20081024Hessing Direct.pdf

BEFORE THE RECEIVED
20De OCT 24 PH 3: 28
IDAHO PUBLIC UTILITIES COMMISSION IDAHO PUBLIC
UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO.IPC-E-08-10
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE )
TO ELECTRIC CUSTOMERS IN THE STATE)OF IDAHO. )
)
)
)
DIRECT TESTIMONY OF KEITH HESSING
IDAHO PUBLIC UTILITIES COMMISSION
OCTOBER 24, 2008
1
2 the record.
Q.Please state your name and business address for
3 A.My name is Keith D. Hessing and my business
4 address is 472 West Washington Street, Boise, Idaho.
5
6
Q.By whom are you employed and in what capacity?
A.I am employed by the Idaho Public Utilities
7 Commission as a Public Utilities Engineer.
8
9
Q.What is your education and experience background?
A.I am a Registered Professional Engineer in the
10 State of Idaho. I received a Bachelor of Science Degree in
11 Civil Engineering from the University of Idaho in 1974.
12 Since then, I worked six years for the Idaho Department of
13 Water Resources, and two years for Morrison-Knudsen. I
14 have been continuously employed at the Commission since
15 August 1983.
16 As a member of the Commission Staff, my primary
17 areas of responsibility have been electric utility power
18 supply, cost allocation, rate design and power cost
19 adjustment (PCA) mechanisms.
20 Q.What is the purpose of your testimony in this
21 proceeding?
22 A.I will address the areas of Jurisdictional
23 Separations, Customer Class Cost of Service, Revenue
24 Allocation and the Power Cost Adjustment (PCA) Mechanism.
25 Q.Please summarize your testimony.
CASE NO. IPC-E-08-1010/24/08 HESSING, K (Di)
STAFF
1
1 A.I accept the Company's Jurisdictional Separations
2 methodology and allocators and the results they produce
3 using Staff adjusted accounting information. Those results
4 are presented in Staff witness Cecily Vaughn's testimony.
5 I accept the Company's proposal to change cost of
6 service methodology to the 3CP/12CP method from the Base
7 Case method that was approved in Case No. IPC-E- 03 - 13.
S Based on a 1.44 percent overall increase in revenue, I
9 propose that individual class increases be capped at 4.9
10 percent and that no class receive a decrease. I propose
11 that classes not impacted by the cap or floor be moved to
12 full cost of service.
13 I propose that PCA computational factors, such as
14 base case power supply costs, energy amounts and the
15 jurisdictional energy allocator used in the Company's Power
16 Cost Adjustment (PCA) mechanism, be updated to reflect
17 Staff's case. I propose that cloud seeding base costs and
1S revenues remain unchanged. I also propose that the load
19 growth adjustment factor used in the PCA remain unchanged
20 while the Commission processes Case No. IPC-E-OS-19 which
21 addresses the methodology and proposes a new load growth
22 adjustment factor.
24
23 JUISDICTIONAL SEPARTIONS
Q.What is the purpose of Jurisdictional
25 Separations?
CASE NO. IPC-E-OS-1010/24/0S HESSING, K (Di)
STAFF
2
1 A.The Jurisdictional Separations process identifies
2 the Idaho jurisdiction's share of total Company costs and
3 revenues and establishes the Idaho jurisdictional revenue
4 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
S the revenue requirement to change between rate cases -
9 changes in accounting information, changes in
10 jurisdictional characteristics (demand, energy and customer
11 numbers) and changes in separations methodology. I will
12 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 to
16 the system. Other Staff witnesses have testified
17 concerning accounting data and appropriate adjustments.
1S 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 every
22 year. These are things like coincident peak demands,
23 annual energy use and numbers of customers by jurisdiction.
24 The fact that these characteristics change on a relative
25 basis is important because they are used to separate or
CASE NO. IPC-E-OS-1010/24/0S HESSING, K (Di)
STAFF
3
1 allocate total Company costs to the various jurisdictions.
