 unweighted shapes of irrigation class energy and
6 coincident peak demands are striking and show why the
7 irrigation class is allocated significant costs for use
8 during the summer peak period.
9 The Department of Energy's Cost of Service Proposal
10 Q.What is Dr. Goins' preference for the
11 classification of production plant?
12 A.He initially recommends that all production
13 plant investment be classified as 100% demand related.
14 To my knowledge this has never been done in Idaho. Coal
15 and hydro plants cost more per kW to build than gas fired
16 peaking units. The additional investment is made with
17 the knowledge that energy can be produced at a lower cost
18 from these plants when they are operated at a high
19 capaci ty factor. Since the additional investment is
20 incurred to reduce energy costs it is logical to allocate
21 the investment as energy related.
22 Q.Please discuss the Department of Energy's Cost
23 of Service proposal presented by Dr. Goins.
24.25
A.Dr. Goins presents the results of four
different cost of service studies but recommends that the
Commission
CASE NO. IPC-E-08-10
10/24/08 1404 HESSING, K (Reb) 17
STAFF
.
.
1 accept either one of his two weighted 12CP studies.
2 Q.Are either one of the two weighted 12CP studies
3 that he proposes the same as the Base Case 12CP study
4 accepted by the Commission in Case No. IPC-E-03-13?
5 A.No. Nei ther one averages weighted and
6 unweighted demand allocators.
7 Q.Are any of the monthly weighting factors zero
8 in his studies?
9 A.Yes. Six months are weighted at zero in the
10 development of the capacity related demand allocator
11 applied to production plant. Demand related transmission
12 allocators and Energy allocators are also weighted but no
13 month is weighted at zero. For base load production
14 plant his method results in a demand allocation based on
15 6 coincident peaks, or a 6CP method.
16 Q.What is the difference between the two weighted
17 12CP methods he recommends?
18 A.In Exhibit No. 610 he classifies hydro and
19 thermal production plant costs and purchased power
20 expense as proposed by the Company using the load factor
21 method. The results presented in Exhibit No. 611
22 classify these same costs using an al ternati ve method.
23 Q.Do you believe that the Commission should
24 accept either one of his weighted 12CP studies?.25 A.No. I have already stated my preference to
move
CASE NO. IPC-E-08-10
10/24/08 1405 HESSING, K (Reb) 18
STAFF
.
.
.
1 to the Company-proposed 3CP/12CP method and I have
2 discussed concerns that I have with zero weighted months
3 especially when there is no averaging of allocators. I
4 have also discussed the reasons why I support the load
5 factor classification of base load production plant
6 costs.
7 Q.Does Dr. Goins recommend that the Commission
8 use his cost of service results or any of the results
9 from the methods presented by the Company as a starting
10 point in class revenue allocation in this case?
11 A.No. He recommends a uniform percentage spread.
12 Q.Do you support a uniform percentage revenue
13 spread to the classes in this case?
14 A. No. No serious move toward cost of service has
15 been made since the IPC-E-03-13 case even though there
16 have been two cases since then. The longer the
17 Commission postpones moves toward cost of service the
18 greater cost of service differences are likely to be. I
19 recommend that the Commission make some move toward cost
20 of service in this case.
21 Q.Does this conclude your rebuttal testimony in
22 this proceeding?
A.Yes, it does.23
24
25
CASE NO. IPC-E-08-10
10/24/08 1406 HESSING, K (Reb) 19
STAFF
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 MR. PRICE: I would now present this
4 wi tness for cross-examination.
5 COMMISSIONER SMITH: Okay, thank you. Mr.
6 Richardson, do you have questions?
7 MR. RICHARDSON: Just a couple,
8 Madam Chair.
9
10 CROSS-EXAMINATION
11
12 BY MR. RICHARDSON:
13 Q Good afternoon, Mr. Hessing.
14 A Good afternoon.
15 Q Mr. Hessing, you state in your rebuttal
16 testimony at page 11, lines 15 to 18 that the current
17 methodology developed in 2004 that establishes coincident
18 demands that are used in developing class cost of service
19 allocation factors has unintended consequences. Can you
20 explain to us what you consider those unintended
21 consequences to be?
22 A I believe that -- well, first off, a
23 little bit of explanation. The coincident peak
24 methodology that picked a five-year median by my
25 understanding was done to deal what abnormal weather
CSB REPORTING
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1407 HESSING (X)Staff
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.
.
1 effects on coincident peak demands and the method does do
2 that, but it also captures other changes in coincident
3 peak factors that might be caused by program changes, you
4 know, such as Peak Rewards Program and Cool Credits
5 Program. The Company made an adjustment, to my
6 understanding, for the irrigators in this case that
7 brought those. current instead of allowing those to lag
8 behind by, I think, two years was the stated amount
9 earlier in someone' s testimony, so it concerns me that
10 we're capturing more than just the weather effects.
11 It concerns me that there are programs
12 that are designed to change coincident demands,
13 coincident peak factors and that the Company is in the
14 process of changing its metering capabilities so there
15 may be other time of use programs that might also from
16 that in the future be designed to change the coincident
17 peak factors, so although I'm not proposing, I haven't
18 proposed a solution to the weather concern that was
19 expressed in the workshops, I am concerned that we're
20 doing more than what we intended to do and I'm concerned
21 that the effects might be larger than the weather-related
22 effects that we were trying to address.
23 Q Would you say that this method of
24 calculating the coincident peak demand factors has had a
25 significant impact on the allocation of revenue
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1408 HESSING (X)
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.
19
1 responsibili ty among customer classes between the 03-13
2 case that was last litigated by the Commission and the
3 rate cases the Company has filed since?
4 A I re-ran with the help of this information
5 provided by the Company the cost of service that Staff
6 would propose and there were significant impacts on some
7 classes as a result of updating the coincident factors to
8 just the most recent year which was 2007.
9 Q And would you agree that this has been a
10 factor in the shift of revenue responsibility to the high
11 load factor customers?
12 A I didn't actually examine it to see
13 what -- I looked at the effects on the Schedule 19
14 customers which is one of the high load factor groups,
15 but I didn't actually examine the other classes to see
16 what those impacts were.
17 Q But it was a factor for the Schedule 19
18 customers?
A It made a difference in Schedule 19 cost
20 responsibility.
21 Q And we could extrapolate that it would do
22 the same for the other high load factor customers?
23
24
25
A It may. I haven't analyzed that.
MR. RICHARDSON: Thank you, Mr. Hessing.
That's all I have, Madam Chair.
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1409 HESSING (X)Staff
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.
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19
1 COMMISSIONER SMITH: Thank you.
2 Mr. Purdy, do you have questions?
3 MR. PURDY: No questions. Thanks.
4 COMMISSIONER SMITH: Mr. Olsen.
5 MR. OLSEN: Yes.
6
7 CROS S - EXAMINAT I ON
8
9 BY MR. OLSEN:
10 Q Good afternoon, Mr. Hessing.
11 A Good afternoon.
12 Q I'd like you to just turn to page 9 of
13 your direct testimony.
14 A I have that.
15 Q And beginning at line 15, you make the
16 observation that the results of this cost of service run
17 compared to the '03 case are different in the '08 case
18 from the '03 case; is that correct?
A Yes, specifically for high load factor
20 customers.
21 Q Okay, and you cite down on line, beginning
22 on line, 24 and continuing over to page 10 that load
23 growth in the residential class has occurred in record
24 amounts and that is one of the rationales for that
25 change; is that correct?
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1410 HESSING (X)Staff
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.
.
1 A The load growth, I think it's well
2 recorded that load growth has occurred in record amounts
3 and it drives some of the changes that have occurred in
4 cost of service, yes.
5 Q Okay, if we could turn to your rebuttal
6 testimony on page 1.
7 A Excuse me, what page was that?
8 Q Page 1.
9 A I have that.
10 Q Okay, beginning on line 20, you just
11 answered the question there and I'll just read it, it
12 says, "The cost of providing service to new customers is
13 always higher than the embedded cost of serving existing
14 customers upon which rates are based."
15 A I think it says "almost always higher."
16 Q I'm sorry, that's correct, "almost always
17 higher," and so that's a position, I guess a truism,
18 usually costs at the margin by and large are higher than
19 the average costs?
20 A It's been the reality of all recent
21 years.
22 Q All recent years, okay. If you could go
23 to page 2 of your rebuttal testimony, beginning on line
24 2, you indicate there that some of the costs are growth
25 related and other costs are associated with replacements,
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1411 HESSING (X)Staff
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.
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20
21
1 as you're characterizing the costs in this case. Now,
2 just quickly here, have some of the Company's
3 run-of-the-ri ver generators along the Snake been
4 replaced, to your knowledge?
5 A I don't know about for the test year, but
6 certainly they've been replaced and upgraded and Swan
7 Falls, that was done a number of years ago there, so I
8 think that's an ongoing program to improve efficiencies
9 when it's cost justified.
10 Q Okay, so that's a cost. Has the Hells
11 Canyon complex been replaced or relocated in the last 25
12 years?
13 A I was down there a couple of years ago
14 when they were doing substantial work on one of the
15 Brownlee units and the turbine was actually pulled out of
16 the hole.
17 Q So there's ongoing maintenance and stuff,
18 but it's not been replaced, per se, the project?
19 A Certainly there's ongoing maintenance.
Q Certainly.
A And relocations and upgrades of all kinds
22 for reliability.
23
24
25
Q Okay; but it's not expanded capacity?
A Well, I think sometimes the upgrades that
the Company makes does expand the capacity.
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1412 HESSING (X)Staff
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.
.
1 Q Well, in the last five years, how many
2 megawatts of capacity has the Company added at Bennett
3 Mountain and Danskin?
4 A I don't have those exact numbers, but it
5 must be near 200.
6 Q Were any of those, the megawatts of
7 capacity that were brought on line there, were those
8 replacement capacity or related to growth?
9 A I would say they're related to growth and
10 reliability.
11 Q In this case you have looked at the
12 Company's proposal and have more or less accepted or have
13 recommended that the Commission accept the 3CP/12CP
14 method; is that a fair characterization of your
15 testimony?
16 A Yes, I examined it and recommended the
17 Commission accept the Company proposal there.
18 Q Now, this method, and I'm going to talk at
19 a high level,' you know, I'm not as technical as some of
20 my colleagues around here, so I'll use a little more
21 generalities here, but my understanding is this 3CP/12CP
22 method allocates some production plant based on 12
23 coincident peaks and other production plant on the basis
24 of three coincident peaks; is that correct?
25 A Could you repeat that? I didn't hear part
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1413 HESSING (X)Staff
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.
.
1 of the question.
2 Q Yes, sorry. My understanding is that some
3 of the production plant is allocated based on 12
4 coincident peaks and the other portion of the plant is
5 based on three coincident peaks; is that correct?
6 A That's my understanding, yes.
7 Q Okay, and that this same procedure uses
8 the system load factor to allocate approximately 59
9 percent of the fixed generation costs on the basis of
10 energy before it applies the use of that 12 coincident
11 peaks; is that correct?
12 A That's true for coal and hydro.
13 Q Coal and hydro, okay. Now, and this is
14 the same method that's being challenged by a number of
15 intervenors, I think specifically the high load factor
16 customers; is that correct?
17 A Yes, they're challenging and proposing
18 other methodologies.
19 Q Now, is this method in any way published
20 or referred to in the NARUC cost of service manual that
21 everybody refers to?
22 A Well, the Company considers it to be a
23 base-intermediate-peak methodology that's referred to in
24 the cost allocation manual that's been discussed here
25 already today by other witnesses.
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1414 HESSING (X)Staff
.
.
.
1 Q But it's not directly that
2 base-intermediate-peak that Dr. Goins testified to
3 earlier today, is it?
4 A He said it wasn't the same as the
5 base-intermediate-peak that he thought the cost
6 allocation manual referenced.
7 Q Now, you made some comments with respect
8 to Mr. Yankel~ s testimony that he's provided in this case
9 and you take issue with the fact that his proposed load
10 growth adjustment isn't in any published manual or you
11 haven't found any type of, I guess, authority for that
12 use; is that correct?
13
14
15
A I think that was the conclusion from the
workshops after the 03-13 case.
Q Isn't it fair to characterize the
16 Company's use. and your acceptance of the 3CP method and
17 12CP method as something that was crafted based on cost
18 of service principles but not necessarily out there in
19 generally accepted terms?
20 A Well, I think there's a substantial
21 difference. I think Mr. Yankel' s proposal constitutes
22 vintaging as one of the other witnesses has discussed and
23 it does that because it draws a line in time for growth
24 and looks at growth-related costs and growth can't be
25 identified without a line that's drawn in time and he did
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1415 HESSING (X)Staff
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.
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1 that and I believe that causes problems and concerns.
2 Q Well, isn't that just true of cost of
3 service in general, it draws a line in time and makes
4 that same assumption?
5 A I don't believe it does. The cost of
6 service studies based on the test year that have been
7 discussed, the projected or forecasted 2008 test year, I
8 don't believe that they do that. They look at a specific
9 year, yes, but they don't look at identifying differing
10 rates based on a 10-year proj ection of load growth.
11 Q But doesn't the cost of service study take
12 the test year and assume it's in a static state and then
13 assigns costs and admittedly in this case, I think
14 Mr. Tatum's testimony says we're trying to do some
15 forward looking when you apply the marginal cost
16 weighting factors, isn't this doing the same thing?
17 A I don't believe it's doing the same thing.
18 We are looking at some forecasts in the test year. There
19 have been various types of normalizing adjustments done
20 to test years, you know, for all the time that I've been
21 working on cost of service cases, but I don't think
22 that's the same thing as looking at a 10-year proj ection
23 of growth and allocating costs away from a class based on
24 the lack of growth in that period.
25 MR. OLSEN: I guess maybe it's a matter of
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1416 HESSING (X)
Staff
.
.
.
17
1 semantics. It seems that if you're looking at some
2 growth factor, I guess, at the margin, it's very similar
3 to look at potential growth in a class, but I have no
4 further questions, Madam Chair.
5 COMMISSIONER SMITH: Mr. Ward.
6 MR. WARD: Thank you.
7
8 CROSS-EXAMINATION
9
10 BY MR. WARD:
11 Q Mr. Hessing, I know you'd be disappointed
12 if you and I didn't have a discussion about cost of
13 service studies and in fact, we've had discussions about
14 them over the last three years in particular both --
15 well, not in hearings because we never got to hearings,
16 but certainly informally; is that true?
A Yes, cost of service has been reviewed in
18 workshops and with previous filings before the Commission
19 that have been settled.
20 Q And one of the contentions Dr. Peseau
21 makes, but is, I think it's fair to say, echoed by the
22 other high load factor expert witnesses, Dr. Goins and
23 Dr. Reading, is that there is a completely inexplicable
24 resul t or change that takes place from the last litigated
25 case, the '03 case as we've been referring to it, and
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1417 HESSING (X)Staff
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.
.
1 today' s cost of service and you would agree with me,
2 would you not, that they make those allegations in
3 general terms?
4 A I think they make allegations. I don't
5 necessarily agree with them.
6 Q Right, and in fact, beginning on page 10
7 of your testimony --
8 A Direct or rebuttal?
9 Q We're in direct now, at least we will be
10 when I get there. Now, here you try to come up with an
11 explanation for why notwithstanding the fact that peak
12 load is out -- peak load growth is outpacing average
13 energy consumption, which would normally suggest that low
14 load factor customers will be seeing pressure on their
15 costs, but in fact, what we are seeing is a huge increase
16 in the high load factor's cost allocation. In general,
17 those would be the expectations we would have when we saw
18 that kind of load growth, wouldn't that be correct?
19 A It's more to me than just cost allocations
20 and I discuss. in part of that presentation there the
21 revenue impacts of a particular class where load is
22 growing and it's a hypothetical. It's very simple
23 because what the Company is really experiencing is a lot
24 more than load growth in one class.
25 Q I understand that, Mr. Hessing, and your
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1418 HESSING (X)Staff
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1 explanation, your simple hypothetical, is exactly what I
2 want to talk to you about. What you postulate is well,
3 the situation is this: Marginal costs are running,
4 marginal energy costs are running, about six cents per
5 kilowatt-hour; right?
6 A That's in the example, yes.
7 Q And from that, you go to the conclusion
8 that the reason or an explanation for the unusual
9 circumstances or the unusual change that we see is that
10 residential customers' rates are about six cents a
11 kilowatt-hour, correct?
12 A Correct.
13 Q Whereas, the high load factor customers
14 are only about three cents per kilowatt-hour; correct?
15 A Correct.
16 Q And I'm obviously trying to digest your
17 discussion on page 10 and 11, so if I do it unfairly, let
18 me know. Now, initially when I read that, it struck me
19 as there was some plausibility, but Dr. Goins has taken
20 issue with it in his rebuttal testimony, as you're well
21 aware, but I want to examine it from a somewhat different
22 perspective. First of all, if you think it through,
23 Mr. Hessing, how could the different rates that are paid
24 by residential customers and a contract customer like
25 Micron if they are properly set, how could any of them
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1419 HESSING (X)
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.
.
1 recover marginal costs that are higher than embedded
2 costs because they're all set on embedded costs, aren't
3 they?
4 A They are all set on embedded costs.
5 Embedded costs change and basically are averaged or
6 blended up with new investment at much higher cost levels
7 than what are included in those embedded costs, so over
8 time, those embedded costs are different and they're
9 higher.
10 Q You mean the marginal costs are higher?
11 A The marginal costs are higher and the
12 embedded costs, they're both higher.
13 Q Are driven higher by the addition of
14 marginal costs, I understand what you're saying.
15 A Okay.
16 Q But that's true for all classes, isn't it?
17 I mean, every time we set rates, we sit down and we
18 determine what the embedded costs are for each class and
19 determine their rates -- if we're doing it properly, we
20 determine the rates on that basis; correct?
21 A If we move to full cost of service, they
22 have rates determined on that kind of a basis.
23 Q All right. Now, after thinking about that
24 a little bit -- may I approach the witness?
25 COMMISSIONER SMITH: Yes, you may.
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1420 HESSING (X)
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.
1 MR. WARD: Just on the assumption you
2 probably don't have Mr. Tatum's exhibits with you, I'm
3 going to bring one to you. We don't need this one
4 identified. We're not going to write on this.
5 (Mr. Ward approached the witness.)
6 Q BY MR. WARD: Now, as I said, after
7 thinking about ita bit, Mr. Hessing, and thinking about
8 it in general terms if we're setting all rates on
9 embedded costs, try to figure out why exactly the
10 six-cent/three-cent hypothetical doesn't make sense and
11 here I have given you Exhibit No. 67 of Mr. Tatum's page
12 1 of 6, and I'll just say I used this rather than your
13 cost study because you have no equivalent exhibit and if
14 you look at this document, basically what this is is a,
15 it is cost of service results in this case using the
16 3CP /12CP for the residential service schedule and you'll
17 see that indicated up in the left-hand, upper left-hand,
18 column.
19
20
A I see that.
Q Okay. Now, if you look through this
21 document, what you see is that, first of all, on the
22 right-hand side, on the far right-hand side, there's a
23 column labeled "Service" and it says, "(dollar per
24 customer per month) ." Do you see that?
25 A I do.
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1421 HESSING (X)Staff
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1 Q And down there at the bottom of that
2 column is a total of $14.89.
3 A I see that.
4 Q And up above, roughly in the middle of the
5 exhibit, if you go over to the left-hand side, you'll see
6 a primary heading at line 22 that's labeled
7 "Distribution" and then a number of lines thereunder. Do
8 you see those?
9 A Yes.
10 Q Okay. Now, can you explain to the
11 Commission what this document is laying out, what those
12 distribution figures and what that customer service
13 figure means?
14 A I think -- first off, I guess this is a
15 page from the cost of service study, the 3CP /12CP study.
16 Apparently, it's also the one that the Company submitted
17 in this case and the cost of service study divides up
18 costs into different categories. It categorizes them by
19 production, transmission, distribution, customer,
20 customer information and miscellaneous and it identifies
21 through the process of cost of service what some of those
22 costs that are allocated by the appropriate factors are
23 and so it has cost categories that, I guess, are
24 recommended by cost of service for those categories.
25 Q All right. Now, I'll try to keep this as
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1422 HESSING (X)Staff
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.
.
1 brief as possible. Let me represent to you that in
2 wi tness Waites' testimony at page 10, line 17, she says
3 that the average residential usage on the Idaho Power
4 system is about 1,065 kilowatt-hours. Will you accept
5 that, subj ect to check?
6 A I will.
7 Q Now, if we start totaling these numbers
8 up, what happens is, first of all, we have for the
9 residential class at 14.89 a month. Do high load factor
10 customers pay anything like that in terms of a proportion
11 of their rates?
12 A I think high load factor customers pay
13 Q For a customer charge if I didn't say
14 that.
15 A Okay, that's what I was thinking of, a
16 customer charge. It seems to me like high load factor
17 customers pay a greater customer charge than that.
18 Q In relation to their rates. Let me ask it
19 this way: If we take the 1,000 and some kilowatt-hours
20 per month and divide it into the 14.89, right away out of
21 the six cents that the residential customers pay, roughly
22 a little less than a cent-and-a-half has to go for the
23 customer charge; correct?
24
25
A Certainly something has to go for the
customer charge and you're representing it as a
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1423 HESSING (X)Staff
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1 cent-and-a-half.
2 Q Well, roughly. It's a little less than
3 that, but I want to try not to calculate all these things
4 out to six places right of the decimal point.
5 A Well, I agree that a portion of the
6 revenue requirement is associated with the customer
7 charge and if you looked at that on a, I guess, blended
8 or a basis of. cents per kilowatt-hour, that's pretty
9 close.
10 Q And if we looked at the same column for
11 the high load factor customers, there would be a much
12 bigger number. than $14.00 there, obviously, but it would
13 be virtually insignificant in terms of a portion of their
14 rate paid because they have so many kilowatt-hours.
15 A As dollars per megawatt-hour, it would be
16 pretty small because of the extremely large amount of
17 energy that those customers use.
18 Q Okay; so now we're down to really the net
19 available in the residential rate for contribution to
20 production and transmission, by the way, which is what
21 we're talking about in terms of incremental cost, it's
22 down to four-and-a-half cents. Now, let's subtract if
23 you add up those columns under distribution, again, I
24 just want to get these in rough terms, it comes out to
25 about point seven cents, if you'll accept my
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1424 HESSING (X)Staff
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.
.
1 representation.
2 A And what columns are you adding?
I'm adding all of those that have entries
4 in lines 23 through 38.
3 Q
But you're excluding the ones you have
Yes, not counting the customer service
8 that we've already added up.
5 A
So there's, I don't know, about ten
There's five, actually.
Okay; so you're looking at summer or
Yeah, actually, they're the same for
15 summer and non-summer in distribution charges, as they
6 already added?
7 Q
You're right, they are.
All right; so if I'm right that that adds
19 up to about point seven percent point seven cents per
A
Q
20 kilowatt-hour, if you look down at the bottom, you see
9 A
21 the total for summer and non-summer rates in the very
10 numbers there.
11 Q
12 A
22 last line, line 60 --
23
24
25
13 non-summer?
Yes.
-- and summer is 6.1 and 4.8, roughly, for
non-summer, so that works out to about the five, the high
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14 Q
16 should be.
17 A
18 Q
1425 HESSING (X)Staff
.
.
.
1 fi ve' s average that I think you have in your testimony
2 somewhere, something just under six cents.
3 A Yes.
4 Q But if we subtract out the distribution
5 and the customer charge, we get something on the order of
6 a non-summer contribution to marginal power supply costs
7 of 2.6 cents and roughly 3.9 cents in the summer per
8 kilowatt-hour. Those numbers don't look any different
9 than the high' load factor contract customers, do they?
10 In other words, they're paying the same amount, as we
11 would expect, in relation to marginal power supply costs,
12 roughly three cents.
13 A I think and it seems to me like there
14 should be similar pages for high load factor customers
15 that we're not looking at here. We're only looking at
16 Schedule 1 and I think there are some differences in the
17 production co~ts between those high load factor customers
18 and residential customers.
19 Q The way it would be allocated, yes, but
20 your point was that the residential rate has six cents
21 available to offset the six cents of marginal power
22 supply costs and what I'm trying to point out is it
23 doesn't.
24
25
A Yes, there are costs here associated with
those things that would have to come out of the six
CSB REPORTING
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1426 HESSING (X)Staff
.
.
.
1 cents, you're correct.
2 Q And on the other hand, for the industrial
3 customers, again, first of all, they don't pay
4 anything -- let me back that up. The contract customers,
5 the very high load factor customers, they don't pay
6 anything for the generalized distribution system; isn't
7 that true?
8 A Yes, most of them don't use the
9 distribution system and are not allocated any
10 distribution costs. Now, that's, like you say, that's
11 not necessarily true of Schedule 19.
12 Q That's true and just by way of caveat so I
13 don't mislead the Commission, typically, the large
14 contract customers have a substation assigned to them,
15 don't they, or allocated to them?
16 A They often do.
17 Q Yeah, but typically those, at least for
18 the ones we've got here today, those have been
19 depreciated out for a long period of time, so we can
20 expect that's going to be a pretty small number.
21
22
A That could be a pretty small number.
Q Okay; so as we would expect when we
23 actually do the numbers and realize that everybody's
24 rates are set on embedded costs or, if you want, a
25 combination of embedded and marginal costs, but if
CSB REPORTING
[phone]
1427 HESSING (X)
Staff
.
.
.
1 they're properly set, everybody is paying the same
2 contribution to power supply costs and everybody is below
3 marginal cost, residential and high load factor if we've
4 done it right.
5 Everybody is paying the marginal cost.A
6 Would you repeat that question one more time for me?
7 I don't think I can repeat it. I made itQ
8 is too complicated. We're setting everybody's rates
9 based on embedded costs and because we do that, the power
10 supply component for everyone, all customer classes, is
11 going to be relatively similar, subj ect to the variations
12 about the allocations that you talked about, it's going
13 to be relatively similar. There's no surprise in that,
14 is there?
15 I think that's true. They'd be relativelyA
16 similar.
17 So what we're seeing happening to the highQ
18 load factor customer can't be explained with the
19 supposition that the residential customers are covering
20 their marginal power supply costs and the high load
21 factor customers are not, can it?
22 I don't believe I said, and maybe you'reA
23 reading that in, that they were covering all of their
24 marginal costs. Those costs are going back -- if the
25 residential class is the growth class and we're looking
CSB REPORTING
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1428 HESSING (X)Staff
.
.
.
1 at those marginal costs, those costs are going into the
2 Uniform System of Accounts and they're being blended or
3 averaged with all the other costs there and the
4 tesidential customers if they're the growth class,
5 they're contributing three cents. Now, all of those
6 costs, because as their load grows, they're allocated a
7 larger percentage of the costs in the accounts, other
8 customers are allocated a smaller percentage, but with
9 other customer classes, that lower percentage does not
10 offset the growth in the costs, in the Uniform System of
11 Accounts, because of the very high marginal costs that
12 are going in there with current growth or relocation or
13
14
anything else.
