HomeMy WebLinkAbout20080104Hessing rebuttal.pdfBEFORE THE
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IDAHO PUBLIC UTILITIES COMMliSSINUBLlC
UTiLITIES COMMISSIC¡i
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-07-8
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE )
IN THE STATE OF IDAHO. )
)
)
)
)
REBUTTAL TESTIMONY OF KEITH HESSING
IDAHO PUBLIC UTILITIES COMMISSION
JANUARY 4,2008
1
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2 the record.
Q.Please state your name and business address for
A.My name is Keith D. Hessing and my business
4 address is 472 W. Washington Street, Boise, Idaho.
5
6
By whom are you employed and in what capacity?Q.
A.I am employed by the Idaho Public Utili ties
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7 Commission as a Public Utilities Engineer.
Q.Are you the same Keith Hessing that previously
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9 submitted testimony in this proceeding?
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A.Yes, I am.
Q.What is the purpose of your rebuttal testimony?
A.I will address portions of the testimonies of Dr.
13 Dennis Peseau, Dr. Don Reading, Dr. Dennis Goins and Mr.
14 Anthony Yankel.
16
15 Cost of Service Matrix
Q.Have you prepared a matrix that shows differences
17 in Cost of Service (COS) assumptions proposed by the
18 various parties to assist in the discussion of the major
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19 COS issues in this case?
A.Yes. Staff Exhibit No. 123 consists of two pages
21 and compares the COS methods proposed in this case and the
22 COS method used as a revenue allocation guide by the
23 Commission in Case No. IPC-E- 03 - 13. The matrix compares
24 the proposed methods in three areas: methodology,
25 classification of costs as demand or energy related and the
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 1
STAFF
1 composition of allocation factors.
2 High load factor (LF) customers proposed three
3 main COS modifications that benefit them in this case.
4 They are i the classification of costs as demand related
5 rather than energy related, the elimination of the
6 averaging of weighted and unweighted allocators in favor of
7 weighted allocation factors, and a reduction in the number
8 of coincident peaks used in determining allocation factors.
9 The lower load factor irrigation class proposed a
10 modification that benefited them. Mr. Yankel proposed that
11 one of the two averaged allocation factors be weighted by
12 expected load growth over a 10 -year period. Irrigation
13 load growth has been and is expected to continue to be
14 quite small. This weighting greatly reduces COS for the
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15 irrigation class.
17
Q.Please illustrate the use of the matrix.
A.To illustrate the use of the matrix I will
18 briefly discuss the COS method used by the Commission in
19 Case No. IPC-E-03-13. It is the first method summarized on
20 page 1 of Staff Exhibit No. 123. It is the same general
21 method as the Base Case method presented by the Company in
22 this filing. Hydro and coal production plant were
23 classified as demand and energy related based on the Idaho
24 jurisdictional Load Factor (LF). Natural gas fired peaking
25 plant investment was classified as 100% demand related.
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 2
STAFF
1 Non-PURPA purchased power costs were classified as 100%
2 energy related and PURPA purchased power costs were
3 classified as energy related except for a small percentage.
4 Six percent of the costs were classified as demand related
5 based on contractual capacity payments made to a few
6 generators. Opportunity sales revenues were classified as
7 100% energy related.
8 The DI0 allocator applies to most demand related
9 costs. It is the average of the weighted and unweighted
10 allocator calculations. The unweighted allocation factor
11 was based on 12 monthly coincident peaks. The weighted
12 allocation factor was based on the five highest coincident
13 peaks weighted by the monthly marginal cost of capacity.
14 The D13 allocator applies to transmission costs.
15 It is the average of weighted and unweighted allocator
16 calculations. The unweighted allocator was based on 12
17 monthly coincident peaks. The weighted allocator was based
18 on the three highest coincident peaks weighted by the
19 monthly marginal cost of transmission.
20 The EI0 allocator is applied to energy related
21 costs. It is based on the monthly weighted energy use by
22 class in the test year. The weighting factors are the
23 monthly marginal costs of energy. The weighted factor was
24 not averaged with the unweighted factor in the IPC-E-03-13
25 case.
CAS E NO. I PC - E - 07- 8
01/04/08
HESSING, K (Reb.) 3
STAFF
1 The matrix shows the COS methods employed by the
2 various parties in a similar format.
4
3 Making Sense of Cost of Service Results
Please address the maj or concerns that you haveQ.
5 with Dr. Peseau's and Dr. Reading's testimonies.
6 A.Their major theme is that COS results do not make
7 sense and, therefore, the methodology must be changed. Dr.
