20071210Hessing direct.pdf

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
zuni DEC '0 Plî 3: 3f:
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-01-8
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE )
IN THE STATE OF IDAHO. )
)
)
)
)
DIRECT TESTIMONY OF KEITH HESSING
IDAHO PUBLIC UTILITIES COMMISSION
DECEMBER 10, 2007
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 Utilities
7 Commission as a Public Utili ties Engineer.
8 Q.What is your educational 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 in
12 Civil Engineering from the University of Idaho in 1974.
13 Since then, I worked six years for the Idaho Department of
14 Water Resources, and two years for Morrison-Knudsen. I
15 have been continuously employed at the Commission since
16 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 and rate design.
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, Rate Design and the Power Cost Adjustment (PCA)
25 Mechanism.
CASE NO. IPC-E-07-812/10/07 HESSING, K (Di)
STAFF
1
1 Q.Please summarize your testimony.
2 A.I accept the Company's Jurisdictional Separations
3 methodology and allocators and the results they produce
4 using Staff adjusted accounting information. Those results
5 are presented in Staff witness Donn English's testimony.
6 I rej ect the Company's proposal to change cost of
7 service methodology to what Idaho Power calls the 3CP/12CP
8 method from the current method that the Company calls Base
9 Case . Given the 2.82 percent overall increase proposed by
10 Staff, I propose that individual class increases be capped
11 at 10 percent and that no class receive a decrease. I
12 propose that other classes be moved toward cost of service.
13 I propose to maintain the rate structure
14 currently in place. Due to the relatively small increase
15 proposed by Staff, I propose that non-energy rates remain
16 unchanged and that increases be spread on energy rates. I
17 propose an exception for the Irrigation Class. I recommend
18 that class receive an increase of 10% and I propose that
19 all rate components be increased by that percentage.
20 I propose that PCA computational factors, such as
21 base case power supply costs, energy amounts and the
22 jurisdictional energy allocator used in the Company's Power
23 Cost Adjustment (PCA) mechanism, be updated to reflect
24 Staff's case. I also propose that the Expense Adjustment
25 Rate for Growth (EARG) , also known as the load growth
CASE NO. IPC-E-07-812/10/07
HESSING, K (Di)
STAFF
2
1 adjustment factor, used in the PCA be updated based on the
2 marginal cost of power supply as ordered by the Commission
3 in Case No. IPC-E-06-0S. This is significantly different
4 than the Company's proposal to calculate the EARG based on
5 an incremental cost methodology. The Company's number is
6 29.16 $/MWh and my number is 62.79 $/MWh.
7 JUISDICTIONAL SEPARTIONS
S Q.What is the purpose of Jurisdictional
9 Separations?
10 A.The Jurisdictional Separations process identifies
11 the Idaho jurisdiction's share of total Company costs and
12 revenues and establishes the Idaho jurisdictional revenue
13 requirement.
14 Q.What causes the Idaho jurisdictional revenue
15 requirement to change between rate cases?
16 A.In general there are three things that can cause
17 the revenue requirement to change between rate cases;
1S changes in accounting information, changes in
19 jurisdictional characteristics (demand, energy and customer
20 numbers) and changes in separations methodology. I will
21 briefly discuss each of the three.
22 Account balances change every year. Some cost
23 categories increase and some decrease. Generally, costs
24 increase, but so do revenues as new customers are added to
25 the system. Other Staff witnesses have testified
CASE NO. IPC-E-07-S12/10/07 HESSING, K (Di). 3
STAFF
1 concerning accounting data and appropriate adjustments.
2 Account balances change between rate cases and those
3 changes appropriately drive changes in the Idaho
4 jurisdictional revenue requirement.
5 Jurisdictional characteristics also change every
6 year. These are things like coincident peak demands,
7 annual energy use and numbers of customers by jurisdiction.
S The fact that these characteristics change on a relative
9 basis is important because they are used to separate or
10 allocate total Company costs to the various jurisdictions.
