20081203Hessing Rebuttal.pdf

BEFORE THE RECEiVED
2D08 DEC - 3 AM 9: 34
IDAHO PUBLIC UTILITIES COMMISSION IDAHO PU8UC
UTILITiES COMr,HSSION
. 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. )
)
)
)
REBUTTAL TESTIMONY OF KEITH HESSING
IDAHO PUBLIC UTILITIES COMMISSION
DECEMBER 3, 2008
1
3
2 the record.
Q.Please state your name and business address for
A.My name is Keith D. Hessing and my business
5
4 address is 472 W. Washington Street, Boise, Idaho.
6
Q.By whom are you employed and in what capacity?
A.I am employed by the Idaho Public Utili ties
S
7 Commission as a Public Utili ties Engineer.
Q.Are you the same Keith Hessing that previously
10
9 submitted testimony in this proceeding?
11
12
A.Yes, I am.
Q.What is the purpose of your rebuttal testimony?
A.I will address portions of the testimonies of
13 Mr. Anthony Yankel, Dr. Dennis Peseau, Dr. Don Reading, and
14 Dr. Dennis Goins.
16
15 Load Growth
Q.Mr. Yankel discusses load growth and its cost of
17 service impacts on the irrigation class in his direct
1S testimony. Please present your views concerning load growth
20
19 and class cost of service studies.
A.The cost of providing service to new customers is
21 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 into
24 the Company's accounting records, those costs are mixed with
25 other plant costs accumulated over many years that are in
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) 1
STAFF
1 various stages of depreciation. Some of the costs are
2 growth related and others are associated with replacements
3 or relocations. Once current load growth costs are mixed
4 with all of the other costs in the Company's accounting
5 system, it is not possible to apply any class characteristic
6 that accurately or even approximately separates growth
7 related costs, for a given time period, from the other costs
S in that account. All costs in the accounts are blended or
9 averaged. Rates based on such an attempt to separate growth
10 related costs from other costs are probably grossly
11 inaccurate and cannot be considered fair or reasonable.
12 Q.Does the Company continue to incur costs to serve
13 the irrigation class even though its load may not be
14 growing?
15 A.Absolutely. Poles, wires, transformers and
16 generation equipment will fail or become obsolete and
17 require replacement. These costs will be incurred at
1S current levels and be booked to the same accounts that all
19 other like costs have been booked to over time. These costs
20 are higher than those recovered through current rates but
21 such investments are required to continue to provide
22 adequate service to existing customers. To the extent that
23 a customer class, such as the irrigators with no growing
24 load, do not pay these costs other customers will.
25
CASE NO. IPC-E-OS-1012/03/0S 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 10-year
4 class load growth projection from Idaho Power's Integrated
5 Resource Plan (IRP) to weight demand and energy allocators.
6 Q.Is this an appropriate methodology to allocate
7 embedded costs?
S A.Not in my opinion. No embedded cost of service
9 study included in the NARUC Electric Utility Cost Allocation
10 Manual allocates growth costs based on the future growth of
11 customer classes. When challenged to find such a method in
12 the cost of service workshops held in Case No. IPC-E-04-23,
13 the Company's search discovered no such methodology.
14 Nei ther did any other party.
15 When growth occurs in any customer class one or
16 more of the allocation factors based on energy use,
17 contribution to system peak or number of customers increase
1S in value and thus cause the allocation of more costs to that
19 class. In other words all costs are averaged and allocated
20 based on class usage characteristics. Cost allocations
21 increase disproportionately for growing classes but do not
22 approximate the growth related costs incurred by the class.
23 All of the cost of service studies submitted in this case
24 allocate costs in this way. This is the extent, under
25 existing embedded cost of service methodologies, to which
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) 3
STAFF
1 growth related costs can be allocated to the cost causer.
2 Q.You have stated that it is your opinion that the
3 high cost of load growth cannot be accurately allocated to
4 the class in which the load growth occurred once the costs
5 are booked to the Company's accounts. Can load growth costs
6 be assessed before the costs are booked to the Company's
7 accounts?