8 Peseau concludes that all four of the Company's filed COS
9 studies are methodologically flawed and that the results
10 are counterintuitive. He then proposes very substantial
11 changes to the Base Case COS method. I do not agree that
12 the Base Case method should be changed. Unnecessary
13 changes in methodology shift costs unnecessarily. Base
14 Case study results make sense and are explainable. I offer
15 the following hypothetical example in explanation. I have
16 prepared a residential load growth scenario using the
17 Company's Base Case COS model. I started with the
18 Company's Base Case COS results, grew the residential load
19 and tracked the changes in COS results in a three step
21
20 process. The example examines changes in COS results
(1) power supply costs, (2) demandcaused by changes in:
23
22 and energy allocators and (3) retail revenue.
Please provide your assumptions.
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25
Q.
A.I assumed the following:
1 )A 250,000 MWh growth in annual residential
CASE NO. IPC-E-07-801/04/08
HESSING, K (Reb.) 4
STAFF
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24 Q.
load.(Generation Level)
2 )That power supply costs to serve the load
are incurred at 62.79 $/MWh.
Therefore, the cost of power supply is
$15,697,500 (250,000 x 62.79).
3 )That the costs were Purchased Power costs
booked in Account 555.1. All Account 555.1
costs are classified as 100% energy related.
4 )That Base Case residential monthly energy
and demand amounts grew in proportion to
normalized amounts. This allowed the
calculation of new allocation factors for
all classes (EI0, DI0, and D13) .
5)That residential sales were 89.1% of the
generation level growth in load due to 10.9%
delivery system losses. Residential sales
are 222, 750 MWh ( 2 5 0 , 000 x . 8 91) .
6 )That the increased retail revenue associated
with residential sales occurred at 59.24
$/MWh, which is current average residential
revenue per MWh. This produces increased
residential revenue associated with load
growth of $13,195,710 (59.24 x 222,750) .
25 of your analysis?
Have you prepared an exhibi t showing the results
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 5
STAFF
1 A.Yes. Staff Exhibit No. 124 is a three page
2 exhibi t that shows COS results from the three step process
3 I employed.
4 Q.Please discuss the results shown on page 1 of
5 Staff Exhibit No. 124.
6 A.Page 1 shows COS results associated with adding
7 $15,697,500 of energy related costs to Account 555.1.
8 (Assumptions 1 through 3 above) Column G shows that the
9 amount, $15,697,500, tracked through properly as operating
10 expense. Column J shows that the overall increase in
11 revenue requirement tracked through correctly because it is
12 the operating expense grossed up, $25,775,295 (15,697,500 x
13 1.642). Column L shows that the high load factor customer
14 classes (DOE, Simplot, Micron and Schedule 19) were
15 allocated the lowest ç/kWh increases which were also the
16 highest percentage increases as shown in Column K. This is
17 the phenomenon discussed in my direct testimony, that
18 relatively small ç/kWh increases will produce relatively
19 large percentage increases when the initial rate is
20 relatively small. At this step COS results reflect only an
21 expense increase and do not yet tie that expense increase
22 to residential load growth.
23 I would observe that this result is similar to a
24 result that might be produced by increased unit costs of
25 natural gas or coal used to fuel generators or an increase
CASE NO. IPC-E-07-801/04/08
HESSING, K (Reb.) 6
STAFF
1 in the unit cost of purchased power without accompanying
2 growth in load.
3 Q.What does page 2 of Staff Exhibit No. 124 show?
4 A.Page 2 shows COS results that capture the effects
5 of assumptions 1 through 5. Page 2 again shows the
6 operating expense increase shown on page 1 but ties that
7 expense to residential load growth. It does this by
8 incorporating changes in energy and demand allocators. The
9 allocation factors for every class, except the residential
10 class, went down and residential class factors went up.
11 The allocation factor changes are not shown on page 2 but
12 their effects are. For example, when page 2 is compared to
13 page 1, Column G still totals to $15,697,500 with all
14 classes receiving a decreased allocation except the
15 residential class. The allocator changes also
16 redistributed some rate base amounts and other revenue
17 amounts with the same pattern. The overall increase shown
18 in Column J remains the same but the class amounts are
19 redistributed with the residential amount being the only
20 one that increased. It is not surprising that Column K
21 shows the largest percentage increase to be the residential
22 class increase. Column K also shows high LF class
23 increases to be approximately half the residential class
24 increase. This appears to me to be the type of results
25 that Dr. Peseau and Dr. Reading were expecting but did not
CASE NO. IPC-E-07-801/04/08
HESSING, K (Reb.) 7
STAFF
1 see. The ç/kWh amounts shown in Column L include the
2 additional retail energy sales associated with the growth
3 in residential load which is shown in Column D.
