20101116Paice Rebuttal, Exhibits.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN TH MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
APPROVAL OF CHANGES TO ITS )
ELECTRIC SERVICE SCHEDULES )
AND A PRICE INCREASE OF $27.7 )
MILLION, OR APPROXIMATELY )13.7 PERCENT )
CASE NO. PAC-E-I0-07
Rebutt Testimony of C. Craig Paice
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-I0-07
November 2010
1 Q.Are you the same C. Craig Paice that. previously filed direct testimony in this
2 docket?
3 A. Yes.
4 Purpose and Summary
5 Q.What is the purpose of your rebuttal testimony?
6 A.My rebutta testimony includes revised exhibits to reflect changes in the Idaho
7 Results of Operations contained in the rebuttal testimony of Company witness Mr.
8 Steven R. McDougal. Additionally, I respond to the testimony of Idao Public
9 Utilities Commssion Staff witness Mr. Bryan Lanspery, PacifiCorp Idaho
10 Industrial Customers ("PilC") witness Mr. Donald Schoenbeck, and Community
11 Action Parnership Association of Idaho ("CAP AI") witness Ms. Teri Ottens.
12 Updated Exhibits
13 Q.Have you prepared any updates to the exhibits filed with your rebuttal
14 testimony?
15 A.Yes. Exhibit No. 81 and Exhibit No. 82 are updates to Exhibit No. 47 and Exhibit
16 No. 48. The revised exhbits reflect changes in the Idaho Results of Operations as
17 presented in Company witness Mr. McDougal's rebuttal testimony.
18 Rebuttal to Direct Testimony of Mr. Bryan Lanspery
19 Cost of Service Support for Residential Customer Increase
20 Q.Why doe Mr. Lanspery propose giving residential Schedule 1 and 36
21 customers an equal percentage increae?
22 A.Mr. Lanspery's proposal is based on the belief that the Company's cost of service
23 study does not provide adequate justification for the increase to residential
Paice, Di-Reb - 1
Rocky Mountan Power
1
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Schedule 36 customers.
Do you agree with hi assertion regarding the Company's cost of servce
results?
No. I disagree for several reasons. First, Mr. Lanspery's assertion is based on his
review of two data request responses provided by the Company. He does not
provide any detailed analysis to ilustrate why the Company's cost of service
results are inadequate.
Next, he fais to acknowledge that Staff witness Mr. Keith Hessing
supports the Company's cost of service study. Mr. Hessing's reasons for
supporting the cost study are: 1) it employs the same basic methodology used in
the Revised Protocol jursdictional allocation process; and 2) it is the same
methodology accepted by the Commssion in prior general rate case decisions.
Also, Mr. Hessing's cost of service results contained in Staf Exhibit No. 129 are
calculated using the same model and methodology proposed by the Company.
Finally, the Company's cost of service results presented in this case are
consistent with results in the prior general rate case. In case PAC-E-07-05, cost
of service results showed that Schedule 36 customers needed an increase slightly
more than 1.8 times the increase requied for Schedule 1 customers. Similarly,
cost of service results in ths case show Schedule 36 customers neeng an
increase of about 1.9 times the increase needed for Schedule 1 customers. This
demonstrates that the Company's cost of service methodology produces a high
level of consistency between cases. For these reasons, I suggest the Commssion
disregard Mr. Laspery's opinion regarg the Company's cost of service results.
Paice, Di-Reb - 2
Rocky Mountan Power
1 Rebuttal to Direct Testimony of Mr. Donald Schoenbeck
2 Generation and Transmission Cost Allocations
3 Q.
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6 A.
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18 A.
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Do you agree with Mr. Schoenbeck's proposal to allocate demand-related
generation and transmission costs using one winter and one summer monthly
system coincident peak (2 CP W/S)?
No. Mr. Schoenbeck's proposed use of a 2 CP method:
1) fails to recognize how the Company plans and operates its generation and
transmission systems;
2) is inconsistent with inter-jursdictional allocations;
3) has the potential to shift customer costs creating rate volatilty; and
4) violates the principle of gradualism which is generaly viewed as an
important consideration in determnig class cost causation.
In addition, Mr. Schoenbeck provides no signicant analysis to support his
recommendation.
Why doe the Company support use of a twelve system coincident peaks (12
CP) method for alocating demand-related generation and transmission
costs?
The 12 CP method is preferable for several reasons. First, the Company has
historicaly allocated generation and trsmission demad-related costs using the
12 CP methodology to reflect the fact that the six-state system is planned and
dispatched as an integrated system. This methodology has been use by the
Company since the Uta Power - Pacifc Power merger in 1989 and continues to
be use because it reflects actual integrated system operations. Dug the Multi-
Paice, Di- Reb - 3
Rocky Mounta Power
1 State Process ("MSP") case PAC-E-02-3 the Company revisited the stress factor
2 analysis that was employed at the time of the merger to determne if a 12 CP
3 allocation method is stil the most appropriate method for the Company to use.,
4 The results indicated that all months contrbute to the system peak in some way
5 and should be included in cost allocation. This allocation issue was raised in the
6 Company's 2001 case PAC-E-01-16 involving Monsanto's contract rate. Staff
7 witness Mr. David Schunkeendorsed the Company's 12 CP approach stating the
8 following on page 16 of his diect testimony:
9 "A 12 CP generation and transmission allocator better10 represents the actual system operation. It recognizes
11 that each of the monthly peaks is of importce."