Q I would agree with that, Mr. Hessing, as
15 long as you say that's true for everybody.
16
17
A It is.
Q Okay. Let's go to your rebuttal. On page
18 5, Dr. Goins did a very good job this morning of
19 explaining how with the 3CP / 12CP we've really kind of
20 invented a new category that isn't exactly demand or
21 energy as we typically think of it and that occurs
22 because we segregate out base load, intermediate load and
23 peaking plants and treat them differently and I don't
24 want to walk through all of that again, but down at the
25 bottom you say, "Dr. Peseau recommends that all hydro and
CSB REPORTING.
[phone]
1429 HESSING (X)Staff
'.
.
.
1 thermal production plant be classified as demand
2 related." Now, if we're going to use the 3CP/12CP
3 approach, doesn' t it make sense to or isn' t it too
4 simplistic to talk about demand related or energy
5 related? The real key becomes is it 3CP demand; in other
6 words, do you allocate the costs to a category that's
7 going to be allocated on 3CP or is it 12CP demand, in
8 which case it's going to be allocated on the basis of
9 unweighted 12CP demand, there's that distinction, isn't
10 there?
11 Yes, there is that distinction.A
12 And it makes a big, big cost distinction,Q
13 too, doesn't?
14 A It does have a significant impact.
15 Okay, and then, of course, the energyQ
16 charge or energy component, whatever the energy component
17 is. Now, isn't it true that what Dr. Peseau did is he
18 allocated 50 percent of hydro to the CP that is for
19 peaking purposes and 50 percent to the base and
20 intermediate plant purposes, that is, non-weighted
21 12CP?
22 That's my understanding of what heA
23 recommended.
24 And in addition, he allocated all thermalQ
25 plant other than the peaking plants to the 12CP?
CSB REPORTING
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1430 HESSING (X)Staff
.
.
.
1 A Yes.
2 Q Now, as Dr. Goins pointed out this
3 morning, with this new category of 12CP or whichever one
4 you want to call it, actually they're both new, with this
5 new category of unweighted 12CP, the dollars we put into
6 that account are going to spread evenly, virtually
7 evenly, throughout the year in the same way that energy
8 does or very similar to the way energy does; isn't that
9 true?
10 A Okay, I think capacity and energy are
11 correlated in the general sense, but the allocators are
12 different and they don't go in exactly the same way as
13 energy. There is a difference. The 12 coincident peak
14 demand allocation method is commonly recognized and used
15 everywhere that I'm familiar with.
16 Q I understand that and I don't take issue
17 wi th that, but what I'm trying to point out is -- let me
18 state it another way, if I may. With the Company's
19 proposal and yours as well for the 3CP/12CP, what we've
20 done is we've. created a new category of demand costs that
21 we're going to allocate on a relative narrow band of 3CP.
22 That's true so far?
23 A Yes.
24 Q And obviously, none of the high load
25 factor customers are going to obj ect to that, are they?
CSB REPORTING
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1431 HESSING (X)
Staff
.
.
.
1 A I wouldn't think so.
2 Q Because that alone is favorable to them?
3 A It is.
4 Q On the other hand, we have taken out the
5 larger chunk of generating plants and production plants,
6 that is, hydro and the base load thermal, which is
7 predominantly coal, and we've allocated them or we've
8 consigned them to a category that is not going to display
9 much seasonality at all, is it? It's going to look
10 awfully close month by month whether it's April, a low
11 cost month, or December, which is a high cost month.
12 A It displays the seasonality of coincident
13 peak demands in the 12 months.
14 Q But that isn't going to be anything like
15 the weighted 12CP or the 3CP either for that matter?
16 A The weighted -- I mean, to me, the
17 difference between the weighted 12CP methodology that was
18 applied in the base case method, the 03-13 case, and the
19 division between the base and the peak demand categories
20 in this case, they both attempted to define seasonality
21 and that seasonality is defined in either case. I
22 believe the 3CP /12CP method defines it better and assigns
23 those peaking plant costs to those three coincident peak
24 months.
25 Q I don't want to abuse this and overstay
CSB REPORTING'
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1432 HESSING (X)Staff
.
.
.
1 our welcome on this single subject, so I'll try to cut to
2 the chase. Dr. Goins said this morning that, and
3 Dr. Peseau says something similar in his testimony
4 without putting a number to it, said essentially what
5 we've done when we create this intermediate category and
6 add it to the energy that right off the top 60 percent,
7 59 percent, of our capacity which is fixed is treated as
8 if it's variable, as if it's energy. That's right off
9 the top per the load factor; right?
10 A And the Commission has been doing that for
11 a great many years and I think it's appropriate.
12 Q Well, there's a long section in
13 Dr. Peseau' s testimony where he explains why the
14 Commission did that many, many decades ago, but I'm not
15 going to pursue that with you, that's a side track for
16 right now, but if Dr. Goins is right that when you take
17 the 60 percent and then you add the intermediate which
18 doesn't vary much, you get something that looks very
19 like, is almost indistinguishable from, an 80 percent
20 allocation of fixed production capacity to variable
21 energy costs, and by the way, I made somewhat the same
22 crude calculation myself a few days ago and it's about
23 right, I think. You can't get the exact, the number
24 exact, but if that's true, does that strike you as
25 appropriate for a company in which at least three, well,
CSB REPORTING
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1433 HESSING (X)Staff
.
.
.
1 at least two witnesses, Company witnesses, have testified
2 that the peak is growing more than twice as fast as the
3 average consumption and that it's expected to do so for
4 the foreseeable future, is that an appropriate cost of
5 service methodology for that Company?
6 A Well, first of all, I'm not sure that it's
7 true, because the cross-examination or the discussion
8 wi th Dr. Goins this morning, he wanted to and at points
9 in there consider the 12CP demand method as energy and if
10 you do that, maybe it is 85 percent, but I don't believe
11 that the 12CP coincident peak demand allocation method is
12 energy.
13 Q Well, but what he was saying, Mr. Hessing,
14 and I got the same result using a different theory but
15 the same general principle, what he's saying essentially
16 is what we're trying to decide with these fixed
17 production plant costs is how much should we allocate to
18 demand, which is related to peaks in some fashion, and
19 we'll stay away from that for a minute, in some fashion
20 is related to peaks and how much we allocate to energy
21 which is variable and in fact varies very little
22 seasonally in the cost of service study and what he's
23 saying is you get -- it doesn't matter what you call this
24 duck, when you get all done with the 3CP/12CP proposal,
25 what you get is roughly the same as you would get if you
CSB REPORTING
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1434 HESSING (X)Staff
.
.
.
1 just went straight to an allocation of 80 percent of the
2 fixed costs to energy.
3 A Well, like I've said --
4 Q Same result.
5 -- I don't believe that's true. If itA
6 were true, it would seem like that would be too much
7 weight on energy.
8 Okay, that's fair enough. I think I justQ
9 have one more, and by the way, you say elsewhere in your
10 rebuttal, you point out that one of the reasons for the
11 drop in load factor on the Idaho Power system was the
12 shut-down of the FMC plant and you're clearly correct on
13 that.
14 A Thank you.
15 It is true, however, though, that in aQ
16 sense from a cost of service standpoint, we may care
17 socially and for other reasons, but from a cost of
18 service standpoint, the causes that motivate a change in
19 load factor really don't make any difference. I mean,
20 the cost of service study doesn't know whether it's load
21 growth or load destruction, does it?
22 To the extent that it affects the loadA
23 factor under the classification methodology that I'm
24 recommending,. all it sees is the load factor and if the
25 load factor changes, then it sees that and if the load
CSB REPORTING
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1435 HESSING (X)Staff
.
.
.
10
1 factor falls from 68 percent to 59 percent, there are
2 fewer costs that are classified as demand related -- I'm
3 sorry, do I have that right? There are fewer costs that
4 are classified as energy related and allocated to high
5 load factor customers.
6 Q Yeah, and the cost of service study
7 doesn't know the cause?
8 A The cost of service study doesn't know the
9 cause.
MR. WARD: Okay, I have some very minor
11 points, but I think that's enough. I'm done. Thank you.
12 COMMISSIONER SMITH: Thank you, Mr. Ward.
13 Mr. Walker, do you have questions?
14 MR. WALKER: Yes.
15
16 CROSS-EXAINATION
17
18 BY MR. WALKER:
19 Mr. Hessing, following the '03 rate caseQ
20 with the last approved cost of service, you're aware,
21 obviously, of' the workshops that went on with most of the
22 parties here discussing these same kinds of cost of
23 service issues?
24 Before you go on with that question, theA
25 last approved- cost of service, the history of this
CSB REPORTING
[phone]
1436 HESSING (X)Staff
.
.
.
1 Commission is that it hasn't approved a cost of service
2 methodology on an ongoing basis. There's a cost of
3 service study methodology that's usually accepted for the
4 allocation in a particular case, but there's no ongoing
5 approval of a methodology to my understanding, so if we
6 can get past that, maybe we can get your question out.
7 Q Fair enough. Since the last contested
8 rate case, anyway, you're aware of the workshops?
9 A I am. I was there.
10 Okay, as were most of the parties that areQ
11 here today?
12 A Yes.
13 Q And in fact, the Company hosted those
14 workshops and participated, also?
15 A That's my recollection.
16 Q And there's no allegation here that the
17 Company was trying to come up with its own cost of
18 service that it ram down everybody's throats or anything
19 like that?
20 A No, I don't believe that I observed
21 anything like that.
22 Nobody was precluded from bringing up anyQ
23 of their ideas or methodologies or anything else to deal
24 with any of these problems?
25 Nobody was precluded. It's interestingA
CSB REPORTING
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1437 HESSING (X)Staff
.
.
.
1 that in the 03-13 case which spun off the workshops that
2 the irrigators were making the argument that something
3 needed to be done to fix cost of service and the high
4 load factor customers were conciliatory. Their costs
5 weren't particularly higher than average and so the
6 discussions in those workshops by the irrigators were
7 kind of like we need to fix this problem and everybody
8 else kind of nodded their head, but nobody else was
9 willing to take cost responsibility, have costs shift to
10 them so the irrigator didn't have to pay them. That's
11 just my observation of one of the things that happened in
12 that workshop.
13 Q And it's not surprising that a diverse
14 group that has different interests in the outcome of cost
15 of service would not be able to come up with a joint
16 consensus on a complicated study in that type of forum,
17 does that surprise you?
18 A Not at all surprising.
19 Q You are aware, though, that there was a
20 document generated and filed with the Commission that was
21 entitled The Final Report from those workshops?
22 A Yes, I am.
23 I believe that the irrigation customersQ
24 actually had that marked as an exhibit earlier in this
25 proceeding. I apologize, I can't remember what exhibit
CSB REPORTING'
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1438 HESSING (X)Staff
.
.
.
1 number that was, but --
2 I think they did. I didn't get a copy ofA
3 that either.
4 Are you generally familiar with theQ
5 resul ts of that workshop and that document?
6 I reviewed that document awhile ago inA
7 this case.
8 And in your --Q
9 COMMISSIONER SMITH: That would be Exhibit
10 307.
11
12
13
14
MR. WALKER: Thank you, Madam Chairman.
Q BY MR. WALKER: Now, in your direct
testimony, your conclusion is that -- you come to the
same conclusion and the same recommendation as the
15 Company with regard to cost of service with very little
16 changes adj usted for -- you take your revenue requirement
17 as did the Company and run it, but other than that, it's
18 essentially the same, same conclusion, same model.
19 A Yes, I accepted the methodology proposed
20 by the Company, the 3CP/12CP methodology.
21 Q Okay, and then in your rebuttal, you still
22 accept the same basic methodology, same cost of service
23 study, but there was one difference you pointed out, one
24 that came to rebuttal, do you recall that?
25 A That's correct. I -- well, go ahead with
CSB REPORTING'
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1439 HESSING (X)Staff
.
.
.
1 your questions.
2 Q What was that particular subj ect that you
3 subsequently changed in rebuttal?
4 One of the things that the parties wereA
5 able to agree on in those cost of service workshops was a
6 change in the way that the coincident factors were
7 calculated and used for cost of service going forward and
8 that was a change that selected a median number from five
9 years of data as opposed to using the most recent year
10 and I've discussed already up here that the intent, as
11 far as I understood it, was to deal with weather and to
12 try to normalize coincident peak demand relative to
13 weather.
14 And that wasn't something that the CompanyQ
15 just came up with on its own, was it?
16 No, it wasn't. I believe the originalA
17 proposal was presented by the irrigators to do some kind
18 of normalization by averaging.
19 And is it your recollection that one ofQ
20 the few consensus items delineated in this final report
21 is that the Company would file its cost of service with
22 that particular methodology for coincident peak?
23 Yes, that's my understanding.A
24 And that was a consensus item at least inQ
25 '05 when this' document was filed and apparently not so
CSB REPORTING
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1440 HESSING (X)Staff
.
.
.
1 now?
2 I guess I would say that I had someA
3 concerns about the methodology beginning with the 05-28
4 case and when Dr. Reading examined them again in this
5 case, I had the opportunity to look at them myself and
6 came to the conclusion that although it was a consensus
7 to file that way, there were some potential problems that
8 I thought were significant and so I guess what I'm
9 proposing and recommending is a change in that
10 methodology. I don't dispute the fact that it was agreed
11 that cost of service would be filed that way as a result
12 of the workshops in the 04-23 case.
13 Q And I guess the change, then, is really
14 just a fall-back to using what was used before?
15 That's correct, and it doesn' t solve orA
16 address the concern of weather normalizing coincident
17 peaks.
18 I guess I -- and I guess I'm trying to getQ
19 some understanding of what happened between direct and
20 rebuttal that' would facilitate that change. I think your
21 testimony referenced
22 I can tell you a little bit about whatA
23 happened if you just want me to go there.
24 MR. WALKER: I apologize, give me a second
25 to get my bearings.
CSB REPORTING
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1441 HESSING (X)Staff
.
.
.
1 (Pause in proceedings.)
2 Q BY MR. WALKER: If you could go ahead and
3 explain as you just offered, I think that would be
4 helpful to everyone.
5 A Okay. Like I said a minute ago, I had
6 some concerns about this issue and I talked to Mr. Tatum
7 about them in a previous case or cases. Those same
8 concerns I discussed with Dr. Reading at about those same
9 times and I was trying to determine exactly what was
10 happening here as a result of this methodology change
11 that had been accepted and so when Dr. Reading filed his
12 testimony in this case, I called him on the phone and
13 said can you come over here and can we talk about what
14 your findings' are and can we see if I agree with you on
15 some of the details of that, and so we met and we talked
16 about it and reviewed some data and he had wanted to
17 update cost of service results for the most recent year
18 and didn't have all of the information to do that, so I
19 made a request of the Company to provide me with some
20 data so that I could do that and I did that and presented
21 it in my testimony.
22 I think you referenced in your testimony,Q
23 and maybe on the stand, too, some systematic changes.
24 A That's what I called them.
25 Q Okay.
CSB REPORTING'
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1442 HESSING (X)Staff
.
.
.
1 A Program changes, things that wouldn't be
2 expected to move around like weather might.
3 Q Do you think the Company has done anything
4 to deal with those?
5 A It's my understanding that the Company
6 deal t with those for the irrigators in this case and I
7 think the Company may have some plans, and I don't know
8 what they are, to deal with them in the future, but we
9 haven't -- there hasn't been any detailed discussion
10 about how that might be done. It doesn't seem reasonable
11 to me to try to track these kinds of programs along and
12 then make adjustments for all of the classes that might
13 have a program now or in the future that changes the
14 relationship between coincident peak and average, so
15 anyway, I don't know where we're going with this, but the
16 Company has made an adjustment for the irrigators in this
17 case.
18 Q And you don't think that's a reasonable
19 way to deal with that?
20 I think it could become very difficult asA
21 we try to deal with the peak concerns that many parties
22 have expressed in this case by shifting peak elsewhere
23 and changing that relationship in those coincident peak
24 factors. I mean, I don't know that the programs we have
25 now, I would expect that they're not the end to programs
CSB REPORTING
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1443 HESSING (X)Staff
.
.
.
1 to address this concern.
2 MR. WALKER: May I approach the witness?
3 COMMISSIONER SMITH: You may.
4 (Mr. Walker approached the witness.)
5 BY MR. WALKER: I'm handing you whatQ
6 it's a little confusing. This is actually Mr. Said's
7 Exhibi t 50, but it's also Mr. Ward's or Micron's Exhibit
8 708.
9 A Okay.
10 Are you somewhat familiar with that?Q
11 I am somewhat familiar with it. If we'reA
12 going to talk about a lot of the numbers there, I may
13 have to go get reading glasses.
14 Q Well, I'm just kind of generally
15 referencing it.
16 COMMISSIONER SMITH: Can you see mine?
17 THE WITNESS: Actually, that's a little
18 better.
19 BY MR. WALKER: Can you read the title onQ
20 it? It says "Marginal Energy Costs."
21 I can read that, yes. That's some of theA
22 biggest print on the page.
23 There was some discussion and I justQ
24 wanted a couple of clarifications about this, so this
25 reflects the ~arginal energy costs as its title suggests.
CSB REPORTING
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1444 HESSING (X)Staff
.
.
.
1 I believe it does.A
2 And is this particular document reallyQ
3 that useful for discussing peak or capacity?
4 I don't believe it is.A
5 This would actually be an inappropriateQ
6 document for discussion about peak cost allocation; isn't
7 that correct?
8 Yeah, this document doesn't deal with peakA
9 or peak costs.
10 And really just to kind of wrap it up,Q
11 isn't really our main purpose here of -- it's really a
12 fundamental of the world that we're in of a regulated
13 utili ty that we're trying to get at here related to costs
14 and cost recovery; is that in the broadest sense what our
15 main function is here?
16 Wi th regard to the cost of service partsA
17 of the cases, you know, I think we're trying to get at
18 costs and cost responsibility by class and identify what
19 appropriate rate levels might be even though we recognize
20 that that's just one factor in a Commission decision as
21 far as to what class revenue requirements ought to be and
22 what class rates ought to be.
23 And wouldn't a good description of theQ
24 cost of service be something that makes a cost allocation
25 to allocate the current costs of the utility of its
CSB REPORTING
[phone]
1445 HESSING (X)Staff
.
.
.
1 current system across its current customers; is that
2 really --
3 A Yes.
4 Nobody can really argue with that?Q
5 I believe that's true.A
6 MR. WALKER: That's all I have. Thanks.
7 (Recess. )
8 COMMISSIONER SMITH: All right, I think
9 it's time to go back on the record. Just for planning
10 purposes, I think we'll go about one more hour. We're
11 now ready for the cross-examination of Staff witness
12 Hessing by Mr~ Bruder
13 MR. BRUDER: We have no questions,
14 Madam Chairman.
15 COMMISSIONER SMITH: Holy smokes. I gave
16 you the prime time and you declined.
17 MR. BRUDER: It took a lot of time in the
18 background getting to no questions.
19 COMMISSIONER SMITH: All right, are there
20 questions from the Commission?
21 COMMISSIONER KEMPTON: I'm sort of
22 stunned, Madam Chairman. No questions.
23 COMMISSIONER SMITH: I have tons of them,
24 but they'll just have to wait. Do you have any redirect?
25 MR. PRICE: No redirect.
CSB REPORTING
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1446 HESSING (X)Staff
.
.
.
1 COMMISSIONER SMITH: No redirect, all
2 right. Thank you, Mr. Hessing.
3
4
5
THE WITNESS: Thank you.
(The witness left the stand.)
COMMISSIONER SMITH: We're ready for your
6 next witness, Mr. Price.
7 MR. PRICE: Yes, we are, Madam Chair. The
8 Commission Staff now calls Mr. Bryan Lanspery to the
9 stand.
10
11 BRYAN LANSPERY,
12 produced as a witness at the instance of the Staff,
20
21
24
25
13 having been first duly sworn, was examined and testified
14 as follows:
DIRECT EXAMINATION
Please state your name for the record.
My name is Bryan Lanspery.
And who is your employer?
I'm employed by the Idaho Public Utili ties
And what is your job title there?
I'm a utilities analyst.
15
16
17
18 BY MR. PRICE:
19 Q
A
Q
22 A
23 Commission.
Q
A
CSB REPORTING
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1447 LANSPERY (Di)Staff
.
.
.
10
1 Q And did you have occasion on October 24th
2 of this year to prepare written direct testimony for this
3 case?
4 Yes, I did.A
5 And did that also include Exhibit Nos. 135Q
6 through 137?
7 Yes, it did.A
8 Do you have any corrections or adj ustmentsQ
9 or supplements to that testimony?
A I have one correction to make. It's on
11 page 11 of my' testimony. It's line 22. I say
12 "iridescent lighting," that should be "incandescent
13 lighting. "
14 Do you have any other corrections orQ
15 addi tions to your testimony?
16 A No, I do not.
17 If I were to ask you the same questionsQ
18 today that were posed in your written direct testimony,
19 would your answers still be the same?
20 A They would.
21 MR. PRICE: I would now move to admit
22 Mr. Lanspery' s direct testimony and spread it upon the
23 record, including Exhibits 135 through 137.
24 COMMISSIONER SMITH: If there is no
25 objection, we will spread the prefiled testimony upon the
CSB REPORTING
[phone]
1448 LANSPERY (Di)Staff
.
.
.
1 record as if read and identify Exhibits 135 to 137.
2 (The following prefiled direct testimony
3 of Mr. Bryan Lanspery is spread upon the record.)
4
5
6
7
8
9
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12
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CSB REPORTING
[phone]
1449 LANSPERY (Di)Staff
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1 Q.Please state your name and address for the
2 record.
3 A.My name is Bryan Lanspery and my business
4 address is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as a utility rate analyst.
8 Q.Gi ve a brief description of your educational
9 background and experience.
10 A.I received a Bachelor of Arts degree in
11 Economics with a social science emphasis from Boise State
12 University in 2003. I also earned a minor in Geographic
13 Information Systems from Boise State University in the
14 same timeframe. I have also earned a Master of Arts in
15 Economics from Washington State Uni versi ty , received in
16 2005. My Masters work emphasized Labor Economics and
17 Quantitati ve Econometric Analysis. Concurrent to
18 pursuing my Masters degree, I functioned as an instructor
19 of Introductory and Intermediate Economics as well as
20 Labor Economics.
21 Q.Would you describe your duties with the
22 Commission?
23 A.I was hired by the Commission in late 2005 as a
24 utili ty analyst. As such, my duties revolve around
25 statistical and technical analysis of Company filings,
CASE NO. IPC-E-08-10
10/24/08
LANSPERY, B. (Di) 1
STAFF
1450
1 including cost/benefit analysis,resource evaluation,.2 price
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CASE NO.IPC-E-08-10 1451 LANSPERY,B.(Di)1a
10/24/08 STAFF
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1 forecasting, and weather normalization methods. I have
2 participated in several general rate cases, focusing on
3 power supply, cost of service, and rate design. I have
4 also been actively engaged in integrated resource
5 planning, DSM/ energy efficiency program evaluation, and
6 revenue allocation issues. I completed the Practical
7 Skills for the Electric Industry held by New Mexico State
8 University in 2006, among numerous other conferences.
9 Q.What is the purpose of your testimony?
10 A.My testimony will cover Idaho Power's rate
11 design proposals for Residential Schedules 1, 4, and 5 as
12 proposed by Company witness Waites, as well as its rate
13 design for Schedule 24 , Agricultural Irrigation Service,
14 discussed in Company witness Bowman's testimony.
15 Could you please summarize your testimony inQ.
16 this case?
17 Yes. As pointed out by Company witnesses GaleA.
18 and Waites, effective rate design should be based on
19 sending cost-based price signals that promote efficient
20 consumption of energy. I propose an al ternati ve inverted
21 block, or three-tiered rate design for residential
22 customers which, in my opinion, provides better price
23 signals to customers while affording the Company a
24 reasonable opportunity to recover its Commission-approved
25 costs. I will also explain Staff's support for the
CASE NO. IPC-E-08-10
10/24/08
LANSPERY, B. (Di) 2
STAFF
1452
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1 Company's rate design proposal for Schedule 24 with
2 proposed rates based on Staff's Cost of Service study.
3 Have you prepared any Exhibits to accompanyQ.
4 your testimony?
5 Yes. Exhibit Nos. 135, 136 and 137.A.
6 Effective Rate Design
7 Please describe what is meant by effective rateQ.
8 design.
9 Effective rate design entails promotingA.
10 efficient consumption of energy through proper pricing.
11 Idaho Power, like most utilities in the Northwest, has
12 low embedded costs of generation resources used to meet
13
14
its average loads but finds itself capacity constrained
through much of the summer and deep winter months.
15 During these times , it is forced to either run higher
16 cost generation resources, such as its simple cycle
17 combustion turbines, or rely on market purchases to meet
18 its load. Flat rate design, in which kWh rates are based
19 on average costs and do not vary based on timing or level
20 of consumption, do not reflect the disparity in costs to
21 serve load during peak periods and off-peak periods.
22 Effecti ve rate design provides customers with a
23 cost-based signal that when consumption reaches a certain
24 threshold, or occurs in a particular time period, the
25 cost to provide that energy can be significantly higher
than the
CASE NO. IPC-E-08-10
10/24/08
1453 LANSPERY, B. (Di) 3
STAFF
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1 embedded rate, and the rate charged to customers should
2 reflect that fact.
3 Q.How can rates reflect disparate costs of
4 energy?
5 A.There are many ways that rates can reflect the
6 variable cost to serve, but the two most prevalent ways
7 are through tiered rate design and time-of-use (TOU)
8 rates. I will describe the basis for tiered rates, or
9 inverted block rates, in further detail wi thin my
10 testimony. TOU rates may be the more effective means of
11 tying variable energy costs with consumption in the short
12 run since marginal costs (generally reflected in market
13 prices), can vary seasonally, daily, or hourly due to
14 loads exceeding the capacity of low cost generation and
15 the inability to store electricity.
16 Tiered rates, in essence, act as a surrogate
17 for TOU rates when TOU metering is not available. For
18 Idaho Power, residential consumption is highest during
19 the most expensive periods to provide energy, the summer
20 and deep winter months. Since timing of consumption
21 correlates well with the amount of consumption, tiered or
22 block rates reasonably tie usage with costs.
23 Are there any advantages to implementing tieredQ.
24 rates in lieu of TOU rates?
25 A. Yes, the main advantage of tiered rates is that
no special metering equipment is necessary. TOU rates
CASE NO. IPC-E-08-10
10/24/08
LANSPERY, B. (Di) 4
STAFF
1454
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1 require meters that can capture consumption over specific
2 timeframes during the billing period. Idaho Power plans
3 to exchange its meters throughout the service terri tory
4 wi th advanced meters over the next few years,
5 facili tating TOU pricing in the near future for all
6 customer schedules. As of now, only residential
7 customers in the Emmett and McCall region have the
8 metering equipment necessary for TOU pricing schemes.