4 Q.What does page 3 of Staff Exhibit No. 124 show?
5 A.Page 3 shows the difference in COS results caused
6 by incorporating all six of my residential load growth
7 assumptions. The difference between page 2 and page 3 is
8 that page 3 credits the residential class with the revenue
9 created by the growth in load. Column E shows that
10 revenue. Columns F, G and H do not change. The class
11 revenue requirement allocations in Column J do not change
12 except for the residential class. The residential revenue
13 requirement increase is offset dollar for dollar with the
14 increase in load growth revenue. The residential class
15 goes from deserving the largest increase to deserving a
16 decrease while all other class results remain unchanged.
17 Q.How do the results of the hypothetical situation
18 that you just discussed relate to the COS results in the
19 current rate case?
20 A.The analysis of the hypothetical situation
21 explains in adequate detail the effect that residential
22 growth and high power supply cost has on all customer
23 classes. There is certainly more going on in the COS
24 studies presented by the Company in this case than growth
25 in the power supply costs of one customer class, but the
CASE NO. IPC-E- 07-8
01/04/08
HESSING, K (Reb.) 8
STAFF
1 COS results in the hypothetical case go a long way in
2 showing that the COS results filed by the Company in the
3 current case are not counterintui ti ve.
4 Q.In your previous example the cost increase was
5 energy related. Did you prepare a hypothetical example to
6 demonstrate the effects of demand related cost increases on
7 COS results?
8 A.Yes. I again started with the Company's Base
9 Case method and results. I added $100,000,000 in gas fired
10 peaking investment to Accounts 340 - 346. Accounts 340 -
11 346 are classified as 100% demand related. Staff Exhibit
12 No. 125 shows the COS impact of the plant addition.
13 Q.Please explain Staff Exhibit No. 125.
14 A.The format is the same as used in the previous
15 hypothetical example. Column H shows that the $100,000,000
16 rate base addition flowed through the model and also shows
17 how the cost was allocated to the various customer classes.
18 Column J shows that the $100,000,000 investment produced
19 approximately $14,000,000 in increased revenue requirement.
20 Columns Land K once again show that high load factor
21 customers receive smaller ç/kWh increases than residential
22 customers but a larger percentage increase. This occurs
23 for the same reasons here as those discussed in the
24 previous hypothetical example.
25 Q.Why does it matter to high LF customers whether
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 9
STAFF
2
1 costs are energy related or demand related?
A.Because a lower percentage of costs are allocated
3 to high LF customers when costs are considered to be demand
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4 related as opposed to energy related.
Q.Please provide the conclusions you reach from the
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6 hypothetical examples you have discussed.
A.High LF customer percentage increases higher than
8 the average are due to increased production costs relative
9 to existing rates and the lack of significant offsetting
10 revenue. The COS resul ts obtained from the Base Case COS
11 method are correctly calculated, make sense and are
12 reasonable and should be used by the Commission as the
13 starting point in revenue allocation to the various
14 customer classes in this case.
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15 Dr. Peseau's Cost of Service Study
Q.Dr. Peseau filed COS results on behalf of Micron.
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17 Please discuss his cost of service study.
A.Dr. Peseau discarded all four of the COS
19 methodologies presented by the Company and presented his
20 own COS method (see Staff Exhibit No. 123). His COS method
21 is a substantial modification of the Company's Base Case
22 method. He ended up with what I would call a weighted 3CP
23 method. He removed the averaging of the weighted and
24 unweighted demand and energy allocators (EI0, DI0, DI3).
25 He also weighted 9 months as zero in determining demand
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 10
STAFF
1 allocators. His marginal cost weighted demand allocation
2 factors were entirely developed using June, July and August
3 data. These demand allocators, based entirely on data for
4 the three summer months, were used to allocate all demand
5 related production costs and all transmission costs, since
6 all transmission is classified as demand related. The
7 results are predictable. The irrigators' rates are 94%
8 below full cos while other customer class rates are above
9 or near full COS. His revenue allocation proposal is that
10 the irrigation class receive twice the average increase and
11 that the remaining increase be spread to all other customer
12 classes on a uniform percentage basis. This means that all
13 customer classes, except the irrigators , receive an
14 increase below the average increase.
15 Q.Please discuss the effects of and the reasons for
16 averaging weighted and unweighted allocators.