12 The 12 CP methodology recognizes that each of the monthly peaks is importt
13 because the Company must plan for and dispatch its resources durg each of the
14 12 months of the year. Additionally, staff witness Mr. Keith Hessing, stated in his
15 diect testimony in this case:
16 "The cost of service methodology presented by the
17 Company is the same methodology accepted by the
18 Commssion in recent general rate case decisions."
19 Second, it is appropriate for allocation methods to be consistent between
20 inter jursdictional and class costs of service. Again, in Case PAC- E-O 1-16, staff
21 witness Mr. Schunke stated the following in his diect testimony on pages 18-19:
22 "I also believe that the jursdctional alocation and
23 the class cost-of-servce alocation should employ
24 similar methodologies. Costs come to Idao though25 the jursdictional allocation. It maes sense to be
26 consistent in the allocation methodology and assign
27 costs to the customer classes in the same way they are28 assigned to the jursdiction."
Paice, Di-Reb - 4
Rocky Mountan Power
1 The 12 CP methodology is employed in both the class cost of service study and
2 the Jursdictional Allocation Model ("JAM"), and has been used since its approval
3 in the MSP Case. Finally, Mr. Schoenbeck fails to mention how his
4 recommended methodology would impact customer class revenue requirements.
5 For example, if the Company's cost of service by rate schedule (Exhibit No. 47,
6 Page 2) had been prepared using a 2 CP method instead of the 12 CP method, the
7 residential time-of-day class would need an additional increase of approximately
8 $1 millon and the irgation class would need an additional increase of almost $3
9 mion.
10 Distrbution Cost Allocations
11 Q.
12
13 A.
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26
Is Mr. Schoenbeck correct in his understanding of which peak load values
are used to develop distribution cost allocation factors?
No. Mr. Schoenbeck states the following on pages 8 and 9 of his testiony:
"For the generation and transmission demand allocation
factor, it is simply the sum of all twelve monthly coincident
peak values ("12 CP"). For the mai distrbution demand
allocation factor, the Company stas with the same twelve
monthly coincident class values as used for the generation and
transmission allocation factor." (emphasis added)
Whle it is tre that the Company uses 12 monthly system coincident peaks to
alocate generation and trnsmission demand costs, they are not used to allocate
distrbution demad-related costs. The Company's cost of service proceures that
accompanied my diect testimony (see Exhibit No. 49, Tab 1, Pages 7-9) clearly
describe the diferences between 12 system coincident peaks, 12 distrbution
coincident peaks, and non-coincident pe loads and explains how they are used
to allocate demand related costs in the cost of service study. Specificaly, the
Paice, Di-Reb - 5
Rocky Mounta Power
1
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14 Q.
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17 A.
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Company develops and employs the following types of peak load values for use
in the cost of service study:
. The 12 system coincident peaks or "12 CP" (each class' contribution to
the 12 monthly peaks coincident with the Company's six-state system
peak) are used to alocate class generation and transmission demand costs.
. The 12 distrbution system coincident peaks or "12 DCP" (simultaneous
combined demad of all distrbution voltage customers at the hour of the
Idaho distrbution system peak weighted by the percent of substations
achieving their annual peak in each month of the year) are used to allocate
substation and prima line costs.
. The maximum non-coincident peaks or "NCP" (maximum monthy class
non-coincident peak) are used to allocate line transformers and secondar
lines.
Mr. Schoenbeck proposes the use of the clas single non-coincident peak (1
NCP) method to allocte distribution demand-related costs for substations
and primary poles and conductors. Is this method appropriate?
No. Mr. Schoenbeck's recommended 1 NCP allocation method is not appropriate
because it ignores the cost causing basis for these facilties, i.e. customers' load
diversity. Load diversity (see cost of service procedures, pages 8-9) recognies
that individual customer peak demads ocur at different times. The Company's
distrbution engineers recognize load diversity when they design substations and
prima lies because they size these facilties to meet the simultaeous
distrbution peak load of the connected customers, not the 1 NCP for each
Paice, Di-Reb - 6
Rocky Mountan Power
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9 A.
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customer class as Mr. Schoenbeck recommends. As such, the Company's use of a
12 DCP method to allocate substations and primar lines is based on cost
causation because it recognizes the load diversity that customers brig to the
distrbution system.
Do you agree with Mr. Schoenbeck's assertion that the NARUC Electric
Utilty Cost Allocation Manual (NARUC Manual) acknowledges a 1 NCP
method to be