2 Staff Exhibit No. 129 demonstrates the changes that have
3 occurred in these characteristics over the Company's four
4 most recent general rate cases including this one. For
5 demonstration purposes only one demand, one energy and one
6 customer allocator are shown. Each category has one or
7 more other allocators that are also used in the
8 jurisdictional separations study. It is significant that
9 while energy and peak loads have grown along with total
10 system costs, the Idaho jurisdiction's share of the
11 Company's costs has changed very little since the Company's
12 last case. This can be observed by the change from the
13 last rate case to this rate case in the major demand and
14 energy allocators. The D10 allocator has not change from
15 .950 and the E10 allocator grew from .947 to .948. In
16 other words, the Idaho jurisdiction was allocated 95.0% of
17 demand related costs in the last rate case and in this case
18 Idaho ratepayers would again be allocated 95.0% of system
19 demand related costs.
20 As pointed out in Company testimony,
21 jurisdictional separations methodology has remained largely
22 unchanged for a very long period of time. When
23 Jurisdictional Separations methodology does not change and
24 major allocators change little, the accounting data drives
25 the changes in the Idaho Jurisdictional Revenue
CASE NO. IPC-E-08-1010/24/08 HESSING, K (Di)
STAFF
4
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 adjustments to the accounting data and the
7 Return on Equity. Staff's Jurisdictional Separations
8 results are presented as Staff Exhibit No. 125 to Staff
9 witness Cecily Vaughn's testimony. Staff proposes
10 an Idaho Jurisdictional revenue requirement of $682,850,888
11 that requires an overall rate increase of $9,681,348 or
12 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 various
19 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 related
23 and each rate class's percentage share of energy use,
24 demand use or number of customers is applied to the costs
25 to divide them among the various rate classes or rate
CASE NO. IPC-E-08-10
10/24/08 HESSING, K (Di)
STAFF
5
1 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 Case"
6 as a guide in allocating costs to the various rate classes.
7 In this case the Company is proposing a change to a method
8 that the Company calls "3CP/12CP". The IPC-E-05-28 general
9 rate case that followed the IPC-E-03-13 case was a settled
10 case that spread costs to classes on a uniform percentage
11 basis and, therefore, did not use cost of service results.
12 Case No. IPC-E-07-8 that followed the 05-28 case was also a
13 settled case that used no specific cost of service study to
14 allocate the Idaho jurisdictional revenue requirement to
15 customer classes.
16 Q.What are the differences between the Base Case
17 method and 3CP/12CP method?
18 A.The differences are in the classification and
19 allocation of Production Plant. The Base Case method
20 classifies all production plant investment, except the
21 Company's gas fired peaking unit investment, as energy and
22 demand related based on the Idaho jurisdictional load
23 factor. The Idaho jurisdictional load factor is 59.38%.
24 Therefore, approximately 59% of these costs were classified
25 as energy related and allocated using an energy allocator,
CASE NO. IPC-E-08-10
10/24/08 HESSING, K (Di)
STAFF
6
1 and approximately 41% were classified as demand related and
2 allocated using a demand allocator. Gas fired peaking unit
3 investment was classified as 100% demand related. Both
4 energy and demand allocators were based on twelve months of
5 data weighted by the marginal cost of energy or demand,
6 respectively, from the Company's marginal cost study.
7 The proposed 3CP/12CP cost of service method
8 classifies base load and intermediate load plant
9 investment, hydro and thermal generating resources, as
10 energy related and demand related based on the Idaho
11 jurisdictional load factor just as the Base Case method
12 does. The Company's peaking resource investment in natural
13 gas fired plant is classified as 100% demand related as in
14 the Base Case study. However, different demand allocators
15 are applied. Demand related peaking unit investment is
16 allocated using an unweighted 3CP allocator based on the
17 Company's three summer peak months of June, July and
18 August. Other demand related production investment
19 associated with serving base and intermediate load is
20 allocated using an unweighted 12CP allocator. The energy
21 related portion of base and intermediate load production
22 plant investment is allocated based on marginal cost
23 weighted class energy use.
24 Q.What other changes in cost of service methodology
25 from IPC-E-03-13 is the Company proposing?