9 Also, TOU pricing primarily targets the timing
10 of usage, not the amount of consumption. Effective TOU
11 rates encourage shifting energy consumption to off-peak
12 periods, where price per kWh is comparatively low, but
13 can result in higher overall consumption with lower bills
14 if enough energy is shifted off-peak. Though not in
15 Idaho Power's near term, in the long run this may result
16 in the need to construct more baseload generation
17 facili ties, putting upward pressure on prices. Tiered
18 rates seek to' lower overall usage, which may prolong the
19 need to acquire highly capi tal-intensive baseload
20 facilities.
21 You mention Idaho Power's plans to rolloutQ.
22 automated metering throughout its service terri tory. Do
23 you anticipate TOU rates for all residential customers in
24 the future?
25 A. Yes I do, which makes effective tiered rate
design now much more important. Tiered rates can be
CASE NO. IPC-E-08-10
10/24/08
1455 LANSPERY, B. (Di) 5
STAFF
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1 combined with TOU rates to maximize the goal of effective
2 price signaling both in the short run and long run.
3 Combining the two would target both the timing and level
4 of consumption by customers, which has the benefit of
5 empowering the customer to control his or her power bill
6 and provide operational improvements for the utility.
7 It is also important to note that the
8 implementation of TOU rates represents a paradigm shift
9 for consumers. To successfully lower one's bill, one
10 must become savvier in tying the overall bill to one's
11 consumption pattern. Tiered rates are billed in blocks,
12 which, if proper education is provided, should draw the
13 eye of the consumer beyond just the bottom line of the
14 bill. If customers are more accustomed to how their
15 consumption affects their overall bill, they will be
16 better prepared for TOU rates.
17 You mention that sending proper price signalsQ.
18 is an important part of effective rate design. What
19 other factors did you consider when approaching
20 residential rate design?
21 I alluded to the fact that prices shouldA.
22 reflect the cost to provide the energy. If this were
23 carried to the extreme, an inverted rate design, which
24 both the Company and the Staff support, would have stark
25 differentials between the first block or tier, and thetail
CASE NO. IPC-E-08-10
10/24/08
1456 LANSPERY, B. (Di) 6
STAFF
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1 block, in order to reflect the substantial difference
2 between the embedded cost of resources and the cost of
3 marginal resources. When promoting tiered rates, one
4 must not lose sight of general rate design principles:
5 rate equity, rate stability, and opportunity for the
6 utili ty to recover its approved costs. Regarding the
7 first two principles, my obj ecti ve was to design a tiered
8 rate structure that provides meaningful signals to
9 customers that incent efficient usage but does not unduly
10 punish a subset of residential customers. Rates should
11 be higher for higher consumption levels, but not to the
12 point that some residential customers face excessively
13 large increases while others face excessively large
14 decreases. To the last principle, given that the goal is
15 to reduce consumption in the tail block, by pricing it
16 too high there is a significant risk that the Company
17 will be unable to collect its Commission-approved costs.
18 Thus, my obj ecti ve in preparing the residential rate
19 design ~as to' provide effective price signals to
20 customers tempered by the aforementioned principles.
21 Are tiered rates generally regarded as anQ.
22 effecti ve means to promote energy efficiency?
23 Yes~ In 2005 the National Action Plan forA.
24 Energy Efficiency, a public-private ini tiati ve consisting
25 of organizations such as the Department of Energy,
CASE NO. IPC-E-08-10
10/24/08
1457 LANSPERY, B. (Di) 7
STAFF
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1 Environmental Protection Agency, and NARUC, stated that
2 "Retail rate designs with clear and meaningful price
3 signals, coupled with good customer education, can be
4 powerful tools for encouraging energy efficiency." The
5 DOE stated more recently in a 2007 report to Congress
6 that rate design is one of 10 mechanisms for enhancing
7 energy efficiency. In each case cited, it is noted that
8 rate design must consider the unique characteristics of
9 the customer class.
10 Q.Are tiered rates common in Idaho?
11 A.Yes. Idaho Power currently has a two-tiered
12 rate structure for residential and small commercial
13 customers during the summer period. Avista also has a
14 two-tiered rate structure for residential customers in
15 Idaho. PacifiCorp currently has a flat rate structure in
16 Idaho, though. it does have a two-tiered residential rate
17 structure in both Washington and California, and a
18 three-tiered structure in Utah.
19 Residential Rate Design
20 You mentioned that characteristics unique toQ.
21 the customer class should be considered when designing
22 rate structures. What "unique characteristics" of the
23 residential class did you consider in your rate design?
24 Residential customers as a class tend to beA.
25 qui te homogeneous when compared to small commercial and
CASE NO. IPC-E-08-10
10/24/08
LANSPERY, B. (Di) 8
STAFF
1458
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1 irrigation customers, but more volatile when compared to
2 industrial customer classes. This can be attributed to
3 end use of electricity. As pointed out in Company
4 wi tness Waites' testimony, residential basic electric
5 usage can cover lighting and home appliances, such as
6 refrigerators and electric ovens. These tend to vary
7 mainly with the size and occupancy of the residence. I
8 would suggest that heating and cooling should also be
9 considered basic end uses, as well as a point at which
10 residential customers begin to differ from one another.
11 A fair percentage of homes in Idaho Power's service
12 terri tory use electricity for heating purposes, while
13 others use natural gas, propane, or biofuels, such as
14 wood-fired stoves, for heating. Similarly, many homes
15 have central cooling systems or some means of air
16 conditioning while many do not.
17 Beyond basic consumption, there is great
18 diversity in discretionary usage such as home computers
19 and home entertainment systems. Between discretionary
20 usage and weather sensitive usage, the residential
21 customers as a whole have relatively low load factors
22 (average load' divided by peak load). This impacts the
23 cost to serve residential customers along with the
24 utility's ability to recover its approved costs.
25 How does this affect residential rate design?Q.
CASE NO. IPC-E-08-10
10/24/08
1459 LANSPERY, B. (Di) 9
STAFF
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1 A. The low load factor reflects the "peakiness" of
2 residential load profiles. Usage tends to be relatively
3 low in spring and autumn months and higher in winter and
4 summer months. In fact, for Idaho Power the residential
5 class peaks in winter with a smaller peak in the summer.
6 When designing tiered rates, I wanted to provide price
7 signals that reflect the dual-season peaking nature of
8 the class and reduce the class average use per customer.
9 Have you reviewed the Company's proposals forQ.
10 residential rate design?
11 A.Yes.
12 Do you propose any changes to the Company'sQ.
13 position?
14 A. Yes.
15 Please summarize your proposal for theQ.
16 residential classes.
17 Based on Staff witness Hessing's Cost ofA.
18 Service results, no rate increase is warranted for the
19 residential customers, therefore I do not believe an
20 increase in the customer charge is justified. Also, I
21 believe that a three-tiered rate structure provides
22 stronger and more accurate price signals than the
23 two-tiered structure proposed by Company witness Waites.
24 I do not propose a significant change in the rate
25 differentials for Schedule 4 or 5 customers than what the
Company has presented in its
CASE NO. IPC-E-08-10
10/24/08
1460 LANSPERY, B. (Di) 10
STAFF
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1 filing.
2 Q.Please summarize the Company's proposal
3 regarding residential tiered rates.
4 The Company proposes to maintain the currentA.
5 two-tier summer rate structure for Schedule 1 customers
6 and implement the same tiered structure in the non-summer
7 period for all residential classes. The Company
8 recommends increasing the size of first block energy from
9 300 kWh to 600 kWh per month for both summer and
10 non-summer periods.
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12
Q.Do you support the Company's proposal?
A.While I agree that the size of the first tier
13 should be increased, I do not believe that the proposal
14 adequately utilizes rate design to promote energy
15 efficient usage.
16 Q.Please explain.
17 Company witness Waites states that basic usageA.
18 is measured by the shoulder months of May and October
19 (Waites, p. 10). As I stated before, I consider heating
20 and cooling to be basic needs for residential customers.
21 I will also note that what is generally considered basic
22 use, such as lighting, does not translate into efficient
23 use (e. g. incandescent lighting vs. compact fluorescent
24 lighting). Much of the May and October usage cited
25 includes discretionary usage, and serves as a poor basis
CASE NO. IPC-E-08-10
10/24/08
1461 LANSPERY, B. (Di) 11
STAFF
.1 for setting a base.If August and January were used to
2 determine basic
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CASE NO.IPC-E-08-10 1462 LANSPERY,B.(Di)11a
10/24/08 STAFF
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1 usage, residential use per customer is more in the
2 neighborhood of 1190 and 1340 kWh, respectively. Using
3 the Company's 60 percent method, the first block should
4 be set closer to 800 kWh.
5 Q.Do you propose setting the first block at 800
6 kWh?
7 A.Gi ven the data available to Staff during the
8 discovery process, it was not possible to analyze the
9 revenue generated by setting the block at 800 kWh.
10 Through the review process, I deduced that the proper
11 cutoff point for the first block should be between 600
12 kWh and 1000 kWh for a three-tier structure. I propose
13 setting the first block at 0-1000 kWh.
14 Q. Why did you stress the three-tier structure in
15 your last reply?
16 A.Again, the goal of tiered rates is to send a
17 cost-based price signal. The farther from the break
18 point, the weaker the price signal. Customers who use
19 1079, the 2008 average according to the Company filings,
20 may see no way to reduce consumption enough to materially
21 impact their bill, thus the signal does not resonate.
22 600 kWh may work under a three-tier system to encourage
23 relatively low usage customers to conserve if there were
24 a higher block to promote a strong signal to those whose
25 consumption is well above average.
CASE NO. IPC-E-08-1010/24/08 LANSPERY, B. (Di) 12
STAFF
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1 Q. Why did you choose 1000 kWh for the first block
2 if you are proposing a three-tier structure?
3 A.The 1000 kWh breakpoint is nearly 8% below 2008
4 average usage. I believe an average 8% reduction is
5 attainable given proper price signals. I see the first
6 block cutoff as a target for customers to achieve. If
7 customers respond to the price signal and average use per
8 customer declines, then I would advocate lowering the
9 block from 1000 kWh, and setting a new target for average
10 usage, and continue that process over time, using the
11 first block as a moving target.
12 What do you propose for the second block?Q.
13 A. For summer months, I propose the second block
14 be set for usage between 1001 kWh and 2000 kWh. In
15 non-summer months, I propose the second block be set
16 between 1001 and 3000 kWh.
17 Please explain why you chose to set the summerQ.
18 block between 1001 kWh and 2000 kWh.
19 I set the limit on the second block at 2000 kWhA.
20 in order to send a second price signal. Based on the
21 Company's filings and production responses, nearly 10% of
22 residential customers have consumption levels above 2000
23 kWh during the summer months of June, July, and August.
24 This corresponds to a period where the Company is
25 capaci ty constrained, and relies heavily on gas-fired
generation and
CASE NO. IPC-E-08-1010/24/08
1464 LANSPERY, B. (Di) 13
STAFF
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1 market purchases to meet load. As I have stated before,
2 customers farther from the tier breakpoint are sent a
3 weaker price signal. Setting the limit on the second
4 block at 2000 kWh sends a signal to higher usage
5 customers while limiting the Company's exposure for
6 revenue recovery.
7 Q.Please explain why you chose to set the
8 non-summer block between 1001 kWh and 3000 kWh.
9 According to the Company, the residential classA.
10 peaks during the winter, mainly due to space heating,
11 while the system peak is in the summer. Based on net
12 power supply runs, during the shoulder months (included
13 in the non-summer period) the Company has adequate
14 resources to serve its load and make off-system sales.
15 There is little validation for sending marginal
16 cost-based price signals during that period. That is not
17 the case during the months of December, January, and
18 February. Net power supply costs per unit during these
19 months are slightly lower than the summer period,
20 presumably due to the higher demand for natural gas.
21 One rationale for a larger block is that, even
22 though marginal costs are somewhat in line with summer
23 marginal costs, the Company's load (demand) is lower, due
24 mainly to the absence of the irrigation load. When
25 analyzing the billings for the three winter months,
CASE NO. IPC-E-08-10
10/24/08
1465 LANSPERY, B. (Di) 14
STAFF
1 roughly 9%of bills fall into the tail block if set at.2 3000 kWh,
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CASE NO.IPC-E-08-10 1466 LANSPERY,B.(Di)14a
10/24/08 STAFF
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1 similar to the tail block that I recommend for the summer
2 period. Again, sending a strong price signal to higher
3 usage customers should be a determinant in tiered rate
4 design, and I believe that this design accomplishes that
5 goal.
6 Similarly, I did not want to lose sight of the
7 fact that, in the winter especially, not all high energy
8 consumers are relatively high income users. While I
9 cannot put an exact percentage to it, there are many low
10 income customers with electric space heating and poorly
11 weatherized homes. Tiered rates are not necessarily low
12 income rates; they are efficiency based rates. A higher
13 rate for energy in the tail block provides a higher
14 incenti ve to invest in energy efficiency measures, such
15 as insulating. a home or converting to a high efficiency
16 heat pump, for those that can afford it. For customers
17 that cannot afford to take such measures, there are
18 programs that can assist in payment of utility bills and
19 weatherization assistance. I will leave the remainder of
20 the discussion on such programs to Staff witness Thaden,
21 noting that the Commission has opened a docket
22 (GNR-U-08-1) to address energy affordability.
23 What differentials do you propose for the blockQ.
24 rate design?
25 I propose that the first block of energy beA.
CASE NO. IPC-E-08-10
10/24/08
1467 LANSPERY, B. (Di) 15
STAFF
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1 priced approximately 12% lower than the second block and
2 the tail block be priced approximately 20% above the
3 second block for all residential classes during the
4 non-summer period. For Schedule 1 customers, I left the
5 Company's first tier rate in place and set the second and
6 third tier rates accordingly to generate approximately
7 25% of residential revenue during the summer period,
8 similar to what the Company currently collects in the
9 summer months. This resulted in the first block being
10 approximately 12% lower than the second tier, and the
11 third tier approximately 20% higher than the second tier.
12 For the non-summer months, I propose that the first block
13 be priced at 90% of the second block, and the last block
14 120% of the second block. I did not change the summer
15 rates for Schedules 4 and 5. The chart below provides a
16 summary of the rates I propose for Schedules 1, 4, and 5.
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CASE NO. IPC-E-08-10
10/24/08
LANSPERY, B. (Di) 16
STAFF
1468
1 IPUC STAFF.Proposed Rates for Idaho Power
2 Schedule i Schedule 4 Schedule 5
3 Non-Sumer
4 1st Block 5.5799 5.5799 5.5799
2nd Block 6.1999 6.1999 6.1999
5 3rd Block 7.4399 7.4399 7.4399
6 Sumer
7 1st Block 5.7792
2nd Block 6.5850
8 3rd Block 7.9020
Energy Watch Rate 20.0
9 Summer kWh 5. 7793
Off-Peak 4.8084
10 Mid-Peak 6.5164
On-Peak 8.8701
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CASE NO.IPC-E-08-10 1469 LANSPERY,B.(Di)16a
10/24/08 STAFF
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1 Q. What is your justification for these
2 differentials?
3 I believe that these differentials result inA.
4 rates that balance the myriad obj ecti ves of effective
5 rate design, namely providing price signals to customers,
6 generating rate stability, and a reasonable opportunity
7 for approved revenue recovery.
8 You do not propose any adjustments to ScheduleQ.
9 4, Energy Watch, or Schedule 5, Time-Of-Use, summer
10 rates?
11 Not at this time. I will note that the rateA.
12 differentials have remained the same since the advent of
13 the pilot programs, and may not reflect the Company's
14 current embedded-marginal cost relationship. In its 2007
15 Annual Report filed in February 2008, the Company states
16 that Energy Watch customers are responding to the price
17 signal sent during event hours, but falls short of
18 acknowledging' whether greater response could be attained
19 through larger rate differentials. The report also
20 states that TOU participants are apparently not shifting
21 load off-peak, which should be a trigger to address the
22 differentials~ Because these are still considered pilot
23 programs, I suggest that these issues be addressed in a
24 different venue than a general rate case.
25 Q. Have you prepared any Exhibits detailing the
rate impact of your recommendations?
CASE NO. IPC-E-08-10
10/24/08
1470 LANSPERY, B. (Di) 17
STAFF
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1 A. Yes. Exhibit No. 135 shows that the rates
2 proposed generate Staff's revenue requirement given the
3 rate design I have outlined above. I have used the
4 energy values provided in Company witness Waites' Exhibit
5 No. 72 to calculate the commodity rates.
6 I have also included Exhibit No. 136 to show
7 the bill impact of my recommendation for residential rate
8 design for Schedule 1 customers, compared to the rates
9 currently in place. Under my proposal, Schedule 1
10 customers will see a decrease in their bills for average
11 annual use less than 1500 kWh compared to current rates.
12 Schedules 4 and 5 customers will see a decrease in their
13 bills for average annual consumption less than 1400 kWh.
14 Do you believe that savings occur at tooQ.
15 generous a level of consumption?
16 I believe this is partly a function of theA.
17 block choice and partly a function of Staff's residential
18 revenue recommendation. Had the first block been set at
19 800 kWh, I would have advocated for a lower first block
20 rate, which would necessitate a larger second and/or
21 third block rate. And since the Staff has recommended
22 that the residential class receive no overall increase to
23 its revenue requirement, I chose to temper the rate
24 differentials at this time for customer acceptance.
25 Has Idaho Power implemented a three-tiered rateQ.
CASE NO. IPC-E-08-10
10/24/08
1471 LANSPERY, B. (Di) 18
STAFF
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1 structure in the past?
2 A. Yes. The Commission approved a three-tiered
3 rate design for Idaho Power in 2001 (Order No. 28722)
4 very similar to what I have proposed here. It was later
5 revoked in 2002 (Order No. 29026).
6 Q.Why did the Commission revoke the three-tiered
7 rate structure?
8 A.The Commission reluctantly returned to the flat
9 rate structure due to a possibility of a large multi-year
10 PCA deferral balance and public sentiment against tiered
11 rates.
12 Q.Do you believe that this is reason enough to
13 prevent the implementation of a three-tiered rate design
14 in this case?
15 A.No. While PCA balances have been fairly large
16 in the recent past, the Company, along with
17 representatives of Staff, IIPA, ICIP and others have
18 engaged in workshops to address the PCA. A properly
19 functioning PCA may alleviate large swings in the
20 deferral balance.
21 Secondly, it is worth noting that rates
22 increased as much as 31% during the period three-tiered
23 rates were in place. It is difficult for a customer to
24 distinguish between bill increases due to rate design
25 modifications and a large, general increase. As pointed
CASE NO. IPC-E-08-10
10/24/08 1472 LANSPERY, B. (Di) 19
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1 out in Order No.29026,only customers consuming over..2 2008 kWh would see an
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CASE NO.IPC-E-08-10 1473 LANSPERY,B.(Di)19a10/24/08 STAFF
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1 increase in their bill when compared to a flat rate. If
2 customers were properly educated by the Company, there
3 may have been a better understanding as to the causation
4 of the bill increase. Also, the Commission noted that
5 many residential customers with high usage were being
6 improperly metered due to non-residential facilities,
7 such as barns and outbuildings, not being metered under
8 general service. Presumably, the Company has addressed
9 this issue.
10 Since Staff is proposing no rate increase for
11 the residential class, the compounding effects that were
12 wi tnessed in 2002 are irrelevant in this proceeding. The
13 Company has maintained a two-tiered structure, and to my
14 understanding' has not received the same level of customer
15 dissatisfaction expressed in the aforementioned case. It
16 is imperative that the Company utilize resources to
17 educate customers about the change in rate design, what
18 can be done to reduce consumption, and how this can
19 prepare the customer for TOU rates in the near future.
20 Finally, and perhaps most importantly, on page
21 26 of Order No. 29026, the Commission explicitly states
22 that:
23 Although it is appropriate to use flat
residential rates this year, this Order
should not be interpreted as precluding
the use of tiered rates in the future. We
believe that last year's tiered rates were
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CASE NO. IPC-E-08-10
10/24/08
1474 LANSPERY, B. (Di) 20
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1 effecti ve in sending a price signal to
customers to conserve. However, many of
these customers experiencing an increase
of 31% or more had limited ability to
significantly alter their energy consumption
2
3
4
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
CASE NO. IPC-E-08-10
10/24/08
1475 LANSPERY, B. (Di) 20a
STAFF
.
.
.
1 once they received the price signal. It is
our belief that with additional customer
education and increased availability of
residential DSM programs like Time-of-Use
metering, tiered residential rates may be
an appropriate rate design option in the
future as circumstances dictate.
2
3
4
5 Wi th advanced metering around the corner, I believe that
6 this is the proper time for the Company to revisit a
7 three-tiered rate structure.
8 Schedule 24 Rate Design
9 Q.Have you reviewed the Company's proposal for
10 Schedule 24, Agricultural Irrigation Service?
11 A.Yes.
12 Q.Could you please summarize the Company's
13 recommendations?
14 A. Yes.In Company witness Bowman's testimony,
15 she proposes "load factor" pricing for Schedule 24
16 customers during the summer period. Load factor pricing
17 is based on the ratio of energy consumed and peak demand
18 in a billing period. A higher load factor indicates
19 efficient energy usage and right sizing of equipment.
20 The Company proposes a two-tiered price structure in
21 which the first applies to usage at or below 164 kWh per
22 kW and a lower rate for usage above that threshold.
23 Does Staff support this change in billingQ.
24 structure?
25 A.Yes. In keeping with the theme of encouraging
CASE NO. IPC-E-08-10
10/24/08
1476 LANSPERY, B. (Di) 21
STAFF
.
.
.
1 energy efficiency through rate design, load factor
2 pricing for irrigation customers is a proper tool. Idaho
3 Power would be the second utility in Idaho (Avista) that
4 uses this pricing mechanism for irrigators.
5 Q.What rate differential does the Company propose
6 in this proceeding?
7 A.For the second tier, representing higher load
8 factor, the Company proposes a 3% decrease in the energy
9 rate.
10 Q.Does Staff support this differential?
11 A.At this time, yes, though I would consider this
12 an introductory level differential at best. Agricultural
13 irrigation can be a capital intensive endeavor, and
14 setting the initial differentials aggressively may unduly
15 harm a significant share of customers. By sending the
16 message that efficient use of equipment will be rewarded,
17 customers can, over time, properly size equipment to meet
18 its operational demands and benefit from lower rates. I
19 encourage the Company and IIPA, with the Staff's
20 assistance, to further develop this rate design to
21 achieve its prescribed goals.
22 Q.You mentioned before that tiered rates act as
23 an excellent surrogate for TOU rates. Is that also the
24 case for irrigation customers?
25 A.Yes I believe so. While tiered rates address
CASE NO. IPC-E-08-10
10/24/08
LANSPERY, B. (Di) 22
STAFF
1477
.
.
.
1 the magnitude of usage, TOU rates address the timing of
2 usage. This is especially important for a class such as
3 irrigators, who as a whole tend to have the highest usage
4 during the most expensive periods to serve load.
5 Q.Has the Company previously offered TOU rates
6 for Schedule 24 customers?
7 A.Yes. The Company recently had a pilot program
8 that offered optional TOU rates to irrigators under
9 Schedule 25. The pilot program terminated in September
10 2007. The Company has stated that with the rollout of
11 advanced meters throughout its service terri tory, it is
12 able to avoid costly metering equipment that would soon
13 be obsolete. Once the AMI system is fully rolled out, I
14 would anticipate TOU rates to again be offered to
15 irrigation customers.
16 Q.What is Staff's recommendation for Schedule 24
17 revenue requirement?
18 Based on Staff witness Hessing's Cost ofA.
19 Service results, the irrigation class revenue requirement
20 is $80,822,001, or 4.9% above current class revenue.
21 Q.How do you propose to spread the 4.9% increase
22 to Schedule 24 customers?
23 A.I recommend that the service charge be
24 increased 5%, from $15.00 to $15.75. I also recommend
25 that the demand charge be increased approximately 4.9%,
from $4.67
CASE NO. IPC-E-08-10
10/24/08 1478 LANSPERY, B. (Di) 23
STAFF
.
.
.
18
20
21
22
23
24
25
1 to $4.90. I propose increasing the non-summer energy
2 rate 4.9%, and the summer low load factor and high load
3 factor rates 6.9% and 3. 7% , respectively.
4 Q.Have you prepared an Exhibit demonstrating that
5 the proposed rates generate the recommended revenue for
6 Schedule 24?
7 A.Yes. Exhibit No. 137 confirms that the rates I
8 propose generate sufficient revenue given the Company's
9 billing determinants.
10 Q.Does this conclude your direct testimony in
11 this proceeding?
12 A.Yes, it does.
13
14
15
16
17
19
CASE NO. IPC-E-08-10
10/24/08
1479 LANSPERY, B. (Di) 24
STAFF
.
.
.
1
2 open hearing.)
(The following proceedings were had in
MR. PRICE: I now present this witness for
4 cross-examination.
3
5
6 Mr. Ward.
7
8
9
10
11
12
13
14 Madam Chair.
COMMISSIONER SMITH: Thank you.
MR. WARD: No questions. Thank you.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: I will pass. Thank you.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Just a couple,
CROSS-EXAMINATION
18 BY MR. RI CHARDSON :
19
15
16
17
Q Mr. Lanspery, will you turn to page 7 of
20 your direct testimony?
21
22
A
Q
Yes.
There you state that pricing in setting
23 prices too high, there's a significant risk that the
24 Company would be unable to collect its
25 Commission-approved costs, and that's at lines 15 to 17.
CSB REPORTING
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1480 LANSPERY (X)
Staff
.
.
.
1 A Correct.
2 Q Would you agree that revenue erosion
3 through demand curtailment during high cost periods is a
4 natural consequence of an effective rate design?
5 A I would agree with that.
6 Q And have either the Staff or, to your
7 knowledge, the Company considered the elasticity impact
8 on Company revenue in their rate design proposals?
9 A I did ask if the Company did any price
10 elastici ty studies, they said they did not. I haven't
11 done any on my own.
12 Q Okay, thank you. Would you agree that a
13 truly effective rate design would have to have by
14 necessi ty an impact, that would need to be adj usted for
15 its impact on consumption and thus revenues?
16 A I'm sorry, could you repeat that, please?
17 Q Yeah, I kind of muddled that, didn't I?
18 Would you agree that a truly effective rate design
19 proposal would need to account for its impact on
20 consumption and thus revenues?
21 A Yes, I believe that it would.
22 MR. RICHARDSON: Okay. Thank you, Mr.
23 Lanspery. That's all I have, Madam Chair.
24 COMMISSIONER SMITH: Okay, Mr. Bruder, do
25 you have questions?
CSB REPORTING
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1481 LANSPERY (X)Staff
.
.
.
1 MR. BRUDER: We have no questions,
2 Madam Chairman.
3 COMMISSIONER SMITH: Mr. Walker.
4 MR. WALKER: Thank you.
5
6 CROS S - EXAINAT I ON
7
8 BY MR. WALKER:
9 Q Good afternoon.
10 A Good evening.
11 Q Yes, it is. Well, just in a broad sense,
12 the goals that you tried to accomplish with your rate
13 design, those' are the same goals that the Company and the
14 Company's witness Waites testified that she had with
15 hers; is that a fair statement?