S A.Yes, to a limited degree. New connections can be
9 required to make a contribution to offset the Company's
10 costs prior to connection. This is currently being done
11 through the Company's Line Extension Rule. Generally, the
12 contribution only offsets a portion of distribution
13 investment. In some special circumstances a portion of the
14 cost of transmission is contributed. No Generation costs
15 are contributed. Past efforts by the Commission to impose
16 growth related fees on new customers to recover generation
17 or production costs have been rej ected by the Idaho Supreme
1S Court. The courts have restricted the manner in which
19 common costs can be collected from customers based on a new
20 customer, old customer distinction. How much, if any, of
21 the growth related common costs can be recovered from new
22 customers and whether they can be recovered through up front
23 contributions or monthly electric rates is unclear.
24 However, it is clear to me that it is just as inequitable to
25 specifically allocate growth related costs to existing
CASE NO. IPC-E-OS-10
12/03/0S HESSING, K (Reb) 4
STAFF
1 customers in a customer class with growing load as it is to
2 assess those costs to existing customers in a class where
3 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.
S Q.Is it fair to protect irrigation customers from
9 what I will call the spill-over costs of load growth while
10 other non-growing customers in other classes are required to
11 pay them?
12 A.No.
13 Load Factor Classification
14 Q.Would you summarize the variety of different ways
15 the parties in this case have proposed to classify base load
16 hydro and thermal production plant to demand and energy?
17 A.Yes. The Company and Commission Staff recommend
1S that hydro and thermal plant costs be split and classified
19 as energy and demand related based on the Idaho
20 Jurisdictional load factor. In this case the load factor is
21 59. 3S%. The proposed methodology would classify
22 approximately 59% of these plant costs as energy related and
23 approximately 41% as demand related.
24 Dr. Peseau recommends that all hydro and thermal
25 production plant be classified as demand related.
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) 5
STAFF
1 Dr. Reading agrees with the Company and Staff that
2 the load factor split should be employed to classify thermal
3 production plant but he proposes a 75% demand/25% energy
4 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 factor
S split in his weighted 12CP method.
9 After stating his preference that all production
10 plant be classified as demand related, Dr. Goins proposes
11 two weighted 12CP studies for Commission consideration. His
12 Exhibit No. 610 study splits thermal and hydro production
13 plant by the load factor as the Company proposed and his
14 Exhibit No. 611 study proposes that hydro and thermal
15 production plant be classified as 42.9% energy related and
16 57.1% demand related.
17 Q.Why does the Staff support the Company in its use
lS of the load factor classification of hydro and thermal
19 production plant?
20 A.First of all it is the method last accepted by the
21 Commission in the IPC-E-03-13 case. In addition to that,
22 the method is self adjusting to address changes in system
23 generation requirements.
24 Q.Please explain how the load factor classification
25 method is self adjusting?
CASE NO. IPC-E-OS-10
12/03/0S HESSING, K (Reb) 6
STAFF
1 A.The load factor is a descriptive characteristic of
2 the system. It is average demand, or energy, divided by
3 peak demand. It is the specific relationship between energy
4 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
S either on their own or as they are encouraged to do through
9 programs designed to encourage changes such as the Peak
10 Rewards program for irrigators or the Cool Credits program
11 for residential customers. As the relationship between
12 peak and energy changes so does the system load factor.
13 Dr. Peseau points out in his testimony that in Idaho Power's
14 1994 general rate case (IPC-E-94-5) the load factor was
15 almost 6S%. In that case approximately 6S% of production
16 plant costs were classified as energy related and
17 approximately 32% were classified as demand related. In
lS this case the load factor is approximately 59%. Therefore,
19 hydro and thermal production costs are being classified as
20 approximately 59% energy and 41% demand. Higher demand
21 percentages benefit high load factor customers. The load
22 factor changed as system characteristics changed and energy
23 and demand classifications were automatically adjusted.
24 Q.What would be the result of applying the load
25 factor classification methodology to a hypothetical system
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) 7
STAFF
2
1 with a 100% annual load factor?
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
S factor classification methodology to a hypothetical system
10
9 with a near 0% annual load factor?
A.The load factor classification method would
11 classify nearly 100% of production plant as demand related.
12 A system with a very low load factor would exhibit one or
13 more sharp short duration peak demands over the course of
14 the year and produce very small amounts of energy.
15 Economics would dictate that the plant that served such a
16 system would be a peaking plant (or plants) constructed to
17 provide low cost capacity or demand.
lS The load factor classification method is self
20
19 adjusting and properly classifies costs, even at the limits.