17 A.Averaging of weighted and unweighted allocators
18 is a compromise. Marginal cost weighting factors are the
19 greatest in the summer time. The application of marginal
20 cost weighted allocation factors substantially impact the
21 irrigation class. The application of an averaged allocator
22 softens the impact on the irrigation class. It removes
23 part of the revenue requirement that would otherwise be
24 assigned to the class and spreads it over other classes.
25 Every party that has filed COS results and a revenue spread
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 11
STAFF
1 recommendation in this case has done something similar.
2 They have proposed that the irrigation increase be capped
3 and that the unrecovered amount be spread to all other
4 classes.
5 Another benefit of averaging weighted and
6 unweighted allocators is that allocations reflect a value
7 related to each class's usage characteristics for every
8 month. I believe that capacity and energy have value in
9 every month. As previously discussed, Dr. Peseau' s COS
10 method weights capacity costs as zero in nine months of the
11 year and, therefore, employs demand allocators based on
12 only three months of class characteristics. The Base Case
13 method recommended by Staff weights six months as zero in
14 the development of demand related allocators but then
15 averages those zero months with an unweighted allocator
16 calculated using coincident peak values for every month.
17 Thus, the averaged demand allocator reflects a value based
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18 on class characteristics for all months.
Q.Is it wrong to use allocators in COS studies that
21
20 do not reflect the full impact of marginal cost weighting?
A.No. The choice to use weighted or unweighted COS
22 allocators or something in between is a judgement call that
23 is influenced by ones choice of policy obj ecti ves. Dr.
24 Peseau would have us believe that unweighted 12CP demand
25 allocators have fallen out of favor and are no longer in
CASE NO. IPC-E-07-801/04/08
HESSING, K (Reb.)12
STAFF
1 use. That is not true in Idaho. Both Rocky Mountain Power
2 and Avista use unweighted 12 CP demand allocators as the
3 primary demand allocators in their COS studies.
4 Classification of Power Supply Costs
5 Q.Staff Exhibit No. 123 indicates that three
6 parties in this case have proposed that one or both of the
7 sub-accounts under Account 555 purchased power be
8 classified as something other than 100 percent and 97%
9 energy related. What treatment do you propose for the
10 classification of these costs?
11 A. Account 555.2 contains the cost of PURPA
12 purchases. I agree that PURPA purchases have some capacity
13 value. I also believe that other short and long-term
14 purchases are made to meet the capacity and energy needs of
15 the system. These costs are contained in Account 555.1. A
16 portion of these costs should be classified as demand
17 related as well. I further believe that Account 447
18 opportunity sales revenue consists of not only revenue from
19 self -generation in a favorably priced market but also
20 revenue from the sale of unused power purchased in advance
21 to hedge against a variety of conditions under the
22 Company's Risk Management Plan. Some of this resold power
23 was purchased for capacity reasons. Revenues from the sale
24 of power purchased for capacity reasons should be credited
25 back to customer classes on the same capacity basis that
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 13
STAFF
1 was used to classify the initial purchase cost.
2 I believe these three accounts all have energy
3 and capacity components and should be classified in like
4 manner. I recommend all three be classified using the
5 Idaho jurisdictional load factor in similar fashion to
hydro and thermal production plant.The LF split
classifies approximately 42%of the costs as demand related
and approximate 1 y 58%of the costs as energy related.I
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9 recommend this as a package deal. All three of these cost
10 categories are power supply costs and the costs are
11 interrelated.
12 Seasonal Shapes included in Allocation Factors
13 Q.On pages 42 and 43 of his direct testimony Dr.
14 Peseau includes two charts that show the effects of
15 marginal cost weighting. Please comment on the charts.
16 A.My only comment on the two charts relates to the
17 horizontal line that is called "non-weighted". My concern
18 is that I would not want anyone to view either of the
19 charts and conclude that allocation factors include no
20 shape except that provided by marginal cost weighting. All
21 of the energy and demand allocation factors proposed for
22 use in this case capture the monthly shape of every
23 individual classes energy and coincident peak demand. The
24 only time this is not true is if the monthly weight is set
25 at zero and the weighted and unweighted allocators are not
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 14
STAFF
1 averaged. Data reflecting the shapes of the allocation
2 factors, weighted and unweighted, for the classes are shown
3 for the Base Case method on Company Exhibit No. 47. The
4 shape of irrigation class energy and coincident peak demand
5 is striking and shows why the irrigation class is allocated
6 significant costs for use during the summer peak period.