16 A I do believe there's some overlap. I
17 think I believe that my testimony states a few more
18 goals than what was in the Company's filing.
19 Q On page 2 of your testimony, lines 17
20 through 20, you agree an effective rate design is based
21 on sending cO$t-based price signals that promote
22 efficient consumption.
23
24
25
A Yes.
Q Those were the same two basic goals that
Company witness Waites said she had in mind when creating
CSB REPORTING
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1482 LANSPERY (X)Staff
.
.
.
1 a residential rate design?
2 A That is what she said.
3 Q And both you and the Company's proposal,
4 both the Staff's and the Company's proposal, for
5 residential rate design is based on a tiered rate design.
6 Obviously, one has three tiers and the other one has two
7 wi th some different break points, but it's the same
8 general idea? On a broad policy-based conceptual idea,
9 it is the same that we're trying to get at here?
10 A In a sense, yes. I think that the
11 difference between a two-tiered rate structure and a
12 three-tiered rate structure as far as accomplishing
13 energy efficiency goals, sending proper price signals,
14 there is a big difference.
15 Q Well, sure, but it's not like we're saying
16 we want, you know, one side is saying we want a flat fee
17 no matter what and the other -- you know, they're pretty
18 close, same general principles?
19 A Tiered rates in general are considered
20 energy efficiency or an efficient rate design.
21 Q And also one of the directives from did
22 Mr. Lobb give you any direction, policy direction, in
23 coming up with your residential rate design?
24
25
A I think the course of events was I
discussed the three-tiered rate design with both Mr. Lobb
CSB REPORTING
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1483 LANSPERY (X)Staff
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.
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1 and my immediate supervisor David Schunke and we came to
2 an agreement that a three-tiered structure would be a
3 proper proposal in this case.
4 Q In Mr. Lobb' s testimony on page 21, lines
5 10 through 12, he states that Staff simply believes that
6 we can and should do more to send the most appropriate
7 price signal to as many residential customers as
8 possible. Are you familiar with that?
9 A I do remember reading that line.
10 Q And did you take that into consideration
11 when you recommended the 1,000 kilowatt break point in
12 your rate design?
13 A That was in my mind when coming up with
14 both the 1,000 kilowatt-hour break point and the summer
15 and non-summer second-tier break point.
16 Q To send the most appropriate signal to as
17 many customers as possible?
18 A Yes.
19 Q And isn't it true that a first tier that
20 breaks at 1,000 kilowatts that during the summer months
21 approximately 57 percent of the Company's customers would
22 be below that. break point?
23 A Based on the bill frequency analysis that
24 was provided to us by the Company, July and August we're
25 looking at about 50 percent. June is a bit higher at 68
CSB REPORTING
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1484 LANSPERY (X)Staff
.
.
.
20
1 percent, but I am not sure if the bill frequency analysis
2 is adjusted for monthly usage or if we're capturing some
3 of May usage in June's bill.
4 Q And if we looked at all the non-summer
5 months, would you agree that approximately 59 percent of
6 all Idaho Power customers would have all of their usage
7 under that 1,000 kilowatt first block?
8 A I would think if you looked at all
9 non-summer months and averaged them together, that might
10 be a rough approximation.
11 Q And that's a general categorization of
12 seasons for Idaho Power's system would be summer and
13 non-summer; would that be fair?
14 A Yes.
15 Q And so if you looked at each one of those
16 separately, more than half, approaching 60 percent, of
17 the customers would be below, entirely below, the 1,000
18 kilowatts.
19 A Correct.
Q And you're aware, aren't you, that July is
21 right in the middle of the summer period, one of the most
22 expensi ve periods to provide electricity to customers?
23
24
25
A Certainly.
Q And that Ms. Waites testified that in July
'07 and July '08, both of those months had average usage
CSB REPORTING
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1485 LANSPERY (X)Staff
.
.
.
1 that was 925 and 922 , respectively; do you disagree with
2 that?
3 A I don't disagree that she testified to
4 that. I do disagree with the numbers that she quoted.
5 As she stated in her testimony, those numbers came from
6 the FCA reports. Those energy totals are weather
7 normalized. If you looked at the bill frequency
8 analysis, the one that she quotes that May and October
9 usage is 806 and 838 kilowatt-hours, respectively, the
10 average energy consumption for residential is 1,086.
11 Q If the Commission were to, hypothetically
12 the Commission were to, decide that a two-tier rate was
13 what it wished to select for the residential class, do
14 you think that Staff's proposal or do you think that the
15 Company's proposal was a reasonable one given the
16 constraint of a two-tier design? Do you think it was
17 fair?
18 A In all honesty, I didn't really put a lot
19 of thought into validating or justifying the two-tiered
20 system. If the Commission decides to go with a
21 two-tiered system, then I would leave it up to them to
22 decide what the proper break points would be.
23 Q Is there anything just patently unfair on
24 its face in what the Company has proposed?
25 A I would say that it's better than what's
CSB REPORTING
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1486 LANSPERY (X)Staff
.
.
.
20
1 currently in place.
2 MR. WALKER: That's all I have. Thank
3 you.
4 COMMISSIONER SMITH: Do we have questions
5 from the Commission? Commissioner Kempton.
6 COMMISSIONER KEMPTON: Thank you,
7 Madam Chairman.
8
9 EXAINATION
10
11 BY COMMISSIONER KEMPTON:
12 Q In your proposal in your description --
13 let me go back to a question that was asked here a few
14 minutes ago and it had to do with elasticity. It's a
15 fairly interesting area to examine. Would you explain
16 what elasticity is in terms of tiered rates?
17 A In the general sense, elasticity is a
18 measure of how responsive customers are to changes in
19 price.
Q In the consideration of where you wanted
21 to put your break point in kilowatt-hours, on page 11 on
22 line 18 you say, "As I stated before, I consider heating
23 and cooling to be basic needs for residential customers."
24 Is that a distinct difference between your proposal and
25 the Idaho Power proposal?
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1487 LANSPERY (Com)Staff
.
.
.
1 A Yes, I think that is definitely a big
2 difference. They spent much time defining what they
3 considered basic usage. My definition of basic usage
4 does differ quite a bit from what the Company posits.
5 Q Have you by any chance read the Idaho
6 energy plan?
7 A I can't say that I have.
8 Q Are you aware in the encouragement of the
9 legislature for the Commission to consider tiered rates
10 the provision for consideration also of homes with
11 central heat that's all electric?
12 A Again, I'm not quite aware of that.
13 Q In including your considerations for a
14 home heated by electricity, would you consider those
15 homes to be above generally the 600 kilowatt-hour
16 break?
17 A Certainly during the heating months, you
18 would find that electric space heating, well, space
19 heating in general, is an expensive endeavor and energy
20 intensi ve. That was one of the reasons or the rationales
21 for having a larger second tier in the non-summer months
22 than in the summer months.
23 Q And moving to 1,000 away from the proposal
24 by Idaho Power of 6bO as a break point?
25 A Yes. I would consider having some level
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1488 LANSPERY (Com)Staff
.
.
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1 of heating captured in that first block, that first tier,
2 to be reasonable.
3 COMMISSIONER KEMPTON: I have no other
4 questions.
5 COMMISSIONER REDFORD: I have none.
6 COMMISSIONER SMITH: Do you have redirect?
7 MR. PRICE: Just one question.
8
9 REDIRECT EXAMINATION
10
11 BY MR. PRICE:
12 Q Mr. Walker talked about whether or not in
13 your opinion Idaho Power Company's proposal for a
14 two-tiered rate system for residential customers is fair.
15 What was your goal in developing the three-tiered system
16 versus the two-tiered system?
17 A The rationale for going with a
18 three-tiered system as opposed to a two-tiered system,
19 there are actually many different facets of it, one of
20 which is that by going to a three-tiered system, you get
21 to send more price signals to reach more customers. The
22 Company's proposal having a tiered rate at 600
23 kilowatt-hours, well below the average, doesn't really in
24 my opinion affect the customers that are using 2,000,
25 3,000 kilowatt-hours a month. They're long past that
CSB REPORTING
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LANSPERY (Di)Staff1489
.
.
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1 tiered break wi thin the first week.
2 The other consideration is that we do have
3 customers that would qualify as low income customers that
4 may fall into the high energy usage category. We don't
5 want to unduly burden any customer class or any subset of
6 customers under a rate design proposal. We do still want
7 to be able to send a proper price signal, though, so you
8 have to moderate both your decision on tier breaks and
9 the rate differentials between the tiers by keeping in
10 mind that there are customers that are going to be
11 affected both positively and negatively.
12
13
14
MR. PRICE: Thank you. That's all I have.
COMMISSIONER SMITH: Thank you, Mr.
Lanspery.
15 (The witness left the stand.)
16 MR. PRICE: Staff now calls Mr. Matt Elam.
17
18
19
20
21
22
23
24
25
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1490 LANSPERY (Di)Staff
.
.
.
1
2
MATTHEW ELAM,
produced as a witness at the instance of the Staff,
3 having been first duly sworn, was examined and testified
4 as follows:
5
6
7
8 BY MR. PRICE:
9 Q
Q
Q
DIRECT EXAMINATION
Can you please state your name?
Matthew Elam.
And who is your employer?
The Public Utilities Commission.
And what is your job title at the
Utilities analyst.
And did you have occasion on October 24th
17 of this year to prepare written testimony for this
10 A
A
Q
A
Q
I did.
Did that include Exhibits 138 through
That's correct.
And I believe you have quite a few changes
24 to note for the record. What are those changes?
11 Q
A I do. They are in regards to the exhibits
12 A
13
14 Commission?
15 A
16
18 case?
19
20
21 142?
22
23
25
CSB REPORTING
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1491 ELAM (Di)Staff
.
.
.
1 that were cited in my testimony and those not
2 corresponding to the exhibits that are shown at the back,
3 the exhibit numbers, so I'll go through them one at a
4 time. On page 3, line 13, I'm striking "Exhibits 1
5 through 5" and replacing it with "Exhibits 138 through
6 140 and Exhibit 142." On page 4, line 8, strike the
7 "small" and replace it with "there is no."
8 COMMISSIONER KEMPTON: With what?
9 THE WITNESS: There is no change. On page
10 5, line 20, strike "Exhibit No.1" and replace it with
11 "Exhibit No. 138."
12 COMMISSIONER SMITH: Could we please go
13 back to page 4, line 8?
14 THE WITNESS: That's strike the "small."
15 COMMISSIONER SMITH: Could you just read
16 how the sentence is supposed to read, please?
17 THE WITNESS: Sure; so the sentence
18 currently reads, "However, I recommend that the customer
19 charge for this class remain unchanged given the small
20 increase in class revenue requirement proposed by Staff."
21 The correct way that it should read is, "However, I
22 recommend that the customer charge for this class remain
23 unchanged given there is no increase in class revenue
24 requirement proposed by Staff."
25 Q BY MR. PRICE: Then on page 5, if you
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1492 ELAM (Di)Staff
.
.
.
20
1 could start with the first word of the sentence and the
2 line number.
3 A All right, it's page 5, line 20.
4 Q First word there, please.
5 A I'm going to it here, so it would be
6 "Schedule 7" or "Schedule" would be the first word.
7 Q And what's your correction?
8 A "Exhibit No. 138." And then on page 7,
9 line 6, starting with "Exhibit," change that to "Exhibit
10 No. 139," and going to page 14 on lines 1 and 2, the
11 first word on line 1 is "and" and if you could switch
12 that with "Exhibit No. 140" and on page 16, line 19,
13 starting with "attached," change that to "Exhibit No.
14 141," and on page 17, line 9, starting with "metered,"
15 change that from "Exhibit No.5" to "Exhibit No. 142,"
16 and I apologize for those changes.
17 Q Is that all the corrections that you have
18 at this time?
19 A That is.
Q Okay. With that said, if I were to pose
21 to you the same questions contained in your written
22 direct testimony today, would your answers be the same?
23
24
25
A They would.
MR. PRICE: Okay, I would move that
Mr. Elam' s testimony with the corrections be spread upon
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1493 ELAM (Di)Staff
.
.
.
1 the record as if read.
2
3
4 142.
5
COMMISSIONER SMITH: So ordered.
MR. PRICE: Including Exhibits Nos. 138 to
COMMISSIONER SMITH: And Exhibits 138 to
6 142 will be identified for the record.
7 (The following prefiled direct testimony
8 of Mr. Matthew Elam is spread upon the record.)
17
18
19
20
21
22
23
24
25
9
10
11
12
13
14
15
16
CSB REPORTING
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1494 ELAM (Di)Staff
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.
.
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Matthew Elam. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission (Commission) as a Utilities Analyst in the
8 Engineering Section of the Utili ties Division.
9 Q.What is your education and experience?
10 A.I graduated from Boise State Uni versi ty earning
11 a Bachelor of Arts degree in Economics. Following this I
12 worked for Albertson's as a Business Analyst in Finance
13 and Corporate Planning before transitioning to Research
14 and Market Analysis. My primary duties included
15 demographic profiling, modeling, and demand forecasting
16 for the purposes of determining ROIC (Return on Invested
17 Capi tal). Following this I accepted a Business Analyst
18 posi tion working in a similar capacity for geoVue Inc.
19 where I would later be promoted to a Senior Business
20 Analyst and Modeler.
21
22
23 /
24 /
25
Q.What is the purpose of your testimony?
A.Under the direction of Randy Lobb, Utilities
/
CASE NO. IPC-~-08-10
10/24/08
1495 ELAM, M. (Di) 1
STAFF
.
.
.
1 Administrator, I will discuss the Company's rate design
2 proposals for Schedule 7, Schedule 9, Schedule 19,
3 Lighting Schedules, and the Non-metered Schedule 40 and
4 provide my rate recommendations based on the Staff
5 revenue requirement recommendation for each class.
6 Q.Please summarize your testimony in this case.
7 A.I fully support the Company's rate design
8 proposals to( 1) add a block rate on the energy charge
9 during the non-summer time period for Schedule 7, (2) add
10 time-of-use (TOU) rates to customers taking service at
11 the Primary and Transmission level for Schedule 9, and
12 (3) increase the differentials between the On-Peak,
13 Mid- Peak, and Off-Peak Energy Charges during the summer
14 and non-summer seasons for Schedule 19 customers. With
15 the exception to maintain current Schedule 7 customer
16 charges, I further agree with the Company's proposed rate
17 component differentials adjusted for the Staff proposed
18 revenue requirement for each class.
19 I also agree with the Company's proposal that
20 Schedule 9 not include a "phase-in" period of shadow
21 billing for the proposed TOU rates.
22 Q.What are Staff's obj ecti ves in evaluating rate
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08
ELAM, M. (Di) 2
STAFF
1496
.
.
.
1 design?
2 A.Staff's obj ecti ves are that rates recover the
3 revenue requirement of each customer class based on the
4 class revenue requirement recommendations of Staff
5 witness Keith Hessing; send an appropriate cost based
6 price signal to customers encouraging the wise and
7 efficient use of energy; provide rate stability and avoid
8 unnecessary complexity.
9 Q.Do you have exhibits illustrating the Schedules
10 wi th your proposals?
11 A.Yes, they are provided as Exhibits 138-140 and
12 Exhibi t 142.
13 SMAL GENERA SERVICE, SCHEDULE 7
14 Q. What rate design does the Company recommend for
15 Schedule 7?
16 A.The Company is proposing to (1) increase the
17 Energy Charges, (2) increase the Service Charge, (3)
18 increase the summer differential between the first block
19 and the second block, and (4) add a block rate on the
20 energy charge during the non-summer time period that has
21 a lower differential than summer.
Q.Do you agree with the Company's proposed rate22
23 design changes?
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1497 ELAM, M. (Di) 3
STAFF
.
.
.
1 A.Yes, I agree with the increase in summer
2 differential between the first block and second block,
3 and to add a non-summer tiered block rate as adjusted for
4 Staff's class cost of service revenue requirement that
5 does not increase for Schedule 7. However, I recommend
6 that the customer charge for this class remain unchanged
7 given there is no increase in class revenue requirement
8 proposed by Staff. I believe tiered block rates are a
9 reasonable surrogate to TOU rates and send a message to
10 reduce demand and encourage the efficient use of energy.
11 In addition they more accurately assign the cost
12 associated with providing increased supply to customers
13 wi th higher usage.
14 Q. What are your specific recommendations for
15 Schedule 7?
16 A.I am recommending that (1) the service charge
17 be maintained at $4.00 and the minimum service charge
18 stay at $2.00, (2) the energy rate for the first 300kWh
19 decrease by 3.44% to .067860/kWh in the summer and
20 non-summer, and (3) the energy rate in excess of 300kWh
21 increase by 2.05% to .080781/kWh in the summer and
22 increase by 2.052% to .071722/kWh in the non-summer.
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1498 ELAM, M. (Di) 4
STAFF
.
.
.
1 This rate design is comparable to the Company proposal
2 with respect to block sizes and rate differentials.
3 Q.Why is Staff proposing a two block rate design
4 instead of a three block rate design as proposed for the
5 residential class?
6 A.The unique characteristics of Schedule 7
7 customers tend to be less homogeneous when compared to
8 the Residential Schedules and therefore make it difficult
9 to define the potential third block baseline usage. In
10 addi tion, the concentration of a high percentage of
11 customer consumption in the first block, the Company's
12 proposal for a non-summer tiered rate differential of
13 5.69%, and the increase of 6.41% to the current summer
14 differential add a sufficient cost based price signal for
15 this class to provide incentive for customers to conserve
16 and use energy efficiently. My rate recommendations for
17 Schedule 7 are shown on Staff Exhibit No. 138.
18 LAGE GENERA. SERVICE, SCHEDULE 9
19 Q.What rate design does the Company recommend for
20 Schedule 9?
21 A.The Company is proposing to (1) increase the
22 Energy Charges, (2) increase the Service Charge, (3)
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1499 ELAM, M. (Di) 5
STAFF
.
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11
1 increase the Basic Charges, (4) increase the Demand
2 Charges differential between the Secondary Service summer
3 and non-summer second block, (5) increase the
4 differential between the Primary and Transmission
5 non-summer and summer Demand Charges, (6) add a summer
6 On-Peak Demand Charge to Primary and Transmission
7 Services, and (7) add mandatory TOU rates to customers
8 taking Primary and Transmission Service.
9 Q.Do you agree with the Company's proposed rate
10 design changes?
A.Yes, I agree with the design component changes
12 recommended by the Company as adj usted for Staff's class
13
14
cost of service revenue requirement increase of 0.60%.
However, I recommend that the customer charge for the
15 secondary service class remain unchanged given the small
16 increase in class revenue requirement proposed by Staff.
17 My rate design proposal attempts to maintain the same
18 billing determinant spreads and relationships as those
19 proposed by the Company. I also agree with the Company's
20 TOU rate proposal as adjusted for Staff's revenue
21 requirement. As previously stated, I believe time of use
22 is the most efficient way to accurately assign the costs
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1500 ELAM, M. (Di) 6
STAFF
.
.
.
1 of providing services and send a cost-based price signal
2 to customers encouraging the wise and efficient use of
3 energy. My rate recommendations for Schedule 9 Primary,
4 Secondary and Transmission service are shown on Staff
5 Exhibit No. 139, pages 1, 2 and 3, respectively.
6 Q.How did you evaluate the TOU differentials
7 associated with Schedule 9 and the potential impact on
8 load shifting?
9 A.I utilized the Schedule 19 historical
10 time-of-use data implemented in Order No. 29547 to
11 determine how' the demand ~or energy shifted to different
12 times given the price structure movement from a
13 tradi tional rate design to a TOU rate design. By
14 analyzing this load shifting along with the embedded
15 differentials. following the implementation of TOU rates,
16 I gained insight into how sensitive customers may be to
17 TOU rates. This provides more insight in evaluating the
18 potential impact of changing TOU rate differentials.
19 Q.How. does this provide insight into how the
20 Schedule 9 TOU rate design differentials should be
21 structured?
22 A.It is reasonable to analyze the Schedule 19
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08
ELAM, M. (Di) 7
STAFF
1501
.
.
.
1 historical data in order to evaluate how the mandatory
2 change from a traditional rate design to a TOU design
3 impacted customers' usage given the price signals
4 associated with the differentials. This is done by
5 evaluating how customers shifted load between Off-Peak,
6 Mid-Peak, and On-Peak. The reaction of customers, or the
7 shift in usage, provides insight into how the historical
8 differentials may have changed usage patterns.
9 Once the customers' sensitivity toward these
10 changes has been evaluated, Staff can more accurately
11 determine the best structure for TOU rates.
12 Q.How did you utilize the sensitivity analysis
13 from the Schedule 19 historical data to evaluate the
14 reasonableness of the differentials included in the
15 proposed Schedule 9 TOU rate design?
16 A.I reviewed the average differentials associated
17 with the Schedule 19 Primary and Transmission services
18 directly following December 1, 2004. The average
19 Mid-Peak to On-Peak differential was 10.70 percent, the
20 average Summer Off-Peak to Summer Mid-Peak differential
21 was 7. 23 perc~nt, and the average Non-Summer Off-Peak to
22 Non-Summer Mid-Peak was 4. 77 percent. The Company is
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1502 ELAM, M. (Di) 8
STAFF
.
.
.
1 currently proposing Schedule 9 introductory TOU
2 differentials averaging a 9.81 percent difference between
3 Mid-Peak and On-Peak, a~ average Summer Off-Peak to
4 Summer Mid-Peak of 6.94 percent, and an average
5 Non-Summer Off-Peak and Non-Summer Mid-Peak of 4.07
6 percent. When these past Schedule 19 differentials are
7 compared to the Company's proposed Schedule 9
8 differentials, the proposed Schedule 9 differentials are
9 slightly lower. According to my analysis, the historical
10 price signals indicated by the differentials yielded a
11 very minor load shift change following the implementation
12 of the Schedule 19 TOU rates.
13 Q. What Schedule 19 historical time frame did you
14 look at to determine the strength of the price signal?
15 A.I analyzed hourly usage data from Schedule 19
16 for 12 months prior to the implementation of TOU rates
17 and 24 months following TOU rates as approved in Order
18 No. 29547.
19 Q.Did you analyze all the Schedule 19 customers
20 prior to December 1, 2004 and compare them to all the
21 customers following December 1, 2004?
22 A.No, I utilized a sample set of Schedule 19
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1503 ELAM, M. (Di) 9
STAFF
.
.
.24 /
25
1 customers by eliminating those with an incomplete range
2 of data. Therefore, customers shifting between Schedules
3 and those completely adding or dropping service
4 throughout the time range were removed. This effectively
5 eliminated as much noise as possible in determining the
6 usage pattern associated TOU rates.
7 Q.Did the differentials associated with Schedule
8 19 change from additional rate cases within the 24 month
9 time frame following the December 1, 2004 implementation
10 of TOU rates?
11 A.Yes, the differentials did change slightly
12 within the 24 month time frame following the December 1,
13 2004 implementation of TOU rates. However the percentage
14 difference between differential changes was very minor,
15 no more than a 3.15 percent difference for all non-summer
16 and summer Primary and Transmission Service TOU
17 categories.
18 Q.Do you feel that given your sensi ti vi ty
19 analysis the Company's proposed Schedule 9 differentials
20 are reasonable and provide customers an opportunity to
21 adjust to the TOU rate design?
22 A.Yes, the differentials proposed by the Company
23 /
/
CASE NO. IPC-E-08-10
10/24/08 1504 ELAM, M. (Di) 10
STAFF
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1 and supported by Staff for Schedule 9 are reasonable
2 because they are less than the Schedule 19 time-of-use
3 start point differentials which yielded little change in
4 load shifting behavior. This is not to say Schedule 9
5 customers will react in exactly the same way as Schedule
6 19 customers have, however the Company's proposal
7 represents a reasonable starting point for evaluating
8 future load shifting behavior.
9 Q.Do you agree with the Company's proposal not to
10 include a "phase-in" period of shadow billing for the
11 Company's proposed Schedule 9 TOU rates?
12 A.Yes , given the limited changes observed in the
13 sensi ti vi ty analysis to the Schedule 19 usage patterns
14 following implementation of TOU rates and the Company's
15 proposed customer education plan, I do not believe a
16 "phase-in" period is necessary. In response to Staff's
17 Production Request No. 49, the Company states, "The
18 addi tional administrative cost of providing shadow bills
19 to Schedule 9 customers for six months is estimated to be
20 about $100,000. The added cost results because there is
21 no automated process to provide these bills ; it is a
22 manual process both in the metering and billing areas."
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1505 ELAM, M. (Di) 11
STAFF
.
.
.
1 This additional cost is not necessary in this case given
2 that the Company is implementing a customer communication
3 and education plan prior to the implementation of rates.
4 If managed correctly and proactively this comprehensive
5 approach would cut costs, eliminate the confusion of
6 customers receiving multiple bills, and maintain
7 effectiveness.
8 LAGE POWER SERVICE, SCHEDULE 19
9 Q.What rate design does the Company recommend for
10 Schedule 19?
11 A.The Company is proposing to (1) increase the
12 Energy Charges, (2) increase the Service Charge, (3)
13 increase the Basic Charges, (4) increase the differential
14 between the summer and non-summer Demand Charges, and (5)
15 increase the differentials between the On-Peak, Mid-Peak,
16 and Off-Peak Energy Charges during the summer and non-
1 7 summer season.
18 Q.Do you agree with the Company proposed rate
19 design changes?
20 A.Yes, I agree with the design component
21 recommendations of the Company as adjusted for Staff's
22 class cost of service revenue requirement increase of
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1506 ELAM, M. (Di) 12
STAFF
.1 4.90%. However, I recommend that the customer charge for
2 the secondary service class remain unchanged given the
3 small increase in class revenue requirement proposed by
4 Staff. Consistent with my proposal for Schedule 9, my
5 rate design proposal for Schedule 19 attempts to maintain
6 the same billing determinant spreads and relationships as
7 those proposed by the Company. I also agree with the
8 Company's proposal to increase differentials between the
9 On-Peak, Mid-Peak, and Off-Peak Energy Charges during the
10 summer and non-summer season TOU rates. However, I also
11 understand that there are a range of reasonable
12 differentials that could be accepted by the Commission.13 between the On-Peak, Mid-Peak, and Off-Peak TOU rates.
14 Throughout my testimony I have consistently maintained
15 that TOU rates better align the rate with costs of
16 increased power supply and encourages load shifting by
17 providing an economic signal that energy is more costly
18 during the peak hours of the day and the summer season.
19 The customers who use the most energy during On-Peak
20 should be assigned higher costs than those who shift load
21 to Mid-Peak or naturally use less during On-Peak. My
22 rate recommendations for Schedule 19 Primary, Secondary
23 /
24 /.25 /
CASE NO. IPC-E-08-10
10/24/08 1507 ELAM, M. (Di) 13
STAFF
.
.
.
1 and Transmission service are shown on Staff Exhibit No.
2 140, pages 1, 2 and 3, respectively.
3 Q.Which component of the Company's Schedule 19
4 rate design proposal do you plan to address with the
5 sensitivity analysis described previously?