Q.What is Dr. Peseau's position in this case
22
21 concerning growth and the Company's load factor?
A.In this case it is Dr. Peseau's position that
23 incorrect price signals are being sent to growing classes
24 and that this is causing a "steady decline in Idaho Power's
25 load factor" (pg. 41). He implies that this justifies an
CASE NO. IPC-E-OS-10
12/03/0S HESSING, K (Reb) S
STAFF
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 this
5 case of 59%.
6 Q.Do you agree with his position?
7 A.No. He is correct that the 1994 load factor was
8 approximately 68% and that it is currently approximately
9 59%. However, the load factor change has nothing to do with
10 load growth and everything to do with the loss of load. In
11 2001 the system lost the load of its single largest
12 customer, FMC Corporation. FMC was also a high load factor
13 customer. When FMC's load was lost the Company's load
14 factor declined. This is evidenced by the Company's load
15 factor in its 2003 general rate case which was 55.26%.
16 Since that point in time the Company's load factor has
17 continued to improve to its current level of 59.38% as shown
18 in the table below.
19 Case No.Load Factor
20 IPC-E-94-5 67.57%
21 IPC-E- 03 - 13 55.26%
22 IPC-E- 05 -28 58.45%
23 IPC-E-07-8 58.53%
24 IPC-E- 08 - 10 59.38%
25
CASE NO. IPC-E-08-1012/03/08 HESSING, K (Reb) 9
STAFF
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 basis.
4 Q.Dr. Reading proposes that hydro production plant
5 be classified as 75% demand/25% energy at least partially
6 because that is the accepted classification in Rocky
7 Mountain Power's cost of service methodology. Do you
S believe that the Commission should accept his
9 recommendation?
10 A.No. This classification mirrors the
11 jurisdictional separations methodology agreed to by parties
12 in PacifiCorp's multi-state process (MSP). The negotiated
13 settlement in the MSP was not solely based on cost of
14 service principles.
15 Idaho's other major electric utility, Avista,
16 employs a classification methodology that has been accepted
17 by the Commission for at least 25 years that is on the
lS opposite end of the spectrum from Rocky Mountain Power.
19 Avista uses an "Equivalent Peaker Method" as identified in
20 the NARUC Electric Utility Cost Allocation Manual (pg. 52).
21 Avista calls its methodology the Peak Credit method. The
22 Peak Credit method assumes that if a utility needs capacity
23 to meet demand, it builds a simple cycle combustion turbine.
24 To the extent that it pays more to build or buy anything
25 other than a combustion turbine, it incurs those costs to
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) 10
STAFF
1 supply energy. The Company uses a ratio of the two costs to
2 classify base load plant to capacity and energy. In its
3 most recent filing, Case No. AVU-E-OS-1, Avista's method
4 classified 73. lS% of hydro plant as energy related and
5 66.43% of thermal plant as energy related. Of course the
6 remaining percentages of both were classified as demand
7 related. The load factor classification of demand and
S energy as proposed by the Company and Staff in this case is
9 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 demands
17 that are used in developing class cost of service allocation
lS factors has unintended consequences.
19 Following Idaho Power's IPC-E-03-13 general rate
20 case the Commission required the parties to hold workshops
21 to discuss cost of service issues. A case was opened, the
22 IPC-E-04-23 case, and a report with recommendations was
23 filed with the Commission. One of the recommendations
24 accepted by the parties was designed to weather normalize
25 coincident peaks instead of using actual coincident peaks
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) 11
STAFF
1 from the test year. The normalization technique was to use
2 the median value from 5 years of monthly data for each month
3 for each class. The logic was that if weather caused higher
4 than normal or lower than normal coincident peaks over a 5-
5 year period, the middle value would be the most normal. My
6 recollection of those workshops is that there was no
7 discussion of other non-weather related factors that might
S cause systematic changes in coincident peaks. Such
9 systematic changes would build (or decline) over a 5-year
10 period and, in a normal weather situation, would result in a
11 3 -year-old median being selected. Systematic changes can
12 increase or decrease class coincident peaks. On demand
13 electric hot water appliances could work to increase demands
14 while the irrigation peak rewards program and the
15 residential cool credits program work to reduce class peaks.
16 Q.Does the Company's filing recognize this problem?
17 A.Yes, to some extent. The Company proposes
lS adjustments to irrigation peaks to include peak reductions
19 due to the peak rewards program for which the irrigation
20 class was not getting full credit.