11 Staff Exhibit No. 116 demonstrates the changes that have
12 occurred in these characteristics over the Company's three
13 most recent general rate cases including this one. For
14 demonstration purposes only one demand, one energy and one
15 customer allocator are shown. Each category has one or
16 more other allocators that are also used in the
17 jurisdictional separations study. It is significant that
1S while energy and peak loads have grown along with total
19 system costs, the Idaho jurisdiction's share of the
20 Company's costs has also grown. This is demonstrated by
21 the change from the last rate case to this rate case in the
22 maj or demand and energy allocators. The D10 allocator grew
23 from. 945 to .950 and the E10 allocator grew from .941 to
24 .947. In other words, the Idaho jurisdiction was allocated
25 94.1% of energy related costs in the last rate case and
CASE NO. IPC-E-07-S12/10/07
HESSING, K (Di)
STAFF
4
1 under the Company's proposal in this case Idaho ratepayers
2 would be allocated 94.7% of system energy related costs.
3 The changes shown in Staff Exhibit No. 116 are consistent
4 with the jurisdictional changes described in Company
5 testimony. The allocation reflects that the City of Weiser
6 is no longer a FERC jurisdictional customer and that Idaho
7 Peak demand and energy use has grown faster than peak
S demand and energy use in Oregon.
9 As pointed out in Company testimony,
10 jurisdictional separations methodology has remained largely
11 unchanged for a very long period of time. This case does
12 include a minor change in the methodology used to establish
13 coincident peak demands associated with weather normalized
14 usage. That change involves the use of the median value
15 from the most recent five years instead of the actual test
16 year value. This relatively small change in methodology
17 should contribute to improved stability of the allocation
1S factor and thus the Idaho jurisdictional revenue
19 requirement.
20 Q.Do you accept Idaho Power's Jurisdictional
21 Separations study?
22 A.I accept the methodology and allocation factors
23 proposed by the CompanYi however, other Staff witnesses
24 have proposed adj ustments to the accounting data and the
25 Return on Equity. Staff's Jurisdictional Separations
CASE NO. IPC-E-07-S12/10/07 HESSING, K (Di)
STAFF
5
1 results are presented as Staff Exhibit No. 112 to Staff
2 witness Donn English's testimony. Those results indicate
3 an Idaho Jurisdictional revenue requirement of $635,272,967
4 that requires an overall rate increase of $17,452,699 or
5 2.82 percent.
6 CLASS COST OF SERVICE
7 Q.What is the purpose of a Customer Class Cost of
8 Service Study?
9 A.A Customer Class Cost of Service Study divides
10 the Idaho Jurisdictional Revenue Requirement that results
11 from the Jurisdictional Separations Study among the various
12 Idaho rate classes.
13 Q.Is the Company proposing to change the Cost of
14 Service method most recently accepted by the Commission?
15 A.Yes. In the IPC-E-03-13 general rate case the
16 Commission used a method that the Company calls "Base Case"
17 as a guide in allocating costs to the various rate classes.
18 In this case the Company is proposing a change to a method
19 that the Company calls "3CP/12CP". The IPC-E-05-28 general
20 rate case that followed the IPC-E-03-13 case was a settled
21 case that spread costs to classes on a uniform percentage
22 basis and, therefore, did not use cost of service results.
23 Q.What are the differences between the Base Case
24 method and 3CP/12CP method?
25 A.The differences are in the classification and
CASE NO. IPC-E-07-812/10/07 HESSING, K (Di)
STAFF
6
1 allocation of Production Plant. The Base Case method
2 classifies all production plant investment, except the
3 Company's gas fired peaking unit investment, as energy and
4 capacity related based on the Idaho jurisdictional load
5 factor. The Idaho jurisdictional load factor is 58.53%.