6 A.I will address the Company proposal to increase
7 rate differentials in the TOU rates. As described
8 earlier this sensi ti vi ty analysis provides insight into
9 how the Schedule 19 customer's have behaved historically
10 given TOU rates, and whether the Company's proposed
11 differential request is reasonable.
12 Q.How can you compare the historical Schedule 19
13 TOU differentials to the current Schedule 19
14 differentials and determine whether the Company's
15 proposed differential increases are necessary?
16 A.The Schedule 19 average differentials
17 associated with the TOU rates 24 months following their
18 implementation were 8.87 percent between Mid-Peak and
19 On-Peak, 7.23 percent between Summer Off-Peak and Summer
20 Mid-Peak, and' 4.74 percent between Non-Summer Off-Peak
21 and Non-Summer Mid-Peak. The average TOU differentials
22 currently approved by the Commission in rates are 8.94
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1508 ELAM, M. (Di) 14
STAFF
.
.
.
1 percent between Mid-Peak and On-Peak, 7.29 percent
2 between Summer Off-Peak and Summer Mid-Peak, and 4.79
3 percent between Non-Summer Off-Peak and Non-Summer
4 Mid-Peak. Given that these differentials have changed
5 little since the implementation of TOU rates it is
6 reasonable to use them in determining how effective they
7 have historically been in sending a price signal and
8 shifting time of consumption. Once this analysis has
9 been made it is possible to associate the historical
10 magni tude of the differential with the Company's proposed
11 price differentials and estimate whether the differential
12 seems reasonable to encourage Schedule 19 customers to
13 shift load.
14 Q.Based on your sensi ti vi ty analysis, how
15 effective do you think the current Schedule 19
16 differentials have been in modifying usage?
17 A.When analyzing the historical effect of TOU on
18 Schedule 19 energy consumption during all months, summer
19 months, and non-summer months, I found very little load
20 shifting from On-Peak to Mid-Peak, and Mid-Peak to
21 Off-Peak.
22 Q.Based on your sensitivity analysis do you think
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1509 ELAM, M. (Di) 15
STAFF
.
.
.
1 the Company's proposal to increase its Schedule 19
2 differentials is necessary?
3 A.Yes, since the current differentials are nearly
4 identical to those implemented at the beginning of
5 time-of-use rates and given that the sensi ti vi ty analysis
6 indicates load shifting was minor, I conclude that the
7 differentials should be increased. However, I also
8 understand that there are a range of reasonable
9 differentials that could be accepted by the Commission
10 between the On-Peak, Mid-Peak, and Off-Peak TOU rates.
11 Addi tionally, in response to Staff's Production Request
12 No. 50, the Company provides an "On-Peak/Off-Peak TOU
13 Energy Charge Rate Differentials" summary that outlines
14 what other utilities in the nation are currently using
15 for Large Commercial and Industrial differentials
16 (attached as Staff Exhibit No. 141). This further
17 emphasizes the Company's request is within reason.
18 LIGHTING AN NON-METERED SCHEDULES
19 Q.What change in revenue requirement do you
20 recommend for the Lighting and Non-Metered Schedules?
21 A.I recommend an overall increase of 4.90% to the
22 Traffic Control Lighting Schedule 42. All the remaining
23 /
24 /
25 /
CASE NO. IPC-E-08-10
10/24/08 1510 ELAM, M. (Di) 16
STAFF
.
.
.
20
21
22
23
24
25
1 Lighting and Non-Metered Schedules have no increase in
2 revenue based on Staff's recommended revenue requirement.
3 Q.Are you proposing any rate design changes to
4 the Company's proposed Lighting and Non-Metered
5 Schedules?
6 A.No, I am not proposing any changes to the rate
7 structure. My rate recommendations for Lighting and
8 non-metered schedules are shown on Staff Exhibit No.5,
9 pages 1 through 8.
10 Q.Does this conclude your direct testimony in
11 this proceeding?
12 A.Yes, it does.
13
14
15
16
17
18
19
CASE NO. IPC-E-08-10
10/24/08 1511 ELAM, M. (Di) 17
STAFF
.
.
.
1 (The following proceedings were had in
2 open hearing.
3 MR. PRICE: And I now present Mr. Elam for
4 cross-examination.
5 COMMISSIONER SMITH: Okay. Mr. Bruder, do
6 you have questions?
7 MR. BRUDER: I have no questions, Madam
8 Chairman.
9 COMMISSIONER SMITH: Mr. Richardson.
10 MR. RICHARDSON: Thank you, Madam
11 Chairman.
12
13 CROSS-EXAINATION
14
15 BY MR. RICHARDSON:
16 Q Mr. Elam, would you turn to page 15 of
17 your direct testimony, please? At line 19 you state that
18 when analyzing the historical effect of TOU on Schedule
19 19 energy consumption during all months, summer months,
20 and non-summer months, I found very little load shifting
21 from on-peak to mid-peak, and mid-peak to off-peak, and
22 was that analysis facilitated through a reference to
23 Staff Production Request No. 45 to Idaho Power?
24
25
A It was not. Although that analysis is
very similar, it was actually a production request for
CSB REPORTING.
[phone]
1512 ELAM (X)Staff
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1 hourly data going back to the implementation of time of
2 use rates in the 03-13 case and it was through an audit
3 request.
6
Q
A
Q
the parties?
A
Q
all?
A
Audit request? Was that available to all
I believe it was.
Okay, did that result surprise you at
12 approach towards my analysis, so I didn't have any
7
8
9
10
13 preconceived notions of what the time of use impact or
14 what the load shifting would end up being.
15 Q But you were investigating whether or not
16 there was any load shifting for what purpose, then?
17 A It was actually serving two different
18 purposes. One of them was to assess the differential
19 increase for Schedule 19. The second purpose of the
20 study was to evaluate the potential time of use impact
21 for Schedule 9.
22 Q And you found basically no time of use
23 impact on Schedule 19?
24
25
A
Q
No. I mean, it was very minimal.
So with that, can you extrapolate that
CSB REPORTING
[phone]
1513 ELAM (X)Staff
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20
1 there will be a tiny use benefit for Schedule 9?
2 A Although Schedule 9 and 19 customers
3 wouldn't behave in exactly the same way , it's assumed
4 that the Schedule 9 differentials for time of use rates
5 are at an introductory level as the Commission adopted in
6 the 03-13 case.
7 Q Do you have an understanding that the
8 Schedule 19 and Schedule 9 customer classes are different
9 in terms of how they use electricity and what their
10 processes are?
11 A Sure, but there are customers that
12 transfer between schedules.
13 Q Right, right, and do you know and if you
14 do, would you agree that due to the nature of
15 manufacturing processes that many of the industrial
16 customers have very little ability to adjust their energy
17 consumption patterns?
18 A Sure, I think you used that example with
19 Nemnich earlier in the Company's testimony.
Q So is your goal in time of use rates to
21 is it either to send a price signal or is it to affect
22 consumption patterns?
23 A It's to send customers the appropriate
24 cost-based signal representing what cost the Company
25 incurs to provide those customers with service. I would
CSB REPORTING
[phone]
1514 ELAM (X)Staff
.
.
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19
1 say the second obj ecti ve would be to get those customers
2 to possibly move towards an off-peak or mid-peak time
3 period.
4 Q To the extent that they're able to do
5 so?
6 A Exactly.
7 Q And if they're not able to do so, then the
8 price signal really doesn't do them a lot of good, does
9 it?
10 A You know, I think a price signal is
11 relative. I think that if the price signal is high
12 enough, then possibly customers will redirect their
13 operations towards a different time period.
14 Q And then I also understand that there's a
15 range of possible differentials between on-peak, mid-peak
16 and off-peak time of use rates and you address that in
17 your testimony; correct?
18 A Correct.
Q And in response to Staff's Production
20 Request No. 50, the Company provides an off-peak --
21 on-peak/off-peak time of use energy rate differential
22 summary which" you reproduce as Exhibit No. 141 in your
23 testimony; correct?
24
25
A I believe that's correct.
Q Turn to 141. Do you have Exhibit 141 in
CSB REPORTING
[phone]
1515 ELAM (X)Staff
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.
.
1 front of you?
2 A I do.
3 Q And is that the on-peak/off-peak time of
4 use energy charge rate differential chart provided by
5 Idaho Power in response to your production request?
6 A It is.
7 Q And looking at this exhibit, the
8 on-peak/off-peak ratio is pretty substantial, between
9 11.2, if I'm eyeballing it correctly, and 296 percent.
10 A That's actually 269.
11 Q Dsylexic. Wouldn't you say that
12 significantly different differentials could certainly be
13 justified?
14 A I think they could be.
15 MR. RICHARDSON: Okay, thank you. That's
16 all I have, Madam Chair.
17 COMMISSIONER SMITH: Thank you. Where did
18 I start? Mr. Purdy.
19
20
21
22
23
24
25
MR. PURDY: No questions.
MR. OLSEN: No questions.
MR. WARD: No questions. Thank you.
MR. RICHARDSON: Madam Chair?
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: You corrected me when I
said 269. If you look down at the third from the bottom,
CSB REPORTING
[phone]
1516 ELAM (X)
Staff
.
.
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18
1 I think we do see a 269 number.
2 THE WITNESS: The 269.7, is that what
3 you're referring to?
4 MR. RI CHARDSON : Yeah.
5 THE WITNESS: What was your question? I'm
6 sorry.
7 MR. RICHARDSON: So when I asked you if
8 the differential was between 11 and 269, I thought I
9 heard you correct me to say it was 169.
10 THE WITNESS: I said 269.
11 MR. RICHARDSON: Okay, I'm sorry, I
12 misspoke. Thank you, Madam Chair.
13 COMMISSIONER SMITH: You told me no
14 Mr. Ward?
15 MR. WARD: I did. Thank you.
16 COMMISSIONER SMITH: Mr. Walker.
17 MR. WALKER: No questions.
19 the Commission?
COMMISSIONER SMITH: Any questions from
20
21
22
23
24
25
COMMISSIONER KEMPTON: No.
COMMISSIONER REDFORD: No.
COMMISSIONER SMITH: Nor I. Any redirect?
MR. PRICE: No redirect.
COMMISSIONER SMITH: Thank you very much,
Mr. Elam.
CSB REPORTING
[phone]
1517 ELAM (X)Staff
.
.
.
1
2
(The witness left the stand.)
3 Mr. Curtis Thaden to the stand.
MR. PRICE: The Commission Staff now calls
4
5 CURTIS THADEN,
6 produced as a witness at the instance of the Staff,
7 having been first duly sworn, was examined and testified
18
8 as follows:
9
10
11
12 BY MR. PRICE:
13
14 record?
15 A
16
17 A
Q
19 Commission?
20
21
A
Q
Q
Q
DIRECT EXAMINATION
Can you please state your name for the
Curtis Thaden.
Who is your employer?
The Idaho Public Utilities Commission.
And what is your job title at the
Utilities compliance investigator.
And on October 24th of this year did you
22 have occasion to prepare written direct testimony for
23 this case?
24
25
A
Q
Yes.
Including Exhibits 143 through 145?
CSB REPORTING
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1518 THADEN (Di)Staff
.
.
.
1 A Yes.
And do you have any corrections or
3 addi tions to that testimony?
2 Q
Yes, I do.
Can you please explain?
On page 9 of my testimony in reference to
Mr. Thaden, can I have you speak up just a
Okay. On page 9 of my testimony in
11 reference to Project Share, line item No.5, the dollar
4 A
12 amount "110,421" needs to be replaced with "135,421."
5 Q
Do you have any other corrections?
A few more. Line No.7, the dollar amount
15 "713,726" needs to be replaced with "738,726." Dollar
6 A
16 amount "61,123" needs to be replaced with "61,331," and
7 Proj ect Share
8 Q
17 lastly, line No. 15, the dollar amount "20,123" needs to
9 little?
10 A
18 be replaced with "45,123."
19
20
21
13 Q
Do you have any other corrections?
No, I do not.
And with that said, if I were to ask you
22 the same questions posed in your written direct testimony
14 A
23 today, would your answers still be the same?
24
25
Q
A
Q
A Yes, they would.
MR. PRICE: I would now move that Mr.
CSB REPORTING
[phone]
1519 THADEN (Di)Staff
.
.
.
16
17
18
19
20
21
22
23
24
25
1 Thaden's testimony be spread upon the record as if read,
2 including Exhibits Nos. 143 through 145.
3 COMMISSIONER SMITH: Okay, seeing no
4 obj ection, we will spread the prefiled testimony upon the
5 record as if read and identify Exhibits 143 through 145.
6 (The following prefiled direct testimony
7 of Mr. Curtis Thaden is spread upon the record.)
8
9
10
11
12
13
14
15
CSB REPORTING
[phone]
1520 THADEN (Di)Staff
.
.
.
1 Q.Please state your name and address for the
2 record.
3 A.My name is Curtis Thaden. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as a Utilities Compliance Investigator. I
8 accepted that position with the Consumer Assistance Staff
9 in July 2007.
10 Q.What is your professional and educational
11 background?
12 A.Prior to my employment with the Idaho Public
13 Utilities Commission, I had 18 years experience working
14 in private industry for Hewlett Packard in a variety of
15 manufacturing positions which include Material Handler,
16 Administrative Assistant, Technical Product/Process
17 Specialist and Engineering Coordinator. In my position
18 as an Engineering Coordinator, I worked with engineering
19 teams to document and communicate, worldwide, the changes
20 made to products and manufacturing processes. I received
21 an Associate of Science Degree from Links School of
22 Business (now known as ITT Technical Institute) in Boise,
23 Idaho, in September of 1983. Additionally, I am a
24 licensed real estate agent in the State of Idaho.
25 Q.Have you previously testified before the
CASE NO. IPC-E-08-10
10/24/08 1521 THADEN, C. ( Di ) 1
STAFF
.
.
.
1 Commission?
2 A.No, I have not.
3 Q.What is the purpose of your testimony in this
4 proceeding?
5 A.I will be addressing the following:
6 (1) demographics of the 24 Idaho Counties in Idaho
7 Power's service terri tory; (2) factors affecting
8 customers ' ability to pay their bills; (3) programs
9 offering financial assistance to Idaho Power's customers;
10 (4) programs, payment plans and payment arrangements
11 offered by Idaho Power to its customers; (5) Idaho
12 Power's deposit policy; and (6) energy efficiency
13 .programs offered by Idaho Power.
14 Q. Please summarize your recommendations to the
15 Commission as discussed in your testimony.
16 A.Staff recommends that the Commission:
17 (1) Direct Staff and Idaho Power to confer about the
18 problem of customer defaults on payment arrangements and
19 identify solutions; (2) Encourage the Company to look for
20 new and creative ways to increase energy efficiency and
21 provide assistance to customers, particularly those
22 customers who are economically disadvantaged.
23 Q.Has the Staff prepared a demographic profile of
24 Idaho Power service territory in Idaho?
25 A.Yes~ Exhibit No. 143 includes demographics
CASE NO. IPC-E-08-10
10/24/08 1522 THADEN, C. (Di) 2
STAFF
1 obtained from the most recent Census Bureau data for each.2 of
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1523 THADEN,C.(Di)2a10/24/08 STAFF
.
.
.
1 the counties served by Idaho Power. For comparison, this
2 Exhibi t also includes statistics for the State of Idaho
3 and the United States. Exhibit No. 144 shows the 2008
4 Federal Poverty Level Guidelines. For purposes of
5 Staff's analysis income at or below 100% of poverty was
6 used. A map of the 24 counties served by Idaho Power
7 can be found in Exhibit No. 145.
8 Q.In reviewing the data, what stands out as
9 particularly noteworthy?
10 A.Idaho Power serves over two-thirds of the
11 state's population. When looking at each county within
12 the service terri tory, it is obvious that some counties
13 are better off than others. Blaine County has the
14 state's highest median and average income, a very low
15 unemployment rate (2.5%), and the lowest poverty rate
16 (5.9%) in the state. In contrast, Owyhee County has a
17 low median and average income and the highest percentage
18 (15.4%) of individuals living in poverty within Idaho
19 Power's service territory. Additionally, Owyhee County
20 has the lowest unemployment rate (2.2%) in the state and
21 has the highest percentage of individuals in the service
22 terri tory that speak a language other than English in the
23 home (23%).
24
25
Six counties (Idaho, Lemhi, Minidoka, Payette,
Power, and Washington) have high percentages (over 12%)
CASE NO. IPC-E-08-10
10/24/08 1524 THADEN, C. ( Di ) 3
STAFF
1 of individuals living in poverty and high unemployment.2 rates
3
4 /
5
6 /
7
8 /
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1525 THADEN,C.(Di)3a10/24/08 STAFF
.
.
.
1 (over 4.0%).
2 In Gooding, Jerome, Owyhee, and Twin Falls
3 Counties, the unemployment rate is lower than the state
4 average of 3.4% but the poverty rate is significantly
5 higher than the state average of 11.5%. With the
6 exception of Twin Falls County, these counties have high
7 percentages of individuals who speak a language other
8 than English in the home. The low unemployment rate
9 coupled with high poverty rates suggests that these
10 counties have a large percentage of "working poor",
11 individuals who are employed but unable to cover life's
12 basic needs due to low wages, inadequate benefits, and
13 li ttle opportunity of economic advancement. Relati vely
14 low-paying jobs in these largely rural agricultural
15 communi ties help explain this situation.
16 Q.Do the Federal Poverty Level Guidelines reflect
17 an accurate gauge of poverty in the United States and
18 Idaho?
19 A.Not. necessarily. The 100% of poverty level is
20 widely regarded as underestimating what it costs to
21 maintain a basic standard of living. Federal and state
22 government agencies charged with the responsibility to
23 protect human health and welfare generally set household
24 income eligibility limits for social service programs at
25 levels exceeding 100% of poverty. Since total household
CASE NO. IPC-E-08-10
10/24/08 1526 THADEN, C. (Di) 4
STAFF
1 income is used to determine eligibility for most social.2 services,the income of all wage earners in a household
3 is combined.For
4 .
5 /
6
7 /
8
9 /
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1527 THADEN,C.(Di)4a10/24/08 STAFF
.
.
.
1 the State of Idaho, there are roughly 44,000 households
2 at or below 100% of poverty. The total number of Idaho
3 households that qualify for LIHEAP benefits under last
4 year's eligibility threshold (150%) of poverty is
5 101,000.
6 Q.What conclusion can be drawn from these
7 demographics?
8 A.Customers who are living in poverty and/or are
9 unemployed have limited or diminished financial resources
10 with which to pay utility bills. Given the recent
11 economic turmoil, Staff believes that the Census data,
12 al though somewhat stale, provides a fairly good picture
13 of Idaho Power's customers today. In fact, there is
14 probably reason to believe, as discussed below, that
15 customers may be worse off in the future. Staff is
16 concerned that a significant number of Idaho Power
17 customers will have problems paying their electric bill,
18 especially when faced with increasing rates.
19 Q.Do you see a trend developing that could
20 further impact the ability of customers to pay their
21 utility bills?
22 A.Yes. Current Idaho Department of Labor data as
23 of August 2008 shows an upward trend in the state's
24 unemployment rate (4.6%). The state's projected
25 unemployment for September 2008 was 5.0% and is
CASE NO. IPC-E-08-10
10/24/08 1528 THADEN, C. ( Di ) 5
STAFF
.
.
.
17
18
19
20
21
22
23
24
25
1 increasing rapidly. This would represent the highest
2 state unemployment rate in four years. The national
3 unemployment
4
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
CASE NO. IPC-E-08-10
10/24/08 1529 THADEN, C. (Di) 5a
STAFF
.
.
.
1 rate increased to a five-year high (6.1%). When
2 comparing the first eight months of 2008 to the first
3 eight months of 2007, 50% more unemployment checks have
4 been issued by the state. In the Treasure Valley alone,
5 several retail and manufacturing business have announced
6 layoffs recently, including the loss of 1,500 jobs at
7 Micron.
8 An increase in the unemployment rate can lead
9 to an increase in the percentage of the state's
10 population who fall below the Federal Poverty Guidelines.
11 As a result, more strain will be placed upon agencies
12 that provide financial assistance for payment of utility
13 bills. The number of disconnections has the potential to
14 increase as people experience difficulty paying their
15 bills. Even people who were high wage earners can find
16 themselves in a tight financial situation following a
17 layoff. Higher unemployment, rising fuel costs and
18 increasing food costs are additional stresses that will
19 have an impact on people's finances.
20 Q.Do you see any other factors that might inhibit
21 a customer' s ability to pay his/her power bill?
22 A.The current housing crisis (record number of
23 foreclosures) has placed additional pressure on
24 households. Homeowners with ARMs (Adj ustable Rate
25 Mortgages) th~t are unable to refinance their home due to
CASE NO. IPC-E-08-10
10/24/08 1530 THADEN, C. (Di) 6
STAFF
1 declining property values will be faced with making a.2 higher mortgage payment
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1531 THADEN,C.(Di)6a10/24/08 STAFF
.
.
.
1 when their ARM resets in 2009. This could cause a severe
2 hardship on individuals who are already strapped with
3 having to pay higher utility costs. Low income
4 households are not the only ones impacted. This is an
5 issue that impacts a diverse group of wage earners.
6 Q.What resources are available to help custome.rs
7 pay their energy bills?
8 A.LIHEAP (Low Income Home Energy Assistance
9 Program) is funded by the Federal government through a
10 grant to the State of Idaho. Unlike the situation in
11 other states, there is no state government funding
12 available in Idaho to help customers pay energy bills at
13 any time of year. For the 2007-2008 winter heating
14 season, $2,006,229 was distributed to 10,421 Idaho Power
15 customers in Idaho to help pay home heating bills. The
16 average amount paid to each participant was $193.
17 Participants are allowed to earn up to 150% of the
18 Federal Poverty Guidelines. The table below reflects the
19 number of Idaho Power customers in Idaho who received
20 LIHEAP benefits and the average dollar amount allocated
21 during the last three heating seasons.
22
23
24
25
Program Year Funding # of Participants Avg. Benefit
2005/2006 $1,825,678 10,105 $181
2006/2007 $1,653,986 9,457 $175
2007/2008 $2,006,229 10,421 $193
CASE NO. IPC-E-08-10
10/24/08 1532 THADEN, C. ( Di ) 7
STAFF
.
.
.
1 Energy Assistance funding provided by LIHEAP does not.
2 sufficiently meet the energy needs of low income
3 customers. Therefore, "Crisis Funding" is available to
4 customers whose circumstances qualify them for additional
5 financial assistance under the LIHEAP program. Money is
6 not always available for "Crisis Funding". Even when
7 funds are available, the number of people who can be
8 helped is quite small. For the 2007-2008 winter heating
9 season, $53,766 was distributed to 199 Idaho Power
10 customers in Idaho.The average amount paid to each
11 participating customer in 2007-2008 was $270. The table
12 below reflects the number of Idaho Power customers in
13 Idaho who received LIHEAP "Crisis Funding" benefits and
14 the average dollar amount allocated during the last two
15 heating seasons.
16 Program Year # of ParticipantsFunding Avg. Benefit
17 2006/2007 $70,196 289 $243
18 2007/2008 $53,776 199 $270
19 Q.Are there other programs in place that can help
20 customers?
21 A.Yes. In Idaho Power's service territory, the
22 Salvation Army administers a program, Proj ect Share,
23 which provides financial assistance to individuals
24 regardless of the heat source. The program is a
25 fuel-blind fund, which means that monies are dispersed
CASE NO. IPC-E-08-10
10/24/08 1533 THADEN, C. (Di) 8
STAFF
1 towards payment of bills that are for any energy sources.2 ( electric,natural gas,
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1534 THADEN,C.(Di)8a10/24/08 STAFF
.
.
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1 wood, coal, propane, kerosene and oil). All money
2 collected, with the exception of administration costs,
3 goes back to the community.
4 In the past three calendar years (2005 - 2007),
5 Idaho Power shareholders donated $135,421 to Proj ect
6 Share; Idaho Power customers in both Idaho and Oregon
7 donated $ 603,305. Of the total amount collected
8 ($738,726), $61,331 of the shareholder contribution (8.6%
9 of funds collected) was paid to the Salvation Army for
10 administering the program. The table below reflects
11 total dollar amounts donated by Idaho Power customers and
12 its shareholders in the past three calendar years.
13 Year Idaho Power Customers Shareholders
14 2005 $203,126 $45,313
15 2006 $201,226
$198,953
$45,123
16 2007 $44,985
17 Q.How much Proj ect Share money was provided to
18 assist with heating costs in each of the past three
19 fiscal years?
20 A.In the past three fiscal years a total of
21 $526,870 was provided to households in Idaho and Oregon
22 served by Idaho Power, the Cities of Burley, Heyburn,
23 Rupert and Weiser and United Electric Co-Op, Inc. Idaho
24 Power does not know how much of this money is distributed
25 to its own customers. The table below reflects the totaldollar
CASE NO. IPC-E-08-10
10/24/08 1535 THADEN, C. (Di) 9
STAFF
.
.
.
1 amounts paid to assist households with their heating
2 costs.
3 Fiscal Year Money Disbursed
4 2004/2005 $188,509
$176,90952005/2006
6 2006/2007 $161,452
7 Q.What efforts does Idaho Power put forth to make
8 the community and its customers aware of Project Share?
9 A.Idaho Power publicizes Proj ect Share through
10 its website, newsletters, and monthly customer billings.
11 In addition, Idaho Power implemented a program called
12 "Comfort Cafe Products" to raise awareness and provide
13 funding for Proj ect Share. The program was a partnership
14 between Idaho Power and a local coffee company (White
15 Cloud Coffee)' that sold a special blend of coffee, hot
16 chocolate and lemonade. A percentage of these proceeds
17 were donated to Proj ect Share. The amount of proceeds
18 collected in 2006 totaled $129 and in 2007 totaled $117.
19 The program was discontinued at the end of 2007. Though
20 the program was canceled, Idaho Power is encouraged to
21 continue with its creative efforts to make the community
22 more aware of Proj ect Share.
23 Q.What utility programs are in place to help
24 customers avoid being disconnected during the winter
25 months?
CASE NO. IPC-E-08-10
10/24/08 1536 THADEN, C. (Di) 10
STAFF
1 A.Idaho Power's Winter Protection Program (aka.2 the "moratorium" )allows residential customers whose
3 household includes either children,elderly or the infirm
4 to be
5
6 /
7
8 /
9
10 /
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1537 THADEN,C.(Di)lOa10/24/08 STAFF
.
.
.
1 protected from disconnection during the months of
2 December through February if they declare that they are
3 unable to pay their utility bill in full. The Winter
4 Payment Plan allows customers who have declared Winter
5 Protection an additional two months of protection
6 (November and March) if they agree to accept and
7 follow-through on monthly payments during the Winter
8 Protection period that are equal to half of the monthly
9 average of the previous 12 months billings.