CASE NO. IPC-E-08-10
10/24/08 HESSING, K (Di)
STAFF
7
1 A.The Company is proposing to classify Account 555
2 - Purchased Power costs (market purchases and PURPA
3 purchases) as energy and demand related based on the system
4 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 occurred
7 since the 03-13 case is a change in the way coincident peak
8 demand allocators are determined. The 03 - 13 cost of
9 service study used actual test year coincident peak demands
10 to determine the allocation factor. Following that case
11 workshops were held to discuss a number of cost of service
12 issues. As part of that process the parties agreed to use
13 a 5 -year median coincident peak demand to normalize the
14 allocation factor. The Company has applied this
15 methodology in all cases since the 03 - 13 case.
16 Q.What is the difference in study results between
17 the 03-13 Base Case method and the 3CP/12 CP method
19
18 proposed by the Company in this case?
Company witness Tatum presents the results ofA.
20 three cost of service studies that he prepared in Company
21 Exhibit No. 69. The results of the Base Case study and the
22 3CP/12CP study are included and show similar trends.
23 Q.Which method do you propose the Commission
25
24 accept?
I recommend that the Commission accept theA.
CASE NO. IPC-E-08-10
10/24/08 HESSING, K (Di)
STAFF
8
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 by
6
5 Staff?
7
A.Yes. Staf f Exhibit No. 130 shows those results.
Q.Do your results show the same general pattern as
9
8 the results presented by the Company in Exhibit No. 69?
Yes. The special contract customers, Micron,A.
10 Simplot and DOE, along with the Large Power customers
11 served under Schedule 19 and the Irrigation class show a
12 need for a much higher than average increase if their rates
13 are to be set at full cost of service. Residential
15
14 customers are shown to deserve a decrease.
Q.Ar~ these results similar to cost of service
16 results from the IPC-E-03-13 case?
17 No. Cost of service results did not indicateA.
18 higher than average cost increases for the high load factor
20
19 customer classes in that case.
21 cost of service results that have occurred since the
Q.How do you explain the significant changes in
23
22 IPC-E-03-13 case?
A.There are a number of circumstances that have
24 caused changes in cost of service results. Load growth,
25 substantially in the residential class, has occurred in
CASE NO. IPC-E-08-1010/24/08 HESSING, K (Di)
STAFF
9
1 record amounts. The cost of power supply to meet the
2 growing load, at approximately 6Ç/kWh, has been much higher
3 than it used to be. Under cost of service methodology a
4 disproportionately larger share of all costs, old and new,
5 are allocated to the residential class because the
6 residential classes percentage share of energy, peak demand
7 and customers has increased.A mix of old and new costs
8 is also allocated to all other classes even if they
9 experienced no load growth. No customer class is entitled
10 to rates based on a grandfathered share of old costs. In
11 the cost of service model the residential class received
12 credi t for all of the revenue from its load growth at near
13 6ç/kWh and a portion of the production cost increases at
14 about the same rate. In the cost of service study the
15 increased revenues offset the increased costs and the
16 Residential Class is shown to deserve an increase below the
17 Idaho Jurisdictional average, or even a decrease as
18 demonstrated in Staff's results.
19 High load factor customer groups are situated
20 differently. They are allocated a reduced portion of all
21 costs, old and new, and have little or no new revenue to
22 offset the new costs. The new costs more than offset the
23 cost reduction due to the decrease in the allocation
24 percentages and without additional revenue rates go up.
25 Therefore, cost of service results indicate increases
CASE NO. IPC-E-08-1010/24/08 HESSING, K (Di) 10
STAFF
1 higher than the average.
2 Even if there were substantial growth in the high
3 load factor classes, their revenue at about 3Ç/kWh would
4 not offset marginal power supply costs at about 6Ç/kWh.
5 The size of the increase may be decreased, but there would
6 still be an above average increase for high load factor
7 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 service
11 study. The explanation that I have provided addresses the
12 cost trends for the large customer classes. There are many
13 other factors that are also driving changes in cost of
14 service results such as differences in methodology,
15 allocation factors, distribution and transmission costs,
16 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 recent
20 general rate case filings - IPC-E-05-28, IPC-E-07-8 and the
21 current case.