6 Therefore, approximately 58% of these costs were classified
7 as energy related and allocated using an energy allocator,
8 and approximately 42% were classified as demand related and
9 allocated using a demand allocator. Gas fired peaking unit
10 investment was classified as 100% demand related. Both
11 energy and demand allocators were based on twelve months of
12 data weighted by the marginal cost of energy or capacity,
13 respectively, from the Company's marginal cost study.
14 The 3CP/12CP method classifies base load and
15 intermediate load plant investment for hydro and thermal
16 resources as demand related and energy related based on the
17 Idaho jurisdictional load factor just as the Base Case
18 method does. The Company's peaking resource investment in
19 natural gas fired plant is classified as 100% demand
20 related as in the Base Case study. However, different
21 demand allocators are applied. Demand related peaking unit
22 investment is allocated using an unweighted 3CP allocator
23 based on the Company's three summer peak months of June,
24 July and August. Other demand related production
25 investment associated with serving base and intermediate
CASE NO. IPC-E-07-812/10/07
HESSING, K (Di)
STAFF
7
1 load is allocated using an unweighted 12CP allocator. The
2 energy related portion of base and intermediate load
3 production plant investment is allocated based on marginal
4 cost weighted class energy use.
5 Q.What is the difference in study results between
6 the two methods?
7 A.Company witness Tatum presents the results of
S four cost of service studies that he prepared in Company
9 Exhibit No. 57. The results of the Base Case study and the
10 3CP/12CP study are included and show similar trends. A
11 table on page 16 of Company witness Tatum's testimony
12 summarizes the methodology differences among the four
13 studies.
14 Q.Which method do you propose the Commission
15 accept?
16 A.I recommend that the Commission stay with the
17 Base Case method. The Company proposed 3CP/12CP method has
1S some appeal and may be an appropriate method for use at
19 some point in the future. However, the Cost of Service
20 issues in this case center on the fact that high load
21 factor customer classes are in line to receive
22 approximately twice the average increase under the
23 Company's proposal. It is easier to identify and discuss
24 the causes of this result if the primary methodology is
25 unchanged.
CASE NO. IPC-E-07-S12/10/07 HESSING, K (Di)
STAFF
S
1 Q.Does your testimony include an exhibit showing
2 Cost of Service results using the Base Case method and the
3 Idaho jurisdictional revenue requirement proposed by Staff?
4
5
A.Yes. Staff Exhibit No. 117 shows those results.
Q.Do your results show the same general pattern as
6 the results presented by the Company in Exhibit No. 57.
7 Yes. The special contract customers, Micron,A.
S Simplot and DOE, along with the Large Power customers
9 served under Schedule 19 show a need for a much higher than
10 average increase if their rates are to be set at full cost
11 of service. Residential customers are shown to deserve a
12 decrease.
13
14 results from the IPC-E-03-13 case?
Q.Are these results similar to cost of service
15 A.No. Cost of service results did not indicate
16 higher than average cost increases for the high load factor
17 customer classes in that case.
1S
19 cost of service results that have occurred since the
Q.How do you explain the significant changes in
21
20 IPC-E-03-13 case?
There are a number of circumstances that haveA.
22 caused changes in cost of service results. Load growth,
23 substantially in the residential class, has occurred in
24 record amounts. The cost of power supply to meet the
25 growing load has been much higher than it used to be,
CASE NO. IPC-E-07-S12/10/07 HESSING, K (Di)
STAFF
9
1 approximately 6Ç/kWh. Under approved cost of service
2 methodology these costs have been allocated
3 disproportionately to the residential class, however, some
4 of these high costs are allocated to all other classes as
5 well. In the cost of service model the residential class
6 received credit for all of the revenue from its load growth
7 at near 6Ç/kWh and a portion of the production cost
S increases at about the same rate. In cost of service the
9 revenues offset the costs and the Residential Class is
10 calculated to receive an increase below the Idaho
11 Jurisdictional average, or even a decrease as demonstrated
12 in Staff's results.