7 The Department of Energy's Cost of Service Proposal
8 Q.Please discuss the Department of Energy's Cost of
9 Service proposal presented by Dr. Goins.
10 A.Dr. Goins employs the Company's 3CP/12CP
11 methodology but recommends different energy/demand
12 classifications for major costs. He initially recommends
13 that all production plant investment be classified as 100%
14 energy related. To my knowledge this has never been done
15 in Idaho. Coal and hydro plants cost more per kW to build
16 than gas fired peaking units. The additional investment is
17 made with the knowledge that energy can be produced at a
18 lower cost from these plants when they are operated at a
19 high capacity factor. Since the additional investment is
20 incurred to reduce energy costs it is logical to allocate
21 the investment as energy related.
22 Dr. Goins' fall back position, should his primary
23 position be rejected, is that hydro investment should be
24 considered to be 60% demand related and 40% energy related,
25 that coal plant be classified to energy and demand based on
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 15
STAFF
1 the Idaho Jurisdictional LF and that peaking plant
2 investment be considered to be 100% demand related. His
3 classification of hydro plant differs significantly from
4 that previously used by the Commission.
5 He also proposes a 50/50 classification of all
6 Account 555 purchased power costs. This classification is
7 arbitrary because it is established with little or no
8 supporting justification.
9 The Irrigators Cost of Service Proposal
10 Q.Please discuss the irrigators COS proposal
11 presented by Mr. Yankel.
12 A. The irrigators present a very interesting
13 proposal. Mr. Yankel' s proposal is intended to overcome a
14 cost of growth inequity that he identifies. According to
15 Mr. Yankel the inequity occurs when the irrigation class is
16 allocated some of the costs of growth when the class is not
17 growing. My residential growth hypothetical example
18 discussed previously in this testimony shows that he is
19 correct in that growth related costs are allocated to the
20 irrigators and to all other customer classes.
21 Q.Should the irrigators be protected from the costs
22 of growth in other classes?
23 A.Irrigators and all other existing customers are
24 already protected from some of the costs of growth because
25 contributions are required under the Company's distribution
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 16
STAFF
1 line extension policy that cover a portion of the costs of
2 growth. Costs offset by contributions do not increase
3 rates.
4 However, the COS analysis filed in this case
5 address costs of growth not offset by contributions. All
6 such costs are part of the costs included in the uniform
7 system of accounts and allocated to all customer classes
8 based on class usage characteristics. Most of the existing
9 individual customers in the non-irrigation classes are no
10 more responsible for growth related cost than the
11 irrigators, yet, none are protected from the costs of
12 growth. This is because rates have historically been
13 averaged to include the cost to serve new customers and the
14 cost to serve older existing customers. Existing
15 irrigators whose loads have not grown have no more right to
16 be protected from growth related costs than do residential
17 or other existing individual customers whose loads have
18 also not grown. In my view a COS methodology that singles
19 out a specific class of customers for rate protection is
20 inequitable and may be contrary to court rulings. Mr.
21 Yankel' s proposed allocation methodology only protects
22 those existing customers taking service within a class that
23 has little or no load growth. For all practical purposes
24 the irrigators are proposing that existing customers be
25 required to pay for all growth related cost caused by new
CASE NO. IPC-E-07-801/04/08 HESSING, K (Reb.) 17
STAFF
1 customers wi thin their classes.
2 It is my opinion that if adequate contributions
3 cannot be collected from new customers, a portion of load
4 growth costs must be passed to all customer classes to
5 assure equity. I do not know whether current law will
6 allow a regulated utility to collect more growth related
7 costs from new customers through up- front fees or to charge
8 different rates based on date of service.
9 I oppose the use of the COS method proposed by
10 the irrigators based on the equity and legal concerns
11 discussed above.
12 Summary
13 Q.Please summarize your testimony.
14 A.In general I believe that the COS proposals
15 presented by the high LF customers in this case serve their
16 individual interests and do not improve COS results.
i 7 I continue to recommend the use of the Base Case
18 COS method proposed in my direct testimony with the
19 following exception. As discussed in this testimony, I am
20 willing to accept the classification of all purchased power
21 costs and opportunity sales revenues by the Idaho
22 jurisdictional LF, but only if all three accounts or sub
23 accounts are classified this way.
24 Load growth costs not offset by customer
25 contributions are impacting all customer classes. Equity
CASE NO. IPC-E-07-801/04/08
HESSING, K (Reb.) 18
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1 requires these costs be spread to all classes.
2 Q.Does this conclude your rebuttal testimony in
4
3 this proceeding?
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A.Yes, it does.
CASE NO. IPC-E-07-801/04/08
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o-.i00
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 4TH DAY OF JANUARY 2008,
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