10 Once a year a brochure titled "Idaho
11 Residential Consumer Information", with information on
12 both the Winter Protection Program and Winter Payment
13 Plan, is sent to all residential customers. All accounts
14 that receive a "Final Notice" during the months of
15 November through February are notified of the Winter
16 Protection Program and the Winter Payment Plan by way of
17 an informational insert included in the mailing titled
18 "What You Need to Know About Our Winter Protection
19 Program". For those customers who have declared Winter
20 Protection, an informational brochure on the Winter
21 Payment Plan is provided in the December, January and
22 February reminder notices that are sent out. The intent
23 of this brochure is to encourage these protected
24 customers to pay a portion of their electric bills during
25 the winter months to help maintain the unpaid balance on
CASE NO. IPC-E-08-10
10/24/08 1538 THADEN, C. (Di) 11
STAFF
1 the account.Both Customer Service Representatives and.2 Field Personnel are educated and trained on the
3 protection options.It can
4
5 /
6
7 /
8
9 /
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1539 THADEN,C.(Di)11a10/24/08 STAFF
.
.
.
1 be concluded that Idaho Power adequately educates its
2 customers on both the Winter Protection Program and
3 Winter Payment Plan.
4 Q.Has the number of customers who have declared
5 the need for Winter Protection increased?
6 A.The number of Idaho customers who declared
7 Winter Protection during the 2007/2008 winter heating
8 season totaled 10,284. This represents a 62% increase
9 when compared to the previous winter heating season
10 (6,362 participants). The increase could be attributed
11 to Idaho Power's educational efforts in providing
12 customers with information about the program as well as
13 an increase in the number of customers who are unable to
14 pay for their heating costs. The table below reflects
15 the total number of participants in the last four winter
16 heating seasons.
17 Winter Season 2004/2005 2005/2006 2006/2007 2007/2008
18 Participants 6,667 7,971 6,362 10,284
19 Q.Has there been an effort by Idaho Power to
20 increase the number of participants in the Winter Payment
21 Plan?
22 A.Of the 10,284 participants who declared Winter
23 Protection in the 2007/2008 winter heating season, 2,563
24 (25%) elected to be placed on the Winter Payment Plan.
25 This is significantly higher than the previous winter
CASE NO. IPC-E-08-10
10/24/08 1540 THADEN, C. (Di) 12
STAFF
1 heating season that totaled only 486 participants (8 %) ..2 The
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1541 THADEN,C.(Di)12a10/24/08 STAFF
.
.
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1 increase could be attributed to Idaho Power's educational
2 efforts in providing information on the payment plan and
3 attempting to encourage customers protected from
4 disconnection to pay at least a minimal amount toward
5 their heating bills. The table below reflects the total
6 number of plan participants in the last three winter
7 heating seasons.
8 Winter Season 2005/2006 2006/2007 2007/2008
9 Participants 144 486 2,563
10 Q.Have customers on the Winter Payment Plan been
11 able to successfully pay down their outstanding account
12 balances before the end of the Winter Protection period
13 on March 31?
14 A. Of the 2,563 participants who elected to be
15 placed on the Winter Payment Plan during the 2007/2008
16 winter heating season, over 75% (1,926 participants) were
17 not able to meet their monthly payment. In the previous
18 winter heating season over 77% (376 participants) were
19 not able to meet their monthly payment. Though more
20 people are participating, it appears the effectiveness
21 and success of the Winter Payment Plan is in question.
22 The table below shows the number of customers on the
23 Winter Payment Plan who were not able to meet the
24 agreed-upon monthly payment in the last three winter
25 heating seasops.
CASE NO. IPC-E-08-10
10/24/08 1542 THADEN, C. (Di) 13
STAFF
.
.
.
1 Winter Season 2005/2006 2006/2007 2007/2008
2 # of Defaults 98 376 1,926
3 % of Defaults 68%77%75%
4 Q.Have the number of residential payment
5 arrangement agreements and defaulted payment arrangement
6 agreements made on accounts increased or decreased?
7 A.The number of Idaho Power residential customers
8 has steadily increased over the past three calendar years
9 (2005-2007) from 360,496 to 383,993. This represents a
10 6% increase (23,497). During this time period the number
11 of payment arrangement agreements increased by 18.5%
12 (29,929) and the number of defaulted payment arrangements
13 increased by 14% (10,773). A customer can have more than
14 one payment arrangement in a given month for an account.
15 Because of this, a payment arrangement agreement and
16 payment arrangement default does not correlate to the
17 actual number. of accounts. If a residential service
18 location (Schedule 1) and a small commercial location
19 (Schedule 7) are included on the same account, then Idaho
20 Power associates the payment arrangement agreement and/or
21 payment arrangement default with Schedule 7. Therefore,
22 the number of residential (Schedule 1) payment
23 arrangements and defaults are actually higher than what
24 is reflected in the table below. This table shows the
25 number of customers, payment arrangements and payment
arrangement defaults.
CASE NO. IPC-E-08-10
10/24/08 1543 THADEN, C. (Di) 14
STAFF
.
.
.
1 Year #of customers Arrangements Defaults % Defaults
2 2005 360,469 161,595 73,112 45%
3 2006 374,527 167,329 73,552 43%
4 2007 383,993 191,524 83,812 44%
5 Q What can be done to help reduce the number of
6 customers who default on their payment arrangement
7 agreements?
8 A.At this time, Staff is not sure why customers
9 are not meeting the terms of payment arrangements. It
10 may be that a. more diligent effort by Idaho Power to
11 provide monthly customer reminder calls would be
12 beneficial, allowing the Company to assess each
13 customer's situation and reinforce to each customer the
14 importance of making the agreed upon payment. Another
15 proposal would be to provide customers a payment coupon
16 book. However, it may be that customers are simply
17 agreeing to make payments in an amount and/or at a time
18 that is not feasible given their financial circumstances.
19 Whether customers are doing so because they feel they
20 have no choice but to agree to terms suggested by the
21 Company, are using payment arrangements as a means to
22 defer disconnection of service due to a lack of ability
23 to budget for" expenses, or some other reason, more study
24 is required to determine why so many arrangements result
25 in default. Staff recommends that it and Idaho Power be
directed to confer about this problem and attempt to
CASE NO. IPC-E-08-10
10/24/08 1544 THADEN, C. (Di) 15
STAFF
.
.
1 identify solutions.
2 Q.Does Idaho Power have a policy in effect that
3 indirectly assists low income customers in getting
4 reconnected after they have been disconnected for
5 non-payment of bills?
6 A.When a residential customer is disconnected for
7 non-payment of their bill, Idaho Power does not require a
8 deposi t to re-establish service. The Company is the only
9 regulated energy utility in Idaho that has this policy.
10 For low income customers who have been disconnected from
11 service for non-payment, a deposit requirement makes it
12 more difficult for them to re-establish service and
13 further places them into debt. Staff believes that the
14 addi tional financial burden of a deposit requirement
15 causes a greater hardship for low income customers and
16 often presents a barrier to customers in obtaining or
17 retaining service. Idaho Power should be commended on
18 their customer-friendly policy of not requiring
19 residential deposits.
20 Q.Does Idaho Power have any programs that assist
21 senior citizens?
22 A.Yes, the Gatekeeper Program. The program
23 provides training to customer service center
24 representatives, meter specialists and field.25 representati ves to notice warning and danger signs in
CASE NO. IPC-E-08-10
10/24/08 1545 THADEN, C. (Di) 16
STAFF
1 elderly customers.If it is determined that assistance.2 is required,the employee
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1546 THADEN,C.(Di)16a10/24/08 STAFF
.
.
.
1 contacts one of the local agencies on aging with the hope
2 that some form of assistance can be rendered. With the
3 planned implementation of remote meter reading, Staff is
4 concerned that the effectiveness and benefit of the
5 program will be diminished.
6 Q.What other Idaho Power programs are available
7 to assist low income customers?
8 A.Energy efficiency programs can make bills more
9 affordable by decreasing usage, thereby lowering energy
10 costs. The Weatherization Assistance for Qualified
11 Customers Program (WAQC) offers financial assistance to
12 qualifying low income customers with electrically-heated
13 homes for weatherization of their homes. A household
14 whose income is 150% of poverty or less qualifies to
15 recei ve weatherization services. This program is funded
16 by Idaho Power and administered by several local
17 communi ty action agencies wi thin Idaho Power's service
18 terri tory. The total number of dwellings in Idaho that
19 were weatherized in 2007 was 397 at a total cost of
20 $1,124,581. This amount does not include IPC
21 Administration and CAP Administration costs.
22 Energy House Call is a program offered to Idaho
23 Power customers who live in manufactured homes that are
24 heated by an electric furnace or heat pump. Although not
25 technically a. low income program, this program targets
customers who live in housing that is more affordable for
CASE NO. IPC-E-08-10
10/24/08
THADEN, C. (Di) 17
STAFF
1547
.
.
.
1 people with limited or fixed incomes. Through local
2 certified contractors, at no cost to the customer, a leak
3 assessment is performed on the electrical heating system
4 ducts. All leaks are sealed; compact fluorescent light
5 bulbs and air filters are installed. Idaho Power's
6 Energy Efficiency Rider funds this program.
7 A newly-created program, the Home
8 Weatherization Pilot Program, is targeted to customers
9 who do not qualify for WAQC due to income that exceeds
10 the allowable level. The Home Weatherization Pilot
11 Program (HWP) will provide weatherization services to
12 twenty electrically heated homes served by Idaho Power in
13 its Southern region. Program participants will be
14 selected from a list of Idaho Power customers who apply
15 for LIHEAP benefits through the South Central Community
16 Action Partnership. To participate in the HWP pilot, a
17 residential customer's annual income must be between 151%
18 and 250% of the federal poverty level and use electricity
19 to heat his or her home.
20 $66,000 from Idaho Power's Energy Efficiency
21 Rider funds is budgeted for the pilot. That amount
22 includes a 10% administrative fee for Home Energy
23 Management, L.L.C., the contractor providing the
24 weatherization services. There will be some additional
25 costs associated with conducting follow-up physical
CASE NO. IPC-E-08-10
10/24/08 1548 THADEN, C. (Di ) 18
STAFF
1 audits that will be completed mostly by regional Idaho.2 Power employees and funded by the Energy
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1549 THADEN, C.(Di)18a10/24/08 STAFF
.
.
1 Efficiency Rider to assure work has been done properly.
2 Q. Does Idaho Power adequately address the needs
3 of its customers through its various programs?
4 A.Although there is always more that can be done,
5 Idaho Power's programs do help customers in a variety of
6 different ways. Idaho Power is actively participating in
7 the energy affordabili ty workshops now underway in Case
8 No. GNR-U-08-1. In that case, workshop participants are
9 exploring ways to address energy affordabili ty and the
10 inabili ty of customers to pay energy bills.
11 Will an increase in Idaho Power's rates affectQ.
12 customers' ability to pay their bills?
13 A. Yes. As I have pointed out in my testimony,
14 there are many factors affecting customers' ability to
15 pay, and a rate increase will add to the financial
16 difficulties faced by customers. Although Staff has not
17 recommended a residential rate increase in this case, the
18 Company will need to continue to be more flexible in
19 making payment arrangements. It will need to work with
(20 the customers to ensure that payments can be made based
.
21 upon schedules that fit the customers' circumstances and
22 needs. Staff' recommends that the Company be encouraged
23 to look for new and creative ways to increase energy
24 efficiency and provide assistance to customers,
25 particularly those customers who areeconomically-disadvantaged.
CASE NO. IPC-E-08-10
10/24/08
THADEN, C. (Di) 19
STAFF
1550
1 Q.Does this conclude your testimony?.2 A.Yes,it does.
3
4
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1551 THADEN,C.(Di)20
10/24/08 STAFF
.1
2 open hearing.)
(The following proceedings were had in
MR. PRICE: I would now present Mr. Thaden
4 for cross-examination.
.
3
5
6 questions?
7
8
9
10
11
12
13
14
15 BY MR. PURDY:.
16 Q
COMMISSIONER SMITH: Mr. Ward, do you have
MR. WARD: No questions. Thank you.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: I just had one, Madam Chair.
CROSS-EXAINATION
Mr. Thaden, on page 17 of your direct
17 testimony, you discuss Idaho Power programs that are
18 available to assist low income customers and on that
19 page, you reference the low income weatherization program
20 which is now referred to, for short, WAQC; is that
21 correct?
22
23
A
Q
That is correct.
And is it also correct that you do not
24 recommend any particular level of funding on that page or.25 elsewhere in your testimony?
CSB REPORTING
[phone]
1552 THADEN (X)Staff
.
.
.
1 A Correct. We do not recommend in my
2 testimony a set level of funding, but Staff does support
3 an increase in funding.
4 Q All right, you jumped ahead, I appreciate
5 that, so your silence is not to be construed as any
6 opposi tion to increasing or seeking a commitment from the
7 Company in this case to increase WAQC funding?
8 A Correct.
9 Q Oh, then I didn't see any reference to the
10 proposal by Ms. Ottens in her testimony to implement a
11 low income conservation education program. Did I
12 overlook it?
13 A In my testimony?
14 Q Yes.
15 A There was no reference to that, a low
16 income energy conservation program, but Staff does
17 support that concept.
18 MR. PURDY: All right, fair enough.
19 That's all. Thank you.
20 COMMISSIONER SMITH: Thank you. Mr.
21 Richardson.
22 MR. RICHARDSON: No questions, Madam
23 Chair.
24 COMMISSIONER SMITH: Mr. Bruder.
25 MR. BRUDER: No questions, Madam Chair.
CSB REPORTING
[phone]
1553 THADEN (X)Staff
.
.
1
2
3
4 Commission.
5
6
7
8
9
10 very much.
11
12
13
14
COMMISSIONER SMITH: Ms. Nordstrom.
MS. NORDSTROM: No questions.
COMMISSIONER SMITH: From the
COMMISSIONER KEMPTON: No.
COMMISSIONER REDFORD: No questions.
COMMISSIONER SMITH: Redirect?
MR. PRICE: No redirect.
COMMISSIONER SMITH: All right, thank you
THE WITNESS: Thank you.
COMMISSIONER REDFORD:Thank you.
(The witness left the stand.)
MR. PRICE: The Commission Staff now calls
15 Ms. Marilyn Parker to the stand.
19
20
21
22
23
24.25
16
17
18
CSB REPORTING
[phone]
1554 THADEN (X)Staff
.1
2
MARILYN PARKER,
produced as a witness at the instance of the Staff,
3 having been first duly sworn, was examined and testified
.
4 as follows:
5
6
7
8 BY MR. PRICE:
9 Q
DIRECT EXAMINATION
Will you please state your name for the
Marilyn Parker.
And who is your employer?
The Idaho Public Utilities Commission.
And what is your job title?
Utilities compliance investigator.
And did you have occasion on October 24th
17 of this year to prepare written direct testimony in this
10 record?
11 A
18 case, including Exhibits Nos. 146 through 147?
20
12 Q
Yes.
Do you have any corrections or additions
21 to that testimony?
13 A
No, I don't.
If I were to pose the same questions to
24 you today as were posed in your written direct testimony,.25
14 Q
would your answers still be the same?
CSB REPORTING
[phone]
15 A
16 Q
19 A
Q
22 A
23 Q
1555 PARKER (Di)Staff
.1 A Yes, they would.
MR. PRICE: I would now move that
3 Ms. Parker's testimony, including Exhibits Nos. 146
2
4 through 147, be spread upon the hearing record as if
5 read.
6 COMMISSIONER SMITH: If there is no
7 obj ection, we will order that the prefiled testimony be
8 spread upon the record as if read and identify Exhibits
9 146 and 147.
10 (The following prefiled direct testimony
11 of Ms. Marilyn Parker is spread upon the record.)
.
.
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CSB REPORTING
[phone]
1556 PARKER (Di)Staff
.1 Q.Please state your name and address for the
2 record.
3 A.My name is Marilyn Parker. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utili ties
7 Commission as a Utilities Compliance Investigator. I
8 accepted that position with the Consumer Assistance Staff
9 in November 2002.
10 Q.What is your educational and professional
11 background?
12 A.Prior to my employment with the Idaho Public.13 Utili ties Commission, I had twenty years experience
14 working in private industry for three different utility
15 companies. In 1973 and 1974, I was employed by Central
16 Alaska Utilities, a water company in Anchorage, Alaska,
17 as the Executive Secretary to the President of the
18 company. From 1982 until 1987, I was employed as a
19 Customer Service Representative for Idaho Power Company
20 in Salmon, Idaho. From February 1989 until November
21 2002, I was employed by Intermountain Gas Company in
22 Customer Services. During my last six years at
23 Intermountain Gas, I supervised representatives at the
24 Customer Service Center's Emergency Answering Service..25 I received a Bachelor of Arts Degree in
CASE NO. IPC-E-08-10
10/24/08
1557 PARKE R, M . ( D i ) 1
STAFF
.
.
.
1 Management and Organizational Leadership from George Fox
2 University in Boise, Idaho in June 2002.
3 In June 2003 and June 2006, I attended the
4 National Low Income Energy Consortium Annual Conference
5 in Sacramento, California and Washington, D. C. ,
6 respectively.
7 Q.Have you previously testified before the
8 Commission?
9 A.Yes, I have.
10 Q.What is the purpose of your testimony in this
11 proceeding?
12 The purpose of my testimony is to address:A.(1)
13 customer comments received by the Commission regarding
14 this case; (2) customer relations; (3) convenience fees;
15 and, (4) irrigation deposits.
16 Q.Please summarize your testimony and
17 recommendations to the Commission.
18 A.I reviewed the customer comments and found that
19 one-third of those commenting were from low and fixed
20 income customers who were concerned about how they would
21 be able to pay higher electric rates and another
22 one-third questioned why existing customers had to pay
23 for new growth.
24 I reviewed the complaints and inquiries
25 received by the Commission over the past four years from
CASE NO. IPC-E-08-10
10/24/08 1558 PARKER, M. (Di) 2
STAFF
1 Idaho Power customers and identified a consistent decline.2 from
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.I PC- E- 0 8 -1 0 1559 PARKER,M.(Di)2a
10/24/08 STAFF
.
.
1 2004 to 2007.
2 I reviewed the Customer Service Center's call
3 answering performance and found that the Company's yearly
4 averages met the goal of answering 80% of calls within 30
5 seconds.
6 I identified technological advancements
7 implemented by the Company and how they have improved
8 customer service.
9 I reviewed the Company's forms required by the
10 Commission' s Utility Customer Relations Rules and found
11 them to be compliant.
12 I addressed the Company's response to Staff's
13 concerns regarding how Idaho Power's irrigation customers
14 were kept informed of the Company's recent changes to its
15 irrigation deposit collection practices.
16 I recommend that the Company explore
17 al ternati ves to its policy of requiring customers to pay
18 convenience fees when paying their Idaho Power bills
19 using check-by-phone, credit card or debit card and
20 report its findings to the Commission Staff.
21 CUSTOMER COMMNTS
22 Q.Have you reviewed the written customer comments
23 that have been received by the Commission regarding this
24 case?.25 A.Yes. As of October 16, 2008, forty-nine (49)
CASE NO. IPC-E-08-10
10/24/08
1560 PARKER, M. (Di) 3
STAFF
.
.
.
1 Idaho Power customers had submitted comments regarding
2 the proposed increase in Idaho Power's electric rates.
3 All the commenters opposed any increase to rates.
4 Q.What are the concerns mentioned most often by
5 customers?
6 A.The comments fell into two maj or categories.
7 One-third of those commenting cited Idaho Power's
8 reference in its press release to the fact that new
9 growth was a major driver in its need for a rate
10 increase. Those customers questioned why current
11 customers had to pay for new growth. Another one-third
12 of the comments were from fixed and low income customers
13 who raised concerns about the current economic conditions
14 and how they would be able to afford to pay higher
15 electric rates.
16 Staff witness Hessing will discuss cost
17 allocation and the cost of growth. Staff witness Thaden
18 will discuss economic conditions and customers' ability
19 to pay.
20 CUSTOMER RELATIONS
21 Q.In the last four years, how many complaints and
22 inquiries has the Commission received regarding Idaho
23 Power?
24
25
A.Staff Exhibit No. MP #1 shows the number of
informal complaints and inquiries received since 2004.
Q. What did your analysis of complaints and
CASE NO. IPC-E-08-10
10/24/08 1561 PARKER, M. (Di) 4
STAFF
.
.
.
1 inquiries since 2004 reveal?
2 A. There has been a consistent decline in the
3 number of complaints and inquiries received by the Idaho
4 Public Utili ties Commission from Idaho Power customers in
5 the past four years.
6 Q.Regarding complaints and inquiries registered
7 at the IPUC, how does Idaho Power compare to the other
8 three maj or regulated energy companies doing business in
9 Idaho since 2004?
10 A.In 2007, Idaho Power and Avista Utilities in
11 northern Idaho had the fewest complaints and inquiries on
12 a per 1,000 customer basis.From 2004 to 2006, Idaho
13 Power had fewer complaints and inquiries than two of the
14 major energy companies (see Staff Exhibit No. MP #2).
15 Q.Is Idaho Power responsive to the Commission's
16 Utility Compliance Investigators during complaint
17 investigations?
18 A.Yes. Rule 404 of the Utility Customer
19 Relations Rules (UCRR) specifies that utilities must
20 respond orally or in writing to the Commission within ten
21 business days of receiving notification from the
22 Commission that an informal complaint against the Company
23 has been received. In 2007, the annual average number of
24 days for Staff to fully resolve complaints among all the
25 energy companies was 6.15. For Idaho Power complaints,
the average number
CASE NO. IPC-E-08-10
10/24/08 1562 PARKER, M. (Di) 5
STAFF
.
.
.
1 of days for Staff to resolve complaints in that same time
2 period was 5.27 days.
3 Q.Is Idaho Power's Customer Service Center
4 telephone answering service level goal of answering 80%
5 of incoming calls wi thin 30 seconds consistent and wi thin
6 industry standards?
7 A.Yes. When looking at yearly averages, the
8 Company has met its goal in each of the last four years.
9 However, when looking at its month to month performance,
10 Idaho Power failed to meet its goal in three months
11 between July 2007 and July 2008.
12 Q.Are you concerned about the failures to meet
13 its goal?
14 A. No. It appears that failures were isolated
15 instances. The worst performance was in July 2007 when
16 the service level dropped to 67.9%. The Company
17 attributed this low service level to having six unfilled
18 positions in its Customer Service Center, which is 11% of
19 the total customer service representative staff. Those
20 positions were filled and the new representatives were
21 answering telephones by the following month. In August
22 2007, the service level rose to 81.04%. The Consumer
23 Assistance Staff has not received complaints from
24 customers who report that they are unable to reach the
25 Company by telephone due to long hold times, busysignals,
CASE NO. IPC-E-08-10
10/24/08 1563 PARKER, M. (Di) 6
STAFF
.
.
.
1 no answers, or being told to call back later due to high
2 call volumes.
3 Q.Are there any other factors to consider when
4 analyzing the Company's service level?
5 A.Yes. Since the implementation of the
6 Interactive Voice Response Unit (IVRU) and the online
7 customer service that is available through Idaho Power's
8 Website, many customers now have instant access to the
9 information they need either by telephone or the Internet
10 wi thout the need to wait on hold to speak to a live
11 customer service representative.
12 Q.What about customers with outages or
13 emergencies to report? How are those calls handled?
14 A. Customers with emergencies are not handled in
15 the same way that a customer who wants to sign up for
16 service would. be handled. When a customer calls Idaho
17 Power, the customer is connected to an automated system,
18 the IVRU, that asks the caller to say one of the
19 following options: "Outage"; "Residential Services";
20 "Irrigation or Commercial"; "New Construction"; or
21 "Electrician". When a customer says "Outage", the caller
22 is first told that if there is an emergency, the caller
23 should hang up and call 911. If the caller stays on the
24 line, the caller is directed to state the city he or she
25 is in. At that point, the automated system looks for an
outage in that
CASE NO. IPC-E-08-10
10/24/08 1564 PARKER, M. (Di) 7
STAFF
.
.
.
1 ci ty. If there is an outage, a recorded message provides
2 details regarding any known outages. If the automated
3 system does not find any outages logged, the caller is
4 advised to stay on the line so that the caller can report
5 an outage to a representative.
6 Q.Has Idaho Power made any investments in
7 technology to improve customer service in outage
8 situations?
9 A.Yes. The Company has made significant
10 investments in its Outage Management System.
11 Q.What were your observations regarding Idaho
12 Power's Outage Management System?
13 A. Idaho Power's Outage Management System is now
14 connected to its IVRU. One of the most important
15 benefits of the two systems being linked is the ability
16 of the Company to reduce the number of employees needed
17 to answer incoming telephone calls during outages.
18 In an effort to further improve customer
19 service during emergencies and outages, Idaho Power
20 relocated its Outage Management Department to the same
21 facili ty as the Customer Service Center last year. Two
22 specially-trained customer service representatives are
23 always located wi thin the Outage Management Center. This
24 allows the Outage Management employees to concentrate on
25 the coordination of communications with its dispatched
employees in the field
CASE NO. IPC-E-08-10
10/24/08 1565 PARKER, M. (Di) 8
STAFF
.
.
.
1 to resolve emergencies and incidents and allows the
2 customer service center employees to work with the
3 incoming telephone calls and customer communications.
4 Q.Has Idaho Power recently improved any of its
5 existing technologies?
6 A.Yes. The Company made many improvements to its
7 Interacti ve Voice Response Unit (IVRU). One of the
8 improvements resulted from Idaho Power's internal
9 tracking of complaints registered with its own customer
10 service representatives. Customers complained about
11 being unable to figure out how to speak with a live
12 representati ve. Idaho Power added an option for
13 customers who select "Residential Services" on the IVRU
14 to speak in person to a customer service representative.
15 In spite of the fact that more and more customers are
16 choosing not to speak with a live customer service
17 representative, Idaho Power accommodated those customers
18 who are still uncomfortable with new technologies; this
19 particularly helps elderly and some physically challenged
20 customers.
21 Q.Do Idaho Power's notices, bills, and written
22 information required by the Commission's Utility Customer
23 Relations Rules (UCRR) comply with these rules?
24
25
A.Yes. I reviewed the documents in September
2008 and found the Company to be in compliance.
Q. In 2008, a provision was added in the UCRR
CASE NO. IPC-E-08-10
10/24/08 1566 PARKER, M. (Di) 9
STAFF
.
.
.
1 203.03 that states "utilities shall implement procedures
2 designed to monitor and identify customers who may be
3 billed under an inappropriate tariff schedule." Has
4 Idaho Power implemented procedures to be in compliance
5 wi th this new provision?
6 A.Yes. According to Idaho Power, its Customer
7 Information System monitors accounts to ensure a customer
8 is billed under the appropriate rate schedule. When
9 usage occurs outside rate qualification rules for a
10 particular rate schedule, the account is routed to a
11 customer service representative for a manual review.
12 CONVNIENCE FEES
13 Q. Pursuant to UCRR 403, did the Commission review
14 Idaho Power's written record of its complaints and
15 requests for conferences?