13 High load factor customer groups are situated
14 differently. They get allocated a portion of the costs
15 associated with residential growth and have little or no
16 revenue to offset those costs. Therefore, cost of service
17 resul ts indicate increases higher than the average. Even
1S if there were substantial growth in the high load factor
19 classes, the revenue at about 3Ç/kWh would not offset
20 marginal power supply costs at 6Ç/kWh. The size of the
21 increase would probably be decreased, but there would still
22 be an above average increase for high load factor
23 customers.
24 Q.Does your explanation explain cost of service
25 trends since the IPC-E- 03 - 13 case?
CASE NO. IPC-E-07-S
12/10/07 HESSING, K (Di) 10
STAFF
1 A. There are many moving parts in a cost of service
2 study. The explanation that I have provided addresses the
3 cost trends for the large customer classes. There are many
4 other factors that are also driving changes in cost of
5 service results such as differences in methodology,
6 allocation factors, distribution and transmission costs,
7 etc.
8 The explanation that I have provided addresses
9 the trend of disproportionate increases to the high load
10 factor classes observed in the IPC-E-05-28 case and the
11 current case.
12 Q.Is there any reason to believe that the trend
13 will not continue?
14 A.No. It is largely driven by the high marginal
15 power supply cost of serving new load. I expect load to
16 continue to grow and marginal costs to remain significantly
17 higher than high load factor customer rates.
18 REVENU ALLOCATION
19 Q.How do you propose the Commission use the Cost of
20 Service results contained in Staff Exhibit No. 117?
21 A.In general, I propose that Cost of Service
22 results be used as a guide in establishing class revenue
23 requirements for the various rate classes. I view Cost of
24 Service results as an imprecise science that is
25 appropriately used as a 'starting point in revenue
CASE NO. IPC-E-07-812/10/07 HESSING, K (Di) 11
STAFF
1 allocation.
2 Q.What customer class allocation of the Idaho
3 Jurisdictional revenue requirement do you recommend?
4 A.Staff's Cost of Service results are based on an
5 average Idaho jurisdictional retail rate increase of 2.82
6 percent. However, some individual class increases vary
7 substantially from the average. For this reason I
8 recommend that cost of service results not be strictly
9 followed, but that the results be used as a guide in
10 establishing class revenue requirements. It is my
11 recommendation that no class receive an increase of more
12 than 10 percent and that all class decreases be set at zero
13 except for the residential class. I propose that the
14 remaining classes be moved 75 percent of the way to cost of
15 service. I then balance the revenue requirement on the
16 residential class and it receives a 1.37 percent increase.
17 Q.Have you prepared an exhibit that shows the
18 results of your proposal?
19 A.Yes. I have prepared Staff Exhibit No. 118. As
20 you can see, Schedule 7 - Small General Service and
21 Schedule 24 - Agricultural Irrigation Service receive the
22 maximum allowable increase of 10 percent. Schedule 9 -
23 Large General Service, Schedule 15 - Dusk to Dawn Lighting,
24 Schedule 40 - Unmetered General Service and Schedule 41 -
25 Street Lighting would receive no increase or decrease. The
CASE NO. IPC-E-07-812/10/07 HESSING, K (Di) 12
STAFF
1 high load factor classes and Schedule 42 - Traffic Control
2 Lighting receive rate increases that move them 75 percent
3 of the way to full cost of service. The Residential class
4 is used to balance the revenue requirement and receives a
5 1.37 percent increase.
6 Q.Have you prepared an exhibit that compares your
7 Revenue Allocation proposal to Idaho Power's Revenue
8 Allocation proposal?
9 A.Yes. Staff Exhibit No. 119 makes that
10 comparison.
11 RATE DESIGN
12 Q.What is your rate design proposal?
13 A.I accept the Company's proposal to keep the rate
14 structures that are currently in place. One possible
15 exception would be voluntary time of use rates for Schedule
16 9 Primary and Transmission service level customers. This
17 option has been discussed among the parties. Staff is not
18 opposed to adding such an option.