22 Q.Is there any reason to believe that the trend
23 will not continue?
24 A.No. It is largely driven by the high marginal
25 power supply cost of serving new load. I expect load to
CASE NO. IPC-E- 08 - 1010/24/08 HESSING, K (Di) 11
STAFF
1 continue to grow and marginal costs to remain significantly
2 higher than high load factor customer rates.
4
3 REVENU ALLOCATION
5 Service results contained in Staff Exhibit No. 130?
Q.How do you propose the Commission use the Cost of
6 A.In general, I propose that Cost of Service
7 results be used as a guide in establishing class revenue
8 requirements for the various rate classes. I view Cost of
9 Service results as an imprecise science that is
10 appropriately used as a starting point in revenue
11 allocation.
12 Q.What customer class allocation of the Idaho
13 Jurisdictional revenue requirement do you recommend?
14 A.Staff's Cost of Service results are based on an
15 average Idaho jurisdictional retail rate increase of 1.44
16 percent. However, some individual class increases vary
17 substantially from the average. For this reason I
18 recommend that cost of service results not be strictly
19 followed, but that the results be used as a guide in
20 establishing class revenue requirements.
21 It is my recommendation that no class receive a
22 rate decrease and that increases be capped at 4.9 percent.
23 All customer classes in between would be moved to full cost
24 of service. This approach diminishes rate shock and moves
25 all classes toward cost of service.
CASE NO. IPC-E-08-1010/24/08 HESSING, K (Di) 12
STAFF
1 Q.Have you prepared an exhibit that shows the
3
2 resul ts of your proposal?
Yes. I have prepared Staff Exhibit No. 131. AsA.
4 you can see, Schedules 19, 24, 42 and the special contract
5 customer schedules would receive the maximum increase of
6 4.9%. Schedules 1, 7, 15, 40 and 41 would receive no
7 increase or decrease. Schedule 9 would be moved to full
8 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.
15
14 POWER COST ADJUSTMNT (PCA) MECHAISM
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
22
21 level.
Q.Have you prepared a similar exhibit that presents
23 your quantification of appropriate PCA computational
25
24 factors?
A.Yes, I have. Staff Exhibit No. 133 contains the
CASE NO. IPC-E-08-1010/24/08 HESSING, K (Di) 13
STAFF
1 information in the Company's proposal from Company Exhibit
2 No. 51 along with my proposal. My proposal is based on
3 Staff's case.
4 Q.Please discuss the factors presented in your
5 proposal to the extent that they differ from the Company's
6 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 a
10 different natural gas price input to that model than the
11 Company did. This difference is discussed in more detail
12 in Staff witness Rick Sterling's testimony. Also the Staff
13 proposes to continue the use of the Commission ordered base
14 revenue and cost amounts for cloud seeding. These
15 differences are also the cause of the difference in the
16 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 Q.Please discuss your recommendation for the load
25 growth adjustment rate.
CASE NO. IPC-E-08-10
10/24/08 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 applied
8 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 growth
11 adjustment rate?
12 A.Yes. Company Exhibit No. 50 shows a 2008
13 marginal power supply cost of $56.48 per MWh. Staff
14 Exhibit No. 134 shows a 2008 marginal power supply cost of
15 $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. IPC-E- 08 - 19
20 before it which contains a stipulated settlement that
21 changes the computational method and the rate. I believe
22 that it is appropriate for load growth adjustment rate
23 changes to be considered in that case.
24 Q.You said that the PCA Forecast equation is also
25 normally updated in a general rate case. Please discuss
CASE NO. IPC-E-08-1010/24/08 HESSING, K (Di) 15
STAFF
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 regression
8 formula based on Commission approved power supply costs
10
9 could be prepared at that time.
Does this conclude your direct testimony in thisQ.
11 proceeding?
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Yes, it does.A.