16 A.Yes ~ I reviewed the Company's records for 2007.
17 These records consist of complaints and requests received
18 by the Company directly and are in addition to those
19 complaints referred to the Company by the Commission. I
20 noted in my review that 10% of these complaints (115)
21 were from customers who were unhappy with the convenience
22 fees required to pay their Idaho Power bill over the
23 telephone with a credit or debit card or check-by-phone.
24 The current c~arge is $2.85 for a payment of up to
25 $300.00. For example, if a customer calls to pay a billthat is
CASE NO. IPC-E-08-10
10/24/08 1567 PARKER, M. (Di) 10
STAFF
.
.
.
1 $305, the customer is required to pay two convenience
2 fees: $2.85 for the first $300 and an additional $2.85
3 for the remaining $5.00 for a total of $5. 70 to pay one
4 bill. As monthly billing amounts have risen, and more
5 customers pay past due bills that have accumulated over
6 time, customers have exceeded the $300 ceiling with
7 increasing frequency.
8 Q.Did Idaho Power take any action to address this
9 issue?
10 A.Yes. Idaho Power negotiated with a new vendor
11 that charges a $2.50 convenience fee. Additionally, the
12 minimum dollar amount per transaction will rise to $500.
13 The new vendor will begin processing Idaho Power's credit
14 card, debit card, and check-by-phone payments in January
15 2009.
16 Q.Do you have an opinion about Convenience Fees?
17 A.Yes. When regulated energy utility companies
18 in Idaho began to address customer requests for more
19 options to pay bills, many of the companies, including
20 Idaho Power, responded by adding the ability to pay bills
21 over the telephone and online. Because relatively few
22 customers used the new conveniences several years ago,
23 the decision was made by the utilities that customers who
24 used the services should pay for the services through
25 individual transaction fees, called "convenience fees."
CASE NO. IPC-E-08-10
10/24/08 1568 PARKER, M. (Di) 11
STAFF
.
.
.
1 At the time when convenience fees were first implemented,
2 it seemed logical that those costs created by a few
3 customers should not be passed on to all ratepayers.
4 There was not a sufficient volume of transactions to
5 enable the Company to negotiate fees with the vendors or
6 offer the service without charge to customers. However,
7 the number of transactions using this method of paying
8 bills has grown from 47,713 in 2003 to 186,435 in 2007.
9 Given the fact that the total number of transactions is
10 growing rapidly (nearly four times as many transactions
11 occurred in 2007 than in 2003), it is very apparent that
12 it is no longer just a few customers using the telephone
13 to pay their bills. The ability of customers to pay over
14 the telephone saves the Company money when customers use
15 this service to avoid being turned off for non-payment of
16 their account. The savings come from the Company not
17 being required to send a meter technician to the
18 customer's home to disconnect and subsequently reconnect
19 service. Although I have concerns about convenience
20 fees, particularly with respect to the impact on low
21 income customers and customers who are having trouble
22 paying their Idaho Power bills, more study is necessary
23 before I can make a recommendation about reducing or
24 eliminating these fees. At this time, I recommend that
25 the Company explore alternatives to requiring customers
CASE NO. IPC-E-08-10
10/24/08 1569 PARKER, M. (Di) 12
STAFF
.1 to pay convenience fees and report its findings to the
2 Commission Staff.
3 IRRIGATION DEPOSITS
4 Q.In the last few years, Idaho Power changed its
5 tariffs regarding when and how deposits are collected
6 from its irrigation customers. What were the primary
7 changes that Idaho Power made to its irrigation deposit
8 collection procedures?
9 A.Idaho Power created two new methodologies for
10 the collection of deposits from its irrigation customers.
11 The first for~ula is entitled "Tier One" and was created
12 in 2002 and the second is entitled "Tier Two" and was.13
14
created and added in 2004. The primary changes were that
the Company now: 1) uses the number of reminder notices
15 rather than late payments the customer received in the
16 previous twelve months as the determining factor in
17 assessing a deposit; 2) ties the amount of the deposit to
18 the electrical characteristics of the pump and motor
19 rather than the pump usage history from the previous
20 year; and, 3) assesses the higher Tier Two deposit if the
21 customer has an outstanding balance greater than $1000.00
22 on December 31 during any of the previous four years.
23 Q.Since Idaho Power changed its deposit
24 collection procedures for irrigation customers, has the.25 Commission received any complaints from irrigators?
CASE NO. IPC-E-08-10
10/24/08
1570 PARKER, M. (Di) 13
STAFF
.
.
.
1 A.Yes. The Commission has received seven
2 complaints from irrigators.
3 Q.What were the most significant issues voiced by
4 those complainants?
5 A.Two of the most recent complaints from
6 irrigators said they did not feel they had been
7 adequately informed of the new deposit collection
8 procedures.
9 Q.Do you concur with the complainants' concerns?
10 A.Yes. My investigation revealed that irrigation
11 customers have not been provided with detailed written
12 information regarding the Company's more stringent
13 deposit policy since May of 2005.
14 Staff reviewed copies of payment reminder
15 notices sent to irrigators and found them to be
16 inadequate. The notices did not make irrigation
17 customers aware of the deposit policy and so customers
18 were not able to avoid having to pay a deposit by
19 altering thir payment habits.
20 Q.Was Idaho Power responsive to the issues
21 mentioned above when brought to its attention?
22 A.Yes. Once the Company was aware of Staff's
23 concerns, it began to work immediately with Staff to
24 re-write its reminder notices. For example, wording was
25 added to reminder notices so that the consequences of
recei ving two. reminder notices in twelve months were
CASE NO. IPC-E-08-10
10/24/08 1571 PARKER, M. (Di) 14
STAFF
.
.
.
19
20
21
22
23
24
25
1 clearly stated. The Company also agreed to revise its
2 bill statement to include information on its deposit
3 policy. An annual brochure sent to irrigation customers
4 will be revised in time for next year's mailing. The
5 brochure will describe in detail the Tier One and Tier
6 Two deposit policy.
7 Q.The reason Idaho Power changed its irrigation
8 deposi t structure was to reduce uncollectible and
9 wri tten-off irrigation account balances. Has the goal
10 been met?
11 A.Reports from the Company show favorable
12 results. The Company reported to Staff that when
13 comparing 2007 with 2003, there had been a 73 percent
14 reduction in past due irrigation account balances and a
15 93 percent reduction in irrigation account written off
16 amounts.
17 Q.Does this conclude your direct testimony in
18 this proceeding?
A.Yes, it does.
CASE NO. IPC-E-08-10
10/24/08 1572 PARKER, M. (Di) 15
STAFF
.
.
.
1
2 open hearing.)
(The following proceedings were had in
4 for cross-examination.
MR. PRICE: Ms. Parker is now available
16
17
18
19
20
21
3
5
6 Mr. Ward.
7
8
9
10
11
12
13
14 Madam Chair.
15
22 late.
23
24
25 much.
COMMISSIONER SMITH: Thank you.
MR. WARD: No questions. Thank you.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Purdy.
MR. PURDY: I have nothing.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions,
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: No questions, Madam Chair.
COMMISSIONER SMITH: Ms. Nordstrom.
MS. NORDSTROM: No questions.
COMMISSIONER KEMPTON: No questions.
COMMISSIONER REDFORD: No questions.
COMMISSIONER SMITH: Nor I. It pays to go
THE WITNESS: Indeed.
COMMISSIONER SMITH: Thank you very
CSB REPORTING
[phone]
1573 PARKER
Staff
.
.
.
1
2
3
COMMISSIONER REDFORD: Thank you.
(The witness left the stand.)
4 Lobb to the stand.
MR. PRICE: Staff would now call Mr. Randy
5
6 RANDY LOBB,
7 produced as a witness at the instance of the Staff,
8 having been first duly sworn, was examined and testified
16
17
18
9 as follows:
10
11
12
13 BY MR. PRICE:
14
15 record?
A
19 Commission.
20
21
Q
A
22 division.
23 Q
Q
A
Q
DIRECT EXAMINATION
Could you please state your name for the
My name is Randy Lobb.
And who is your employer?
I'm employed by the Idaho Public Utilities
And what is your job title?
I am the administrator of the utili ties
And did you prepare written testimony in
24 this case on October 24th of this year?
25 A Yes, I did.
CSB REPORTING
[phone]
1574 LOBB (Di)
Staff
.
.
.
1 Q And do you have any corrections to that
2 wri tten direct testimony?
3 A I have a few corrections. Beginning on
4 page 4, it would be line 4, "2.9" at the end of that
5 sentence should be "1.4." Also, on page 4, line 9,
6 beginning on line 9, should be modified. It reads,
7 "revenue, depreciation expense, legal fees and interest
8 paid," continuing on 10, "on deferred director fees... ff.
9 Starting on line 9, it should read, "revenue,
10 depreciation expense and legal fees" and strike "and
11 interest paid on deferred director fees." Okay, on page
12 6, line 9, the "2000" should be "3000" and on line 10,
13 the "3000" should be "2000" and that's all the
14 corrections I' have.
15 Q Thank you, and if I were to pose the same
16 questions to you today that are contained in your written
17 direct testimony, would your answers be the same with
18 these corrections?
19
20
A Yes, they would.
MR. PRICE: I would now move that Mr.
21 Lobb' s testimony, prepared written direct testimony, be
22 spread upon the record as if read.
23 COMMISSIONER SMITH: Seeing no obj ection,
24 it is so ordered.
25 (The following prefiled direct testimony
of Mr. Randy Lobb is spread upon the record.)
CSB REPORTING'
[phone]
1575 LOBB (Di)Staff
.
.
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Randy Lobb and my business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed?
6 A.I am employed by the Idaho Public Utili ties
7 Commission as Utilities Division Administrator.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science Degree in
11 Agricultural Engineering from the University of Idaho in
12 1980 and worked for the Idaho Department of Water
13 Resources from June of 1980 to November of 1987. I
14 recei ved my Idaho license as a registered professional
15 Civil Engineer in 1985 and began work at the Idaho Public
16 Utilities Commission in December of 1987. My duties at
17 the Commission currently include case management and
18 oversight of all technical Staff assigned to Commission
19 filings. I have conducted analysis of utility rate
20 applications,. rate design, tariff analysis and customer
21 petitions. I have testified in numerous proceedings
22 before the Commission including cases dealing with rate
23 structure, cost of service, power supply, line
24 extensions, r~gulatory policy and facility acquisitions..25 Q.What is the purpose of your testimony in this
CASE NO. IPC-E-08-10
10/24/08 1576 LOBB, R. (Di) 1
STAFF
.
.
.
1 case?
2 A.The purpose of my testimony is to introduce
3 Staff witnesses, identify issues addressed by each and
4 discuss the various policy issues associated with this
5 case.
6 Q.Could you please describe Staff's filing in
7 this case?
8 A.Yes. Staff Auditor Cecily Vaughn begins with
9 actual audited cost data for the historical 12-month base
10 period of January 1, 2007 through December 31, 2007. She
11 then updates the historical data to reflect changes in
12 investment and expense levels through December 31, 2008.
13 The resulting annual revenue requirement increase
14 proposed by Staff is approximately $9.68 million for an
15 overall increase of 1.44%.
16 The revenue requirement proposal is based on
17 her recommendations for expense adjustments, the rate
18 base additions and expense adjustments of Staff
19 accounting witness Leckie, the various expense
20 adjustments of Staff accounting witness Nobbs, the power
21 supply expense adjustment of Staff Engineering witness
22 Sterling and the cost of capital recommendations of Staff
23 accounting witness Carlock.
24 Ms. Vaughn is responsible for summarizing all
25 revenue requirement adjustments in the jurisdictional
separations study model showing accounting and allocation
CASE NO. IPC-E-08-10
10/24/08 1577 LOBB, R. (Di) 2
STAFF
.
.
.
1 of Company costs. In addition, Ms. Vaughn specifically
2 discusses the Company's proposed treatment of Adjustment
3 for Funds Used During Construction (AFUDC) associated
4 wi th Hells Canyon relicensing construction work in
5 progress (CWIP). Ms. Vaughn recommends an adjustment of
6 $2.9 million to reflect a more accurate recovery in rates
7 of annual AFUDC accruals. Ms Vaughn also discusses her
8 recommended reduction of $885,000 in annual P-card
9 expendi tures and her $ 653,000 pass through to customers
10 of the Federal Energy Regulatory Commission (FERC)
11 credi t. Finally, Ms. Vaughn addresses the Company
12 proposal to increase various 2007 capital and expense
13 accounts using a compound annual growth rate (CAGR)
14 escalator. Ms. Vaughn recommends reducing the Company's
15 proposed increase in expense accounts from $15.9 million
16 to $1.75 million and reducing materials/supplies related
17 ratebase for an additional revenue requirement decrease
18 of $780,000.
19 Senior Staff Auditor Joe Leckie discusses
20 various adjustments to O&M expenses and verifies the
21 Company's rate base calculation. Mr. Leckie accepts the
22 Company's calculation of rate base using the 13-month
23 average, including Company proposed plant additions
24 through December 31, 2008, annualizing of major plant
25 addi tions and escalation in plant accounts under $2
CASE NO. IPC-E-08-10
10/24/08 1578 LOBB, R. (Di) 3
STAFF
1 million to arrive at a recommended rate base level of.2 approximately $2.1
3
4 /
5
6 /
7
8 /
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1579 LOBB,R.(Di)3a10/24/08 STAFF
.
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.
1 billion.
2 Mr. Leckie also proposes to limit salary
3 expense to known and measureable changes through 2008
4 resul ting in a reduction in Company proposed revenue
5 requirement of $1.4 million. Mr. Leckie further
6 recommends reductions in incentive payments ($3.2
7 million) and removes the 2009 Structured Salary
8 adj ustment (SSA) ($ 3.0 million). Additionally, he
9 recommends adjustments in miscellaneous revenue,
10 depreciation expense and legal fees to further reduce the
11 Company's request by $2.1 million. Finally, Mr. Leckie
12 discusses the. Company's limited application of cost
13 containment and the need to improve cost reduction
14 programs.
15 Staff Auditor John Nobbs addresses various 900
16 Series account expense adj ustments to reflect the
17 extraordinary level of expenses incurred in the historic
18 base year. Mr. Nobb's adjustments reduce the Company's
19 recommended test year revenue requirement by $667,000.
20 Senior Staff Engineer Rick Sterling is
21 responsible for review of the Company's Aurora power
22 supply model used to calculate annual net power supply
23 costs. Mr. Sterling proposes an adj ustment in the
24 natural gas price forecast used by the Company in its
25 modeling. The results of the forecast modification are
CASE NO. IPC-E-08-10
10/24/08 1580 LOBB, R. (Di) 4
STAFF
1 increases in fuel expenses,purchase power costs and.2 opportuni ty sales for an
3
4 /
5
6 /
7
8 /
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1581 LOBB,R.(Di)4a10/24/08 STAFF
.
.
.
1 overall decrease in Company proposed annual net power
2 supply expenses of $11.2 million.
3 Deputy Administrator and Audit Section
4 Supervisor Terri Carlock addresses cost of capital and
5 return on equity. Ms. Carlock recommends a return on
6 equi ty of 10.25% and a capital structure of approximately
7 51% debt and 49% equity for an overall recommended rate
8 of return of 8.057%.
9 Senior Staff Engineer Keith Hessing addresses
10 class cost of service (COS) methodology, class revenue
11 spread and the power cost adjustment (PCA) load growth
12 adj ustment component. Mr. Hessing recommends that the
13 Commission accept the 3cp/12cp cost of service
14 methodology proposed by the Company. Using the
15 jurisdictional allocation study modified to reflect
16 Staff's proposed adj ustments, Mr. Hessing applies the
17 cost of service (COS) study results to recommend class
18 revenue requirement changes ranging from no change for
19 some classes where COS suggests declines are warranted to
20 a 4.9% cap on the increase for the other classes where
21 larger increases are suggested by the COS. Mr. Hessing's
22 recommendation of no increase for the residential class,
23 when combined with his revenue recommendations for the
24 other classes, generates Staff's recommended overall
25 revenue requirement increase of 1.44 percent. Mr.
Hessing further recommends that the load
CASE NO. IPC-E-08-10
10/24/08 1582 LOBB, R. (Di) 5
STAFF
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1 growth adj ustment in the PCA remain unchanged from that
2 approved by settlement in Case No. IPC-E-07-08until the
3 Commission decides the issue in Case No. IPC-E-08-19.
4 Staff Economist Bryan Lanspery addresses issues
5 associated with residential rate design. After a review
6 of potential rate design al ternati ves and the Company's
7 proposal, Mr. Lanspery recommends that the Commission
8 adopt a three block tiered rate design with block breaks
9 at 1000 and 2000 kWh per month in winter months and 1000
10 kWh and 3000 kWh in summer months. Mr. Lanspery
11 determines that the current customer charge of $4.0 per
12 month combined with revenue generated under his summer
13 and winter three tiered energy rate proposal will provide
14 the current annual revenue requirement for the
15 residential class as recommended by Staff. Mr. Lanspery
16 also supports the Company's recommendation to adopt a
17 load factor based rate design for irrigation customers.
18 Staff economist Matt Elam addresses rate design
19 for all non residential customer classes except
20 irrigation. Mr. Elam evaluates and accepts the rate
21 design proposals of the Company for Schedules 7, 9 and 19
22 as adj us ted for Staff recommended class revenue
23 requirement. While Mr. Elam recommends no change in the
24 Schedule 7 customer charge, he specifically supports the
25 Company recommendation for a year round two tiered energy
rate. He also specifically
CASE NO. IPC-E-08-10
10/24/08 1583 LOBB, R. (Di) 6
STAFF
.
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1 supports the Company recommendation to implement
2 time-of-use (TOU) rates for Schedule 9 commercial
3 customers. Finally, Mr. Elam evaluates the effects of
4 TOU rates on large industrial Schedule 19 customers and
5 supports the Company proposal to increase TOU energy rate
6 differentials.
7 Staff Economist Lynn Anderson addresses the
8 demand side management (DSM) expenditures made by the
9 Company over the last two years. Mr. Anderson recommends
10 that the Commission defer approval of the Company's DSM
11 program expenditures from the DSM tariff rider for
12 calendar years 2003 through 2007 until sufficient
13 information is provided to evaluate prudency. Mr.
14 Anderson spec~fies what information should be provided in
15 terms of program specific DSM expenditures and resultant
16 energy savings for presentation in future DSM or general
17 rate proceedings.
18 Finally, Consumer Investigators Marilyn Parker
19 and Curtis Thaden address a broad range of consumer
20 issues. Ms. Parker concludes that the Company has done a
21 reasonable job of reducing overall customer complaints
22 and improving overall customer service. She specifically
23 recommends that the Company be directed to re-evaluate
24 the convenience fees it charges for electronic payments.
25 Mr. Thaden provides information on customer
CASE NO. IPC-~-08-10
10/24/08 1584 LOBB, R. (Di) 7
STAFF
1 income levels and employment levels and evaluates the low.2 income programs provided by the Company.
3
4 /
5
6 /
7
8 /
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1585 LOBB,R.(Di)7a10/24/08 STAFF
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1 Q.What has been your role in this case?
2 A.My role as Staff Administrator has been to
3 oversee the preparation of the Staff case with respect to
4 identification of issues, coordination of positions on
5 those issues and development of Staff policy.
6 Q.What are the important policy issues in this
7 case?
8 A.In my opinion, the most important policy issues
9 include establishing the rate case test year, identifying
10 revenue requirement adjustments, assigning cost of
11 service responsibility and applying appropriate rate
12 design.
13 TEST YEA
14 Q. What is the Company's proposed test year in
15 this case?
16 A.The Company proposes to use a 12-month test
17 year ending December 31, 2008.
18 Q.Does this represent a change from test year
19 proposals made by the Company in past cases?
20 A.Yes , it does represent a change in terms of the
21 methods used to establish test year levels for revenues,
22 expenses, investment totals and determine annual revenue
23 requirement.
24
25
Q.Please explain.
A.In past rate cases, the Company has used a
CASE NO. IPC-E-08-10
10/24/08 1586 LOBB, R. (Di) 8
STAFF
1 variety of approaches to establish what it believes to.2 be a
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1587 LOBB,R.(Di)8a10/24/08 STAFF
.
.
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1 representati ve annual revenue requirement recoverable
2 through rates. It has used 12 months of actual historic
3 cost data updated for known and measurable changes. It
4 has proposed a split test year that utilizes 6 months of
5 actual booked costs and 6 months of forecasted or
6 budgeted costs, with actual cost provided before hearing,
7 to establish annual revenue requirement and set rates.
8 In its last case, the Company proposed a 12-month test
9 period using fully budgeted costs.
10 In this case, the Company has proposed to start
11 with 12 months of actual 2007 booked costs and then
12 update those costs by including known and measurable
13 expense changes, annualizing for partial year
14 expendi tures, annualizing for maj or plant additions as if
15 they were in service for the entire year and finally,
16 inflating a variety of expense and capital accounts based
17 on the annual growth rate in those accounts over prior
18 years.
19 Q.Why has the Company continually changed the
20 method by which it determines annual revenue requirement?
21 A.The Company argues that the methodology changes
22 are necessary to reduce the effects of "regulatory lag"
23 and improve the Company's ability to earn its authorized
24 return.
25 Q.
A.
What is "regulatory lag"?
Regulatory lag generally refers to the delay
CASE NO. IPC-E-08-10
10/24/08 1588 LOBB, R. (Di) 9
STAFF
.
.
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1 between when the Company actually requests cost recovery
2 and when new Commission approved rates become effective
3 to recover those costs.
4 Q.How does the Company proposed test year in this
5 case address "regulatory lag"?
6 A.The Company's proposed test year addresses
7 regulatory lag in the following ways:
8 1) It updates actual account expenditures
9 incurred during a historical base test period to reflect
10 known and measurable future changes through year-end
11 2008. Salaries are escalated through 2009.
12 2) It annualizes partial year test period
13 expendi tures to reflect the fact that costs will be
14 incurred in the future for the entire year.
15 3) It includes forecasted plant additions to
16 be completed before December 31, 2008.
17 4) . It annualizes major plant additions (over
18 $2 million) completed before December 31, 2008 as if they
19 were in service for the entire year.
20 5) It escalates various expense and capital
21 accounts by a compound annual growth rate (CAGR) based on
22 the growth in that account in prior years.
23 6) It forecasts variable power supply costs
24 based on estimated 2008 average customer totals.
25 Q.What is Staff's position with respect to the
CASE NO. IPC-E-08-10
10/24/08 1589 LOBB, R. (Di) 10
STAFF
.
.
.
1 Company's proposed test year and adj ustments?
2 A.Staff generally accepts the Company proposed
3 2008 test year that begins with actual 2007 calendar year
4 costs updated through December 31, 2008. There are
5 notable exceptions associated with forecast methodology.
6 Items 1 and 2 listed above dealing with traditional known
7 and measurable changes and annualization of existing
8 partial year costs have been accepted in the past by the
9 Commission and are supported by Staff in this case.
10 Staff has recommended that salary changes be limited to
11 year-end 2008.
12 Staff also supports the inclusion of major
13 plant additions (in excess of $2 million) expected to be
14 completed prior to December 31, 2008 and annualizing such
15 plant as if it were in service for the entire year.
16 While this adjustment has been allowed by the Commission
17 in the past on a proj ect by proj ect basis for very large
18 plant additiops, it has not been approved across the
19 board for proj ects as small as $2 million. The
20 Commission has historically required expense reducing or
21 revenue producing offsets to match project cost recovery
22 in rates. Al though the Company has included a revenue
23 producing impact for some plant in this case, it has not
24 included any impact for others.
25 Staff supports some but not all of the Company's
CASE NO. IPC-E-08-10
10/24/08 1590 LOBB, R. (Di) 11
STAFF
.
.
.
1 proposed escalation of expense and capital accounts on
2 the basis of a CAGR. Staff witness Vaughn addresses the
3 Company's proposal and recommends that escalation be
4 limi ted to select accounts with more reasonable
5 increases. The effect of this recommendation is an annual
6 revenue requirement that is $15.01 million less than that
7 proposed by the Company.
8 Q.Company witness Gale states in testimony that
9 the methodology used by the Company to escalate historic
10 expense and capital account totals was consistent with
11 input received by Staff and others in workshops
12 addressing forecasted test years. Why then does Staff
13 oppose the Company's full application of this
14 methodology?
15 A.Staff agrees that the methodology used by the
16 Company in this case, an escalator applied to historic
17 account totals, is superior to the fully budgeted future
18 test year proposed by the Company in its last general
19 rate case. The impact of the forecast in this case can
20 at least be evaluated. However, Staff does not believe
21 that the Company's choice of escalator or the accounts
22 chosen for escalation reasonably meet the "known and
23 measureable" cost standards.
24 Q.Can. any forecasted increase meet the "known and
25 measurable" cost standard?
CASE NO. IPC-E-08-10
10/24/08 1591 LOBB, R. (Di) 12
STAFF
1 A.I believe it is very difficult to meet the.2 known
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1592 LOBB,R.(Di)12a10/24/08 STAFF
.
.14
1 and measurable standard using any budget proj ection,
2 forecast or estimate of future costs. However, Staff has
3 tried to balance the need for timely cost recovery with
4 the Commission's obligation to audit and verify that
5 costs have been or will be reasonably incurred. That is
6 why Staff has agreed to support including major capital
7 investment in rates before some of the costs are actually
8 incurred and before the plant is actually in service.
9 These maj or investments are scheduled to be online by
10 December 31, 2008, to be used and useful when rates are
11 effective. Staff has also agreed to go beyond the 13
12 month average' rate base for major plant additions to
13 include plant in rate base as if it had been in service
for the entire year. Furthermore, Staff has agreed to use
15 forecasted 2008 customer totals to establish annual
16 variable power supply costs. Finally, Staff has agreed
17 to escalate capital accounts and some expense accounts
18 using the Company proposed CAGR. While Staff does not
19 agree with all of the recommended forecasted increases,
20 it has agreed. to cautiously move beyond the strict
21 interpretation of what has traditionally been "known and
22 measurable" .
23 Q.Why does Staff agree with the Company's
24 proposal to account for 2008 capital expenditures?.25 A. Staff recognizes the impact of growing load on
Company expenditures and the need to include major plant
CASE NO. IPC-E-08-10
10/24/08 1593 LOBB, R. (Di) 13
STAFF
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.
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1 additions in rates on a more timely basis. Consequently,
2 Staff supports the Company's proposal for treatment of
3 2008 plant additions in excess of $2 million. The
4 expected expenditures and the timeline for these
5 addi tions are generally known and measureable. .
6 Staff has also agreed in this case to accept
7 the Company's proposal to escalate (at 6%) 2008 plant
8 addi tions with the exception of Staff witness Vaugh's
9 recommended reduction for escalated materials and
10 supplies in ratebase, of less than $2 million. Staff
11 does not believe that this adjustment necessarily reaches
12 the same level of need nor is it as justified from a
13 known and measurable standpoint. Nevertheless, Staff
14 recognizes the smaller capital requirements associated
15 with growing load and will continue to evaluate the
16 meri ts of escalating these capital accounts in future
17 rate cases. Staff witness Leckie addresses this issue
18 further in his testimony.