19 Due to the Staff's proposal to increase rates on
20 average only 2.82%, I propose no change in the Company's
21 non-energy rates except for Schedule 24 irrigation rates
22 which I will discuss later. If the Commission grants a
23 significantly higher increase than proposed by Staff, then
24 part or all of the requested increase in non-energy rates
25 may be justified.
CASE NO. IPC-E-07-812/10/07 HESSING, K (Di) 13
STAFF
1 For classes where rate increases are recommended,
2 I propose that energy rates be increased to obtain the
3 desired revenue requirement. A uniform percentage energy
4 rate increase may not be appropriate for Schedules 7, 9 and
5 19, Small General Service, Large General Service and Large
6 Power Service , respectively. These are metered general
7 service schedules. They are general service in that
S customers served under these schedules are not required to
9 take service under another schedule based on their
10 electrical end use. Examples of end use schedules are
11 residential, irrigation and various lighting schedules.
12 The customers who take service under Schedules 7, 9 or 19
13 qualify for a specific schedule based on the size of their
14 load. Since these customers can move from one schedule to
15 another as their load increases or decreases, it is
16 important that rates transition smoothly at schedule
17 boundaries.
lS Q.What is your rate design proposal for Schedule 24
19 - Agricultural Irrigation Service?
20 A.Since I am proposing a 10% increase for Schedule
21 24, I propose a uniform percentage increase to all rate
22 components.
23 POWER COST ADJUSTMNT (PCA) MECHAISM
24 Q.What Power Cost Adjustment (PCA) components are
25 established in a general rate case?
CASE NO. IPC-E-07-S12/10/07 HESSING, K (Di) 14
STAFF
1 A.Company Exhibit No. 38 identifies the "PCA
2 Computational Factors" that are established in a general
3 rate case. The Company proposes that the PCA computational
4 factors be updated to the 2007 test year level.
5 Q.Have you prepared a similar exhibit that presents
6 Staff's quantification of appropriate PCA computational
7 factors?
8 A.Yes, I have. Staff Exhibit No. 120 contains the
9 Company's proposal from Company Exhibit No. 38 along with
10 the Staff proposal.
11 Q.Please discuss the numbers presented in your
12 proposal to the extent that they differ from the Company's
13 proposal.
14 A.The Company and Staff proposals for Normalized
15 Power Supply Expense differ because the expense amounts
16 come from the AURORA power supply model and Staff assumed a
17 different natural gas price input to that model than the
18 Company did. This difference is discussed in more detail
19 in Staff witness Rick Sterling's testimony. This
20 difference is also the cause of the difference in the
21 Normalized Base PCA Rate that is calculated using the
22 Normalized Power Supply Expense.
23 The other difference shown in Staff Exhibit No.
24 120 is in the Expense Adjustment Rate for Growth (EARG) ,
25 sometimes called the Load Growth Adjustment Factor. The
CASE NO. IPC-E-07-812/10/07 HESSING, K (Di) 15
STAFF
1 EARG multiplied by load growth between rate cases removes
2 load growth related net power supply costs from PCA
3 consideration. The Company proposes to use 29.16 $/MWh and
4 the Staff proposes to use 62.79 $/MWh. Staff's results are
5 shown on Staff Exhibit No. 121. In general, the reason for
6 the difference is pointed out in Company witness Greg
7 Said's testimony. He proposes to use an incremental cost
8 approach to the calculation instead of the marginal cost
9 approach required by the Commission in its final order in
10 Case No. IPC-E-06-08. In Order No. 30215 at page 14, the
11 Commission said,
12 IT is FURTHER ORDERED and Idaho Power is
directed in its next general rate case and13 in all future rate cases to update the PCA
load growth adjustment factor utilizing14 updated marginal cost analysis studies and
line loss data.
15
16 Q.Did the Company provide a 2007 marginal power
17 supply cost including line losses?