CASE NO. IPC-E- 08 - 1010/24/08 HESSING, K (Di) 16
STAFF
Case No. IPC-E-08-10
Comparison of Historic Jurisdictional Allocators
Oregon &
Classification Allocator Case No.Units Idaho FERC Total
Demand 010 IPC-E-03-13 kW 2,076,437 121,967 2,198,404
010 IPC-E-05-28 kW 2,102,069 121,411 2,223,480
010 IPC-E-07-08 kW 2,281,542 120,809 2,402,351
010 IPC-E-08-10 kW 2,335,595 121,919 2,457,514
010 IPC-E-03-13 Allocator 0.945 0.055 1.000
010 IPC-E-05-28 Allocator 0.945 0.055 1.000
010 IPC-E-07-08 Allocator 0.950 0.050 1.000
010 IPC-E-08-10 Allocator 0.950 .0.050 1.000
Energy E10 IPC-E-03-13 kWh 13,275,012 832,564 14,107,576
E10 IPC-E-05-28 kWh 13,950,521 868,631 14,819,152
E10 IPC-E-07-08 kWh 14,784,934 827,764 15,612,698
E10 IPC-E-08-10 kWh 15,036,726 826,902 15,863,628
E10 IPC-E-03-13 Allocator 0.941 0.059 1.000
E10 IPC-E-05-28 Allocator 0.941 0.059 1.000
E10 IPC-E-07-08 Allocator 0.947 0.053 1.000
E10 IPC-E-08-10 Allocator 0.948 0.052 1.000
Customer CW903 IPC-E-03-13 Weighted Customers 6,581,117 292,716 6,873,833
CW903 IPC-E-05-28 Weighted Customers 8,910,067 379,961 9,290,028
CW903 IPC-E-07 -08 Weighted Customers 8,910,067 379,961 9,290,028
CW903 IPC-E-08-10 Weighted Customers 7,873,470 309,347 8,182,817
CW903 IPC-E-03-13 Allocator 0.957 0.043 1.000
CW903 IPC-E-05~28 Allocator 0.959 0.041 1.000
CW903 IPC-E-07 -08 Allocator 0.959 0.041 1.000
CW903 IPC-E-08-10 Allocator 0.962 0.038 1.000
Exhibit No. 129
Case No. IPC-E-08-10
K. Hessing, Staff
10/24/08
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Exhibit No. 130
Case No. IPC-E-08-10
K. Hessing, Staff
10/24/08
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Comparison of Cost Of Service Results and Revenue Allocation Proposals
Case No. IPC-E-08.10
Company Staff
COS COS
Results Results
Rate 3CP/12CP 3CP/12CP
Line Sch.Percent Company Percent Staff
No Tariff Description No.Change Proposal Change Proposal
%%%%
Uniform Tariff Rates:
1 Residential Service 1 3.71 6.31 (4.51)0.00
2 Small General Service 7 7.91 10.63 (1.02)0.00
3 Large General Service 9 8.73 11.46 0.60 0.60
4 Dusk to Dawn Lighting 15 (41.85)2.51 (50.19)0.00
5 Large Power Service 19 15.87 15.00 6.77 4.90
6 Agricultural Irrigation Service 24 28.54 15.00 19.74 4.90
7 Unmetered General Service 40 (2.57)2.51 (10.22)0.00
8 Street Lighting 41 (29.24)2.51 (37.87)0.00
9 Traffic Control Lighting 42 44.20 15.00 33.68 4.90
Special Contracts:
10 Micron 26 24.41 15.00 14.51 4.90
11 J R Simplot 29 28.14 15.00 17.91 4.90
12 DOE 30 25.37 15.00 15.63 4.90
13 Total Idaho 9.89 9.89 1.44 1.44
Exhibit No. 132
Case No. IPC-E-08-10
K. Hessing, Staff
10124/08
peA Computational Factors
Case No. IPC.E.QS.10
Normalized PCA Expense
Normalized Power Supply Expense
Normalized CSPP
Cloud Seeding Expense
Cloud Seeding Revenue
Normalized PCA Expense