19 STAFF ADJUSTMNTS
20 Q.Staff has recommended a reduction of $56.9
21 million in the annual revenue requirement proposed by
22 Idaho Power Company. In what areas were the adj ustments
23 made?
24 A.The annual revenue requirement adj ustments were
25 primarily made in the following areas.
CASE NO. IPC-E-08-10
10/24/08
1594 LOBB, R. (Di) 14
STAFF
1 1 )A decrease of $16.9 million due to a.2 recommended reduction in return on equity from
3
4 /
5
6 /
7
8 /
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1595 LOBB,R.(Di)14a10/24/08 STAFF
.
.
1 11.25% to 10.25%.
2 2) A decrease of $15.01 million due to
3 reductions in the Company's proposed CAGR
4 O&M/materials supplies account escalation.
5 3) A decrease of $11.2 million in proposed
6 variable power supply cost.
7 4) A $7.3 million adjustment that includes an
8 increase in miscellaneous revenues, a reduction
9 in legal fees, miscellaneous expenses and
10 P-card expenses, a reduction in depreciation
11 expense, a reduction in annual AFUDC recovery
12 associated with Hells Canyon relicensing and
13 spreading of a prior FERC credit.
14 5) A decrease of $4.6 million due to
15 reductions in 2008 salary adjustments, a
16 reduction in anticipated 2008 employee and
17 executive salary incentives and elimination of
18 forecasted 2009 salary increases.
19 Q.You mention above a reduction in the Company
20 proposed adjustment for funds used during construction
21 (AFUDC) associated with Hells' Canyon relicensing. Does
22 Staff oppose the recovery of Hell's Canyon AFUDC in this
23 case?
24.25
A.No. In fact Staff agrees that AFUDC recovery
through rates is justified in this case. While Staff
CASE NO. IPC-E-08-10
10/24/08 1596 LOBB, R. (Di) 15
STAFF
.
.
.
1 would not normally recommend recovery of any proj ect cost
2 before the proj ect is completed and expenditures
3 appropriately reviewed, the magnitude of deferred
4 construction work in progress (CWIP) costs, the magnitude
5 of AFUDC associated with those costs and the length of
6 the relicensing process make it necessary in this
7 instance.
8 Staff agrees with the Company that the current
9 AFUDC accrual on an annual basis should be recovered
10 through rates as an expense rather than allowed to accrue
11 in the deferred account for later recovery through rates
12 as a capital investment. The AFUDC adj ustment proposed
13 by Staff simply reflects what Staff believes is a more
14 accurate estimate of annual AFUDC accrual. Staff also
15 believes that AFUDC accrual on Hells Canyon relicensing
16 CWIP should cease after 2009 with a filing by the Company
17 to incorporate all proj ect costs in rates. Staff witness
18 Vaughn discusses the AFUDC adjustment further in her
19 testimony.
20 Q.How were the areas and magnitude of other Staff
21 adjustments determined?
22 A.The areas for adjustment were identified as a
23 result of extensive Staff audit of Company books and an
24 evaluation of the methodology and justification used by
25 the Company to update actual 2007 booked costs to the
2008 test year levels.
CASE NO. IPC-E-08-10
10/24/08 1597 LOBB, R. (Di) 16
STAFF
.
.
.
16
1 Staff's overall approach in developing revenue
2 requirement is to identify expenses and investment that
3 are inappropriate or otherwise excessive and should not
4 be subj ect to recovery from customers. Addi tionally,
5 Staff evaluated the methodology used by the Company to
6 increase or adjust actual costs to reflect future costs
7 that are expected to be incurred. Staff has tried to
8 balance the need for timely cost recovery with the need
9 to assure that costs are appropriately incurred, and
10 capital investments are both used and useful in providing
11 utility service and known and measurable for recovery
12 through rates.
13 The specific rationale and justification for
14 each adj ustment is further addressed in the testimony of
15 individual Staff witnesses.
Q.Do you believe the Staff recommendation for a
17 1.44% revenue requirement increase in this case balances
18 the needs of the Company with the needs of its customers?
19 A.Yes, I do. While Staff has taken a critical
20 look at all underlying Company expenses, the proposed
21 adj ustments have been limited almost entirely to return
22 on equity and forecasted increases in expenses for 2008.
23 In fact, except for the CAGR adjustment in materials and
24 supplies addressed by Staff witness Vaughn, Staff
25 recommended no adj ustments to Company proposed capital
addi tions. At the same time, Staff has agreed to a broad
CASE NO. IPC-E-08-10
10/24/08 1598 LOBB, R. (Di) 17
STAFF
.
.
.
20
1 range of adj ustments to the historical base year in
2 developing the 2008 test year designed to allow more
3 timely recovery of capital investment and expenses.
4 These previously discussed adjustments include annualized
5 capi tal additions forecasted for completion in 2008, CAGR
6 escalation of capital plant additions of less than $2
7 million, CAGR escalation of O&M expense accounts, the use
8 of variable power supply costs using forecasted 2008
9 loads and recovery of annually accumulated AFUDC
10 associated with Hell's Canyon relicensing.
11 I believe Staff's recommendations serve
12 customers by limiting rate recovery to a reasonable level
13 of Company costs. While not moving to a fully forecasted
14 test year as recommended by the Company, Staff has agreed
15 to cautiously move from the traditional definition of
16 known and measureable adjustments of historical data to
17 allow test year adj ustments based on estimates and
18 forecasts.
19 COST OF SERVICE
Q.What other policy positions has the Staff taken
21 in this case?
22 A.The remaining policy issues deal primarily with
23 class cost of service allocation methodology, rate spread
24 among the classes and rate design. Staff's positions on
25 these issues were developed in conjunction with the
CASE NO. IPC-E-08-10
10/24/08 1599 LOBB, R. (Di) 18
STAFF
1 technical Staff who address those issues in testimony.2 filed
3
4 /
5
6 /
7
8 /
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.IPC-E-08-10 1600 LOBB,R.(Di)18a10/24/08 STAFF
.
.
.
1 in this case and are discussed by those witnesses.
2 Generally , it is the Staff's policy to maintain
3 consistency between rate cases with regard to power
4 supply, jurisdictional allocations and class cost of
5 service methodologies. Staff believes its methodologies
6 in this case for these functions adhere to that policy.
7 Wi th respect to cost of service, Staff believes
8 that the 3cp/12cp methodology proposed by the Company
9 reasonably allocates costs to the various classes. Staff
10 believes, and Mr. Hessing explains in his testimony, that
11 the small changes in this methodology over that last
12 approved by the Commission in Case No. IPC-E-03-13 is
13 justified by more accurately assigning cost based on
14 causation. Specifically, the recommended cost of service
15 study provides a more accurate allocation of production
16 costs based on how production plant is used, when it is
17 used and the value of the plant at the time it is used.
18 Wi th respect to revenue spread among the
19 classes, Staff believes that cost of service is an
20 inexact science to be used as a guide in setting class
21 revenue requirement. That is why Staff witness Hessing
22 uses cost of service in his proposal to move toward, but
23 not all the way to, cost of service as indicated by the
24 study. Mr. Hessing's proposal provides rate stability by
25 limiting revenue requirement changes within each class to
a relatively small
CASE NO. IPC-E-08-10
10/24/08 1601 LOBB, R. (Di) 19
STAFF
.
.
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1 range. Although cost of service in conj unction with
2 Staff's proposed revenue requirement could have justified
3 a reduction in residential rates, it was determined that
4 no increase was most appropriate. This approach
5 recognizes the potential bill reducing impact on
6 residential customers of the tiered rate design and the
7 moderating effect on other classes of no change in the
8 residential revenue requirement.
9 RATE DESIGN
10 What is Staff's policy with respect to rateQ.
11 design within the customer classes?
12 A.Staff's policy with respect to rate design is
13 to balance the need to send appropriate price signals
14 wi th the need to have relatively stable rates and
15 appropriate revenue recovery.
16 Q.What is Staff's position with respect to the
17 rate design recommendations of the Company?
18 A.Staff believes the Company has done a good job
19 of proposing customer rates that meet the Staff
20 objectives described above. In fact, the Company
21 proposal to establish residential tiered rates year round
22 and increase the first energy block from 300 to 600 kWh
23 per month was quite reasonable. Staff also agrees with
24 the Company's rate design proposals based on irrigation
25 load factor and the Time of Use (TOU) rate proposed for
CASE NO. IPC-E-08-10
10/24/08 1602 LOBB, R. (Di) 20
STAFF
.
.
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1 large commercial customers. These rate design proposals
2 recognize the principal that rates should follow costs
3 wi thout sacrificing rate stability. With adj ustments for
4 its revenue requirement recommendation, Staff supports
5 all of the rate design recommendations of the Company
6 wi th the exception of the Schedule 1 residential rate and
7 customer charges for Schedule 7.
8 Q.Why has Staff proposed a different rate
9 structure for the residential customer class?
10 A.Staff simply believes that we can and should do
11 more to send the most appropriate price signal to as many
12 residential customers as possible. That is why Staff has
13 made the three tiered inverted block rate proposal to
14 provide at least two break points where rates change to
15 reflect higher production costs. Certainly, time of use
16 (TOU) rates made available with the installation of
17 automated meters will allow the Company to send a broad
18 range of price signals to customers that better reflect
19 cost of service. The multiple tiered rate structure
20 serves a similar role until TOU rates are implemented.
21 Staff witness Lanspery provides greater detail on Staff's
22 residential rate design recommendation.
23 Q.Does this conclude your direct testimony in
24 this proceeding?
25 A.Yes, it does.
CASE NO. IPC-E-08-10
10/24/08 1603 LOBB, R. (Di) 21
STAFF
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 MR. PRICE: And I'll make Mr. Lobb
4 available for cross-examination.
5 COMMISSIONER SMITH: Mr. Richardson, do
6 you have questions?
7 MR. RICHARDSON: I do, Madam Chair.
8
9 CROSS-EXAMINATION
10
11 BY MR. RICHARDSON:
12 Q Good evening, Mr. Lobb.
13 A Good evening.
14 Q Let's start with page 15 of your direct at
15 the very bottom over to the top of page 16, "While Staff
16 would not normally recommend recovery of any proj ect cost
-
17 before the proj ect is completed and expenditures
18 appropriately reviewed, the magnitude of deferred
19 construction work in progress (CWIP) costs, the magnitude
20 of AFUDC associated with those costs and the length of
21 the relicensing process make it necessary in this
22 instance. " What is the magnitude of those two items that
23 you are referring to?
24
25
A . My understanding of the deferred CWIP is
that approximately, and I don't have the numbers before
CSB REPORTING
[phone]
1604 LOBB (X)Staff
.
.
.
1 me, but a substantial portion in the neighborhood of
2 $50 million is CWIP and the remainder of the total 96
3 million, and these are rough numbers, but I think the
4 relationships are the same, are the AFUDC on the actual
5 construction cost, so those are the magnitude, the CWIP
6 and the AFUDC.
7 Q $50 million, approximately?
8 A Well, the total balance is nearly 100
9 million.
10 Q Okay, and the amount of CWIP is
11 A It's about half that.
12 Q Okay, and CWIP is -- stands for
13 construction work in progress; is that right?
14 A That's right.
15 Q And why would you not normally recommend
16 recovery of CWIP in rates?
17 A Mostly because CWIP is associated with
18 proj ects under construction that have not been completed
19 or costs incurred associated with proj ects that haven't
20 been completed are not used and useful and in service,
21 and so in my view, it would be improper to include
22 CWIP-related costs for those types of proj ects.
23 Q But because of the magnitude of these two
24 items, you are recommending CWIP to be recovered in
25 rates?
CSB REPORTING
[phone]
1605 LOBB (X)Staff
.
.
.
1 A It's a combination of the magnitude and
2 the time frame that these costs were incurred and the
3 costs that customers are going to incur over time and
4 it's Staff's position that the compounding of AFUDC upon
5 AFUDC year after year will cause customers to pay more in
6 the long run when that total deferred AFUDC that's
7 compounded year after year is put in rate base.
8 Q And you're the Staff's policy witness on
9 this issue?
10 A That's correct.
11 Q So I'm going ask you a couple of policy
12 questions on CWIP and ask if you agree or not with these
13 statements. In general, isn't it true that CWIP in rates
14 forces customers to pay for property not currently
15 used -- not currently being used to serve customers?
16 A In most cases, I agree with that, but in
17 the case of the relicensing of the hydroelectric proj ects
18 on the Snake River, those projects are generating power,
19 are used and useful and I think there is the opportunity
20 and the requirement to make a distinction in this case.
21 Q Oh, I understand and that's why I was
22 asking you from a policy standpoint.
23 A Okay. No, I agree, in most cases, you're
24 correct.
25 Q And maybe Hells Canyon is unique because
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1606 LOBB (X)Staff
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1 it's up and running right now, but I just want to talk
2 about the Staff's policy.
3 A Okay.
4 Q And isn't it also true that CWIP in rates
5 should -- isn't it true that CWIP in rates doesn't
6 correspond to the current costs of providing service?
7 A I think that's generally true.
8 Q And isn't it also true that CWIP in rates
9 blurs the traditional roles of investors and
10 ratepayers?
11 A Could you give an example of what you
12 mean?
13 Q Well, yeah, I can, because isn't it true
14 that CWIP in rates confiscates ratepayers ' capital
15 because the cost of money is less to the Company than it
16 is to the ratepayers?
17 A I think it has been viewed that way, and
18 from a ratepayer standpoint, large industrial customers,
19 for example, might consider that the case.
20 Q And isn't it also true that CWIP in rates
21 dampens management's incentive for prudent resource
22 planning and aggressive cost control?
23 A I don't have any information that would
24 indicate that that's the case necessarily.
25 Q Would you agree that CWIP in rates amounts
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1607 LOBB (X)Staff
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1 to a political allocation of capital?
2 MR. PRICE: I'm going to object to the
3 form of that question. I don't think Mr. Lobb can make a
4 statement as to the political impact.
5 MR. RICHARDSON: May I approach the
6 wi tness in response, Madam Chair?
7 COMMISSIONER SMITH: You may.
8 MR. RICHARDSON: Thank you.
9 (Mr. Richardson aproached the witness.)
10 MR. RICHARDSON: Madam Chair, I'm handing
11 the witness a multiple-page document. This is an excerpt
12 from a document entitled, "Errata Notice" and "Order No.
13 99204" and, Mr. Lobb, I'LL hand you the full Order in
14 case you want to familiarize yourself with the full Order
15 rather than just the excerpt. I'll give you a moment to
16 familiari ze yourself with the document.
17 THE WITNESS: Okay, I'm familiar with it
18 generally.
Q BY MR. RICHARDSON: So you are the policy,
20 Staff policy, witness on CWIP; correct?
21
22
A Yes.
Q And have you reviewed prior policy
23 statements by this Commission on CWIP?
24
25
A I have not reviewed this Order, no.
Q Okay, this is an Order that was issued by
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1608 LOBB (X)Staff
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1 the PUC about 18 months prior to the time the legislature
2 passed the Idaho Code 502A which prohibited this
3 Commission from authorizing CWIP in rates, so it was
4 probably, as far as my research can find, one of the last
5 statements of this Commission of its policy on CWIP and
6 so I would ask you to read for the Commissioners -- I'm
7 not going to mark it as an exhibit because it's already a
8 Commission document and were you in the room yesterday
9 when I was visiting with one of the Company witnesses on
10 CWIP, Mr. Gale?
11 A Yes, I was.
12 Q Okay, and I handed out an Order and asked
13 him to read from it. Do you recall that?
14 A Yes, I do.
15 Q Okay, and so let's start on this handout
16 at the top of page 17. It's discussing the Order that we
17 handed out to Mr. Gale yesterday, so if you could read
18 for the record those first two paragraphs.
19 COMMISSIONER SMITH: Mr. Richardson,
20 before we start, I just want to clear up something. You
21 know, the front page of this says that this is an Errata
22 Notice in this case.
23 MR. RICHARDSON: I can clear that up for
24 you, Madam Chairman.
25 COMMISSIONER SMITH: And it doesn't have
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1609 LOBB (X)Staff
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1 an Order number, so it's hard for me to believe that's
2 the front page of 17546.
3 MR. RICHARDSON: It's the front page of
4 what the Commission has published on its website for that
5 Order. Apparently, the person downloading your documents
6 decided to attach the errata on top of the Order, so it
7 is an errata to this Order number, but it's not the cover
8 page of the Order.
9 COMMISSIONER SMITH: Right.
10 MR. RICHARDSON: But I'm not marking it
11 for--
12 COMMISSIONER SMITH: I understand that.
13 Okay, thank you for clearing that up.
14 Q BY MR. RICHARDSON: So reading at the top
15 of page -- turn to page 17 of Order 17546, would you read
16 us the first two paragraphs, please?
17 A "Order No. 16945 was issued barely nine
18 months ago, on December 9, 1981. The Commission
19 continues to adhere to the views stated in that Order.
20 We note, however, that our exclusion of CWIP from rate
21 base is not a knee-j erk reaction to talismanic
22 incantation of the phrase 'used and useful.' In a narrow
23 sense, that phrase could be taken as a denial of any
24 responsibility from one generation to the next, as in the.25 cynical attitude, 'What has posterity ever done for me?'
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1610 LOBB (X)Staff
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1 Taken in that sense, it would never make sense for the
2 elderly or for childless couples to pay a school tax, or
3 for anyone to ever plant a redwood tree. We are not
4 advocating the short-sighted and mean-spirited principle
5 that this generation should not prepare for or contribute
6 to the needs of the next."
7 Do you want me to read the next paragraph
8 as well?
9 Q Please do.
10 A "Rather, we focus on more fundamental
11 principles of risk allocation in the regulatory process.
12 Stockholders provide capital for investment in new plant.
13 In exchange for a return on that investment, the
14 stockholders incur certain risks. Those risks have
15 become painfully apparent in the Northwest in recent
16 months with the collapse of one nuclear proj ect after
17 another. The' full history of these proj ects has yet to
18 be told, but it is obvious that a great deal of blame can
19 be traced to lack of oversight and of diligent managerial
20 supervision. It is entirely proper that shareholders
21 bear the risks occasioned by corporate managerial
22 decisions. Exclusion of CWIP from rate base is one means
23 of providing an incentive to bring projects on line in a
24 timely and budget-conscious manner. Others may be.25 possible, but they have not been explored in this case.
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1 The Commission therefore reaffirms its traditional policy
2 of denying inclusion of CWIP in rate base."
3 Q Thank you, and in response to the
4 objection to my question, that Order that you just read
5 from is reaffirming the language on the preceding page,
6 on page 16, wherein the Commission identified CWIP as a
7 poli tical allocation of capital, so does that help you
8 understand what -- can you respond to my question, will
9 you agree that CWIP in rates does amount to a political
10 allocation of capital?
11 A Well, at this time the Commission made a
12 fairly strong statement about including CWIP in rates for
13 various types of proj ects. Now, I guess our proposal in
14 this case is to give the Commission what we believe is
15 the proper approach for this particular proj ect in the
16 treatment of CWIP in this particular case given the fact
17 that it is legal to do so, is my understanding, and the
18 Commission can decide if they want to continue with a
19 policy of absolutely not including CWIP.
20 Q It was legal in your mind for the
21 Commission to do so when it issued its Order; correct?
22
23
A I understand.
Q Okay, and when you as a policy witness
24 decided to advocate for CWIP in rates in this case, you
25 testified you didn't do any research on the Commission's
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1 prior policy statements or pronouncements on CWIP in rate
2 base?
3 A I did not review this Order, no.
4 MR. RICHARDSON: Thank you, Madam Chair.
5 That's all I have.
6 COMMISSIONER SMITH: Mr. Purdy, do you
7 have questions of Mr. Lobb?
8 MR. PURDY: No, ma'am, I do not.
9 MR. OLSEN: No questions.
10 COMMISSIONER SMITH: Mr. Ward.
11 MR. WARD: Just a couple.
12
13 CROSS-EXAMINATION
14
15 BY MR. WARD:
16 Q Mr. Lobb, if at the time the Staff was
17 preparing its testimony or even before that when it was
18 making its decisions on key issues in this case, if at
19 that time you. had known the general economic
20 circumstances we would find ourselves in today with, just
21 to tick off a few, certainly mushrooming unemployment,
22 financial meltdown in somewhat historic proportions,
23 would you nec~ssarily, would the Staff necessarily, have
24 come to the same conclusion about recommending the
25 inclusion of this particular CWIP item in this case?
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1 A I believe that we would because of, as I
2 stated, the nature of the accrual, the type of proj ect
3 that we're dealing with and what we believed was a
4 significantly higher cost in the future if we fail to do
5 this. It seems to me that right now we're allowing
6 recovery of these costs through an expense. We're
7 returning the money to the Company, but they don't earn a
8 return on it and if you leave it in CWIP and allow it to
9 accrue, they both return the dollars, get a return on the
10 dollars and get return of the dollars, and this is a
11 project, as I say, that's used and useful and continues
12 to be that way.
13 Q Well, with regard to whether the proj ect
14 is used and useful, of course, the project itself is used
15 and useful, but there is no permanent license which is
16 what I understand Idaho Power is pursuing here and I
17 admit, my understanding of relicensing is very crude, but
18 as I understand it, it operates under a temporary license
19 until the final disposition is made; is that correct?
20 A That's correct.
21 Q So in that sense, this is kind of
22 unusual -- well, this is very unusual, but still, the
23 license which is in question is not used and useful
24 because it's not granted yet.
25 A That's true, that's true, the license is
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1614 LOBB (X)Staff
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1 not granted.
2 Q And I have just a little bit different
3 understanding of political allocation of capital than
4 implied by Mr. Richardson's questions which I think I can
5 illustrate with this question. Leaving aside the strange
6 si tuation of the hydro relicensing here and let's just
7 take a typical proj ect, the Company is building a
8 combined cycle plant and asks for CWIP in rate base
9 before the plant is in fact operating and producing.
10 That's a more typical situation, is it not?
11 A That's correct.
12 Q And in that case, absent government
13 intervention in some fashion, can any, can you think of
14 any entity in a free market or in a free enterprise
15 system that can ever recover not only the cost of its
16 capital, but a return on its capital before it can
17 produce the first widget?
18 A No, but I think that has to be also
19 balanced with the Company's obligation to serve and
20 that's the regulatory compact and I think you can't
21 disregard that obligation.
22 Q Right, but would you agree with me that
23 the only way that anomaly can occur, that is, a recovery
24 of and on capital prior to actual production, is some
25 sort of political intervention or let's call it
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1615 LOBB (X)Staff
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1 governmental intervention? Take out the loaded term.
2 A I guess I would answer the question this
3 way and that is that when the Staff looked at putting
4 this case together and we looked at forecasted test years
5 and regulatory lag and proper recovery, timely recovery
6 of costs, cash flow issues, we believed that this was one
7 of the more appropriate ways that you could provide cash
8 flow. Now, you asked -- it was asked earlier whether or
9 not in this economic environment we would have made this
10 decision. Well, you certainly could have put it off.
11 You could have allowed the deferrals to accrue and you
12 could pay later and customers will pay later, I suspect.
13 This is not the type of project, relicensing costs,
14 that's very easy to go back after the fact and disallow a
15 lot of cost. In my experience, that has been the case.
16 Now, is this something that is done for other businesses,
17 cost recovery before they actually build widgets, no,
18 it's not.
19 MR. WARD: Thanks. That's all I have.
20 COMMISSIONER SMITH: Let's go off the
21 record for a moment.
22 (Off the record discussion.)
23 COMMISSIONER SMITH: All right, Mr. Kline.
24
25
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1 CROSS-EXAMINATION
2
3 BY MR. KLINE:
4 Q Mr. Lobb, I do want to follow up just a
5 li ttle bit more on the Staff's recommendation on the
6 handling of CWIP. On page 16, starting on line 13, you
7 talk about Staff recommending that the Company make a
8 filing at the end of 2009 to include the relicensing
9 costs in rates at that time and cease recording AFUDC.
10 Do you see that?
11 A That's correct.
12 Q All right. Now, as Ms. Vaughn noted, the
13 Company doesn't have an awful lot of control over the
14 FERC as to when that permanent license is going to be
15 issued. Do you remember that testimony?
16 A I do.
Q What happens if we don't have a permanent
18 license in 2009? We make the filing, but we continue to
19 accrue costs in, say, 2010, whatever, would you continue
20 to accrue AFUDC on the costs the Company is incurring
21 after it makes the filing that you have contemplated
22 here?
23 A I certainly think we'd want to look at it
24 at that time. I think we expect the Company to file
25 another rate case, perhaps, at a later time, but
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1617 LOBB (X)Staff
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1 obviously, we recognize that the relicensing is not
2 entirely in the hands of the Company, but we want to make
3 sure that the Company does everything they can to
4 finalize that process.
5 Q And, of course, you would agree that if
6 the Company is continuing to accrue AFUDC on those, on
7 that CWIP, CWIP not in rate base, it is entitled by law
8 to accrue AFUDC?
9 A Yes.
10 MR. KLINE: That's all I had.
11 COMMISSIONER SMITH: Are there questions
12 from the Commission?
13 COMMISSIONER KEMPTON: Madam Chairman, I
14 don't have a question, but I would like to make note of
15 the fact that the question asked by Mr. Richardson
16 involved the term political allocation of capital which
17 was coined by Mr. Bertschi and he is not here where I can
18 ask him clarifying definitions of that term and so at a
19 minimum, this has to be hearsay.
20 COMMISSIONER SMITH: All right, Mr. Price,
21 do you have any redirect?
22 MR. PRICE: Yeah, I have a couple of quick
23 ones.
24
25
COMMISSIONER SMITH: That's the wrong
answer.
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6 BY MR. PRICE:
7 Q
MR. PRICE: I'm sorry.
COMMISSIONER SMITH: Go ahead.
REDIRECT EXAMINATION
Mr. Lobb, is it your understanding that
8 Staff's proposal includes an AFUDC carrying charge, but
9 it does not include all CWIP costs in rate base?
10 A Yes.
Okay, and when you were considering cash
12 flow, wasn't the need for capital a large part of that
11 Q
14 A Absolutely, and I think we've addressed
19 you, Mr. Lobb.
13 consideration?
15 that in our treatment of the capital additions in the
16 Company's general rate case, in this case.
17
18
MR. PRICE: Nothing further.
COMMISSIONER SMITH: Thank you, and thank
20 (The witness left the stand.)
21 COMMISSIONER SMITH: And we're at the end
22 of today. I suggest that we start 9: 00 in the morning
23 and--
24
25
MR. PRICE: Madam Chair?
COMMISSIONER SMITH: Yes.
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1619 LOBB (Di)Staff
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MR. PRICE: I was going to make a motion,
a Bench motion, at this time, I was wondering if we could
3 start at the very minimum a little later than 9: 00
4 o'clock.
5 COMMISSIONER SMITH: We'll be off the
6 record. In fact, we'll just be adj ourned and you can go
7 and we'll hash this out.
8 (The Hearing recessed at 6: 40 p.m.)
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