18 A.Yes. Company Exhibit No. 37 shows the EAG to be
19 $67. 74/MWh for 2007.
20 Q.You propose an EARG of 62.79 $/MWh. Why is your
21 number different?.
22 A.The marginal cost calculation is based .on Staff's
23 power supply modeling assumptions that included a different
24 natural gas price.
25 Q.Aside from the fact that the Company's EARG is
CASE NO. IPC-E-07-812/10/07 HESSING, K (Di) 16
STAFF
1 not based on marginal costs, do you have other concerns
2 wi th the proposed method?
3 A.Yes. The method is inaccurate and unstable
4 because it can produce results that vary widely from the
5 29.16 $/MWh that the Company calculated in this case. My
6 concerns stem from the fact that the Company's method
7 includes a change in market price along with load growth.
8 The Company's method takes the difference in net
9 power supply cost calculated at two points in time, 2007
10 and 2008, and divides that by the change in load over the
11 same time increment. The Company then infers that the
12 change in cost is caused by the change in load. If load
13 were the only thing that changed over the time increment,
14 the inference would be correct but the calculated number
15 would be the marginal cost.(62.79 $/MWh as calculated by
16 Staff.) However, the Company method incorporates a second
17 component that also affects net power supply cost. The
18 Company increases market price. The change in power supply
19 cost caused by the change in market price has the ability
20 to dwarf the marginal cost difference of an increment of
21 load growth because market prices apply to all market
22 purchases and sales. AURORA modeled net power supply cost.
23 is quite sensitive to market price.
24 Q.Please provide an example of the Company's
25 incremental cost method that demonstrates its instability?
CASE NO. IPC-E-07-8
12/10/07 HESSING, K (Di) 17
STAFF
1 A.Before I give the example I need to explain that,
2 for Idaho Power Company, higher market prices lead to
3 reduced net power supply cost because Company opportunity
4 sales revenues more than offset market purchased power
5 cost.
6 Assume the scenario upon which the Company based
7 its calculation except that 2008 natural gas prices and,
8 therefore, market prices are up more than the Company
9 proj ected. This could cause reduced power supply costs
10 over a period with positive load growth. Load growth
11 increases cost but the increase in market price can reduce
12 cost a greater amount. The Company's method calculates a
13 negative number. It is not reasonable to infer that load
14 growth causes a reduction in power supply cost. It is not
15 reasonable to apply a negative EARG in the PCA.
16 Q.Could the Company's method produce a number much
17 higher than 29 $/MWh?
18 A.Yes: Again assuming the scenario presented by
19 the Company, except market prices are down in 2008. That
20 means that net Power supply cost is up. The combination of
21 higher power supply cost and increased load growth cost
22 could result in a much higher number than the Company's
23 29.16/MWh.
24 Q.Please summarize your conclusions concerning the
25 Company's proposed incremental cost method of calculating
CASE NO. IPC-E-07-812/10/07 HESSING, K (Di) 18
STAFF
1 the Expense Adjustment Rate for Growth (EARG) used in the
3
2 PCA.
A.The Company's method is inappropriate because the
4 change in load over time is not the only driver causing a
5 change in cost. Changes in market prices can have a large
6 impact on net power supply cost which can cause the Company
7 calculated EARG to be inaccurate and unjustified.
8 Q.Does this conclude your direct testimony in this
9 proceeding?
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Yes, it does.A.