Normalized Base PCA Rate Computation
Normalized System Firm Sales
Normalized Base PCA Rate
Idaho Jurisdictional Percentage Computation
Normalized System Firm Load
Idaho Jurisdictional Firm Load
Idaho Jurisdictional Percentage
Expense Adjustment Rate for Growth
Applied to one-half of load growth
Units
MWh
Ø/kWh
MWh
MWh
%
$/MWh
2007
Settlement
$
$
$
$
$
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93,080,631
892,084
(1,427,334)
127,510,051
14,239,222
0.8955
15,612,699
14,784,934
94.7%
62.79
Company Staff
Proposal Proposal
2008 2008
Test Year Test Year
88,421,246 77,576,480
63,269,889 63,269,889
892,084
(1,427,334)
151,691,135 140,311,119
14,465,151 14,465,151
1.0487 0.9700
15,863,628 15,863,628
15,036,726 15,036,726
94.8%94.8%
62.79
Exhibit No. 133
Case No. IPC-E-08-10
K. Hessing, Staff
10/24/08
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 24TH DAY OF OCTOBER 2008,
SERVED THE FOREGOING DIRECT TESTIMONY OF KEITH HESSING, IN CASE
NO. IPC-E-08-1O, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L KLINE
LISA D NORDSTROM
DONOV AN E WALKER
IDAHO POWER COMPANY
POBOX 70
BOISE ID 83707-0070
E-MAIL: bkline(iidahopower.com
Inordstrom(iidahopower .com
dwalker(iidahopower.com
PETER J RICHARDSON
RICHARDSON & O'LEARY
PO BOX 7218
BOISE ID 83702
E-MAIL: peter(irichardsonandolear.com
RANDALL C BUDGE
ERICLOLSEN
RACINE OLSON NYEET AL
PO BOX 1391
POCATELLO ID 83204-1391
E-MAIL: rcb(iracinelaw.net
elo(iracinelaw.net
MICHAEL L KURTZ ESQ
KURT J BOEHM ESQ
BOEHM KURTZ & LOWRY
36 E SEVENTH ST STE 1510
CINCINATI OH 45202
E-MAIL: mkurz(iBKLlawfrm.com
kboehm(iBKLlawfrm.com
BRADMPURDY
ATTORNEY AT LAW
2019 N 17TH ST
BOISE ID 83702
E-MAIL: bmpurdy(ihotmail.com
JOHN R GALE
VP - REGULATORY AFFAIRS
IDAHO POWER COMPANY
POBOX 70
BOISE ID 83707-0070
E-MAIL: rgale(iidahopower.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: dreading(imindspring.com
ANTHONY Y ANKEL
29814 LAKE ROAD
BAY VILLAGE OH 44140
E-MAIL: yanel(iattbi.com
KEVIN HIGGINS
ENERGY STRATEGIES LLC
PARKS IDE TOWERS
215 S STATE ST STE 200
SALT LAKE CITY UT 84111
E-MAIL: khiggins(ienergystrat.com
LOTH COOKE
ARTHUR PERRY BRUDER
UNITED STATE DEPT OF ENERGY
1000 INDEPENDENCE AVE SW
WASHINGTON DC 20585
E-MAIL: lot.cooke(ihq.doe.gov
arhur. bruder(ihg .doe. gOY
CERTIFICATE OF SERVICE
DWIGHT ETHERIDGE
EXETER ASSOCIATES INC
5565 STERRTT PLACE, SUITE 310
COLUMBIA MD 21044
E-MAIL: detheridge(iexeterassociates.com
DENNIS E PESEAU, Ph.D.
UTILITY RESOURCES INC
1500 LIBERTY STREET SE, SUITE 250
SALEM OR 97302
E-MAIL: dpeseau(iexcite.com
CONLEY E WARD
MICHAEL C CREAMER
GIVENS PURSLEY LLP
601 W BANNOCK ST
PO BOX 2720
BOISE ID 83701-2720
E-MAIL: cew(igivenspursley.com
KEN MILLER
CLEAN ENERGY PROGRAM DIRECTOR
SNAKE RIVER ALLIANCE
PO BOX 1731
BOISE ID 83701
E-MAIL: kmiler(isnakeriverallance.org
~~SECRETAR
CERTIFICATE OF SERVICE