21 Q.What methodology do you propose to be used in the
22 place of the 5 -year median methodology?
23 A.I accept Dr. Reading's proposal to return to the
24 use of coincident peak data based on the single most recent
25 year.
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) 12
STAFF
1 Q.Did you rerun the Staff cost of service
3
2 recommendation using the proposed methodology?
4
A.Yes. Those results are shown on Exhibit No. 151.
Q.Does this change the revenue allocation proposal
6
5 that you made in your direct testimony?
A.Yes, it changes my original proposal. My new
7 proposal is shown on Exhibit No. 152. Under my new proposal
8 the floor remains at no decrease, Schedule 9 moves to full
9 cost of service with a 1.75% increase and all other classes
10 who would receive increases have their increases capped at
12
11 3.89%.
Q.Have you prepared an exhibit that shows the
13 Company's proposal, your original proposal and your proposal
14 on rebuttal?
15 A.Yes. Exhibit No. 153 shows those results.
17
16 12CP Methodology
Q.In his testimony on page 43, Dr. Peseau discusses
18 concerns he has with the Company's 3CP/12CP methodology. He
19 says that classifying steam production plant as energy and
20 demand related and then applying a 12CP demand allocator to
21 the demand portion is a "double allocation of baseload steam
22 production to energy". He says that a 12CP demand allocator
23 is essentially an energy allocator. Please respond.
24 A.A 12CP demand allocator is composed of a
25 utility's 12 monthly coincident peak demands. It is
CASE NO. IPC-E-08-10
12/03/08 HESSING, K (Reb) 13
STAFF
1 commonly used to allocate demand related production costs
2 even when a portion of those costs are classified as energy
3 related. This is exactly the case with Avista and Rocky
4 Mountain Power here in Idaho. The classification/
5 allocation method applied to steam production plant by the
6 Company in this case is not a double allocation to energy
S
7 and in fact is common practice.
Q.Why should base load capacity related costs be
10
9 allocated using a 12CP allocator in this case?
A.Capacity is required and has value in all months.
11 Idaho Power is a dual peaking utility with a summer and
12 winter peak. The off peak, spring and fall shoulder months,
13 provide the opportunity for the Company to take plants down
14 for necessary scheduled maintenance. This circumstance can
15 produce situations in shoulder months where available
16 capacity is as important as it is in peak load months.
17 Q.Has the Idaho Commission ever accepted a Cost of
lS Service study in an Idaho Power rate case that did not
19 include some measure of coincident peaks in all 12 months of
21
20 the year in the development of coincident peak allocators?
A.No. Even though there have been other proposals,
22 the Commission has always used a 12CP methodology to
23 allocate base load production costs. Weighted 12CP methods
24 have often weighted some months as zero. When the
25 Commission accepted such weighting, it averaged the zero
CASE NO. IPC-E- OS - 1012/03/0S HESSING, K (Reb) 14
STAFF
1 weighted result with a 12CP allocator that included a
2 coincident peak demand value for all months. I believe that
3 the Commission's decisions are in recognition of the fact
4 that capacity has value in all months.
5 Q.Dr. Peseau says that the 12CP "Base Case" method
6 included in the Company's filing in this case is not the
7 method used as the starting point for cost allocation in
S Case No. IPC-E-03-13. Please comment.
9 A.The Base Case method presented by the Company in
10 this case is substantially the method used by the Commission
11 as the starting point for cost allocation in the IPC-E-03-13
12 case. There are two differences. The Base Case method
13 filed by the Company in this case used coincident peaks
14 based on a five-year median value instead of the most recent
15 year. I discussed this difference earlier in my testimony.
16 The other difference is in the number of zero weighted
17 months. In the IPC-E-03-13 case as well as the Base Case
lS cost of service in this case, zero weighted months are
19 averaged with non-zero coincident peaks to obtain the final
20 allocator used in the cost of service model. The cost
21 shifts to high load factor customers due to changes in Base
22 Case methodology that Dr. Peseau discusses in his testimony
23 simply did not occur.
24 Q.Since the Company and most parties to this case
25 are supporting some version of 3CP/12CP methodology, why is
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) 15
STAFF
1 it important to establish that the Base Case methodology
2 presented by the Company in this case is substantially the
3 same methodology used by the Commission as the revenue
4 allocation starting point in the IPC-E- 03 - 13 case?