CASE NO. IPC-E-07-812/10/07 HESSING, K (Di) 19
STAFF
Case No. IPC-E-07 -08
Comparison of Historic Jurisdictional Separations Allocators
Classification Allocator Case No.Units Idaho Oregon FERC Total
Demand 010 IPC-E-03-13 kW 2,076,437 100,747 21,220 2,198,404
010 IPC-E-05-28 kW 2,102,069 104,412 16,999 2,223,480
010 IPC-E-Q7-08 kW 2,281,542 111,276 9,533 2,402,351
010 IPC-E-03-13 Allocator 0.945 0.046 0.010 1.000
010 IPC-E-05-28 Allocator 0.945 0.047 0.008 1.000
010 IPC-E-07-08 Allocator 0.950 0.046 0.004 1.000
Energy E10 IPC-E-03-13 kWh 13,275,012 696,678 135,886 14,107,576
E10 IPC-E-05-28 kWh 13,950,521 755,480 113,151 14,819,152
E10 IPC-E-07-08 kWh 14,784,934 764,815 62,949 15,612,698
E10 IPC-E-03-13 Allocator 0.941 0.049 0.010 1.000
E10 IPC-E-05-28 Allocator 0.941 0.051 0.008 1.000
E10 IPC-E-07-08 Allocator 0.947 0.049 0.004 1.000
Customer CW902 IPC-E-03-13 Weighted Customers 4,116,945 237,644 12,457 4,367,046
CW902 IPC-E-05-28 Weighted Customers 4,479,706 237,465 7,260 4,724,431
CW902 IPC-E-07-08 Weighted Customers 4,958,009 290,012 6,756 5,254,777
CW902 IPC-E-03-13 Allocator 0.943 0.054 0.003 1.000
CW902 IPC-E-05-28 Allocator 0.948 0.050 0.002 1.000
CW902 IPC-E-07-08 Allocator 0.944 0.055 0.001 1.000
Exhibit No. 116
Case No. IPC-E-07-8
K. Hessing, Staff
12/10/07
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Comparison of Cost Of Service Results and Revenue Allocation Proposals
Case No. IPC-E-07-08
Company Staff
COS COS
Results Results
Rate 3CP/12CP Base Case
Line Sch.Percent Company Percent Staff
No Tariff Description No.Change Proposal Change Proposal
%%%%
Uniform Tariff Rates:
1 Residential Service 1 1.27 4.53 (4.47)1.37
2 Small General Service 7 15.29 15.00 14.50 10.00
3 Large General Service 9 9.60 13.14 (0.18)0.00
4 Dusk to Dawn Lighting 15 (19,52)3.23 (15.05)0.00
5 Large Power Service 19 17,57 15,00 5,27 3,95
6 Agricultural Irrigation Service 24 36.77 20.00 31,63 10.00
7 Unmetered General Service 40 3.47 .6,81 (0,89)0,00
8 Street Lighting 41 4,97 8,35 (0.65)0,00
9 Traffic Control Lighting 42 16,00 15,00 6,87 5,16
Special Contracts:
10 Micron 26 23.56 20.00 10.41 7,80
11 J R Simplot 29 26.72 20.00 11,52 8.64
12 DOE 30 24.48 20.00 8,60 6,45
13 Total Idaho 10.35 10.35 2.82 2,82
Exhibit No. 119
Case No. IPC-E-07-8
K. Hessing, Staff
12/10/07
PCA Computational Factors
Case No.IPC-E-07-08
Company
Proposal
Staff
Proposal
Units
2007
Test Year
2007
Test Year
Normalized PCA Expense
Normalized Power Supply Expense $40,279,069 34,964,671
Normalized CSPP $93,080,631 93,080,631
Cloud Seeding Expense $892,084 892,084
Cloud Seeding Revenue $(1,427,334)(1,427,334)
Normalized PCA Expense $132,824,450 127,510,052
Normalized Base PCA Rate Cómputation
Normalized System Firm Sales MWh 14,239,221 14,239,221
Normalized Base PCA Rate Ø/kWh 0.93281 0.89548
Idaho Jurisdictional Percentage Computation
Normalized System Firm Load MWh 15,612,699 15,612,699
Idaho Jurisdictional Firm Load MWh 14,784,934 14,784,934
Idaho Jurisdictional Percentage %94,7%94.7%
Expense Adjustment Rate for Growth $/MWh 29.16 62.79
Exhibit No. 120
Case No. IPC-E-07-8
K. Hessing, Staff
12/10/07
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o-.i00
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