5 A.If it is substantially the same methodology last
6 used by the Commission, then the proposed change to 3CP/12CP
7 methodology does not cause a radical change in results.
8 This is demonstrated on Company Exhibit No. 69 where the two
9 resul ts are compared. Since both methods show large
10 increases to high load factor customers, the proposed change
11 in methodology is not driving those results.
12 Seasonal Shapes included in Allocation Factors
13 Q.On page 38 of his direct testimony Dr. Peseau
14 includes two charts that show the effects of marginal cost
15 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 someone might view the charts and conclude that
19 allocation factors include no shape except that provided by
20 marginal cost weighting. That is not true. All of the
21 energy and demand allocation factors proposed for use in
22 this case capture the monthly shape of every individual
23 class's energy and coincident peak demand. The only time
24 this is not true is if the monthly weight is set at zero and
25 the weighted and unweighted allocators are not averaged.
CASE NO. IPC-E-08-10
12/03/08 HESSING, K (Reb) 16
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 Case
4 method on Company Exhibit No. 59. The weighted and
5 unweighted shapes of irrigation class energy and coincident
6 peak demands are striking and show why the irrigation class
7 is allocated significant costs for use during the summer
S peak period.
10
9 The Department of Energy's Cost of Service Proposal
Q.What is Dr. Goins' preference for the
12
11 classification of production plant?
A.He initially recommends that all production plant
13 investment be classified as 100% demand related. To my
14 knowledge this has never been done in Idaho. Coal and hydro
15 plants cost more per kW to build than gas fired peaking
16 units. The additional investment is made with the knowledge
17 that energy can be produced at a lower cost from these
lS plants when they are operated at a high capacity factor.
19 Since the additional investment is incurred to reduce energy
20 costs it is logical to allocate the investment as energy
22
21 related.
Q.Please discuss the Department of Energy's Cost of
24
23 Service proposal presented by Dr. Goins.
A.Dr. Goins presents the results of four different
25 cost of service studies but recommends that the Commission
CASE NO. IPC-E-OS-10
12/03/0S 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. Neither one averages weighted and unweighted
6 demand allocators.
7 Q.Are any of the monthly weighting factors zero in
S his studies?
9 A.Yes. Six months are weighted at zero in the
10 development of the capacity related demand allocator applied
11 to production plant. Demand related transmission allocators
12 and Energy allocators are also weighted but no month is
13 weighted at zero. For base load production plant his method
14 results in a demand allocation based on 6 coincident peaks,
15 or a 6CP method.
16 Q.What is the difference between the two weighted
17 12CP methods he recommends?
lS A.In Exhibit No. 610 he classifies hydro and thermal
19 production plant costs and purchased power expense as
20 proposed by the Company using the load factor method. The
21 results presented in Exhibit No. 611 classify these same
22 costs using an alternative method.
23 Q.Do you believe that the Commission should accept
24 either one of his weighted 12CP studies?
25 A.No. I have already stated my preference to move
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) lS
STAFF
1 to the Company-proposed 3CP/12CP method and I have discussed
2 concerns that I have with zero weighted months especially
3 when there is no averaging of allocators. I have also
4 discussed the reasons why I support the load factor
6
5 classification of base load production plant costs.
Q.Does Dr. Goins recommend that the Commission use
7 his cost of service results or any of the results from the
S methods presented by the Company as a starting point in
10
9 class revenue allocation in this case?
11
A.No. He recommends a uniform percentage spread.
13
12 to the classes in this case?
Q.Do you support a uniform percentage revenue spread
A.No. No serious move toward cost of service has
14 been made since the IPC-E-03-13 case even though there have
15 been two cases since then. The longer the Commission
16 postpones moves toward cost of service the greater cost of
17 service differences are likely to be. I recommend that the
lS Commission make some move toward cost of service in this
20
19 case.
Q.Does this conclude your rebuttal testimony in this
22
21 proceeding?
23
24
25
A.Yes, it does.
CASE NO. IPC-E-OS-1012/03/0S HESSING, K (Reb) 19
STAFF
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 3RD DAY OF DECEMBER2008,
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1000 INDEPENDENCE AVE SW
WASHINGTON DC 20585
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arhur. bruderCfhq.doe. gOY
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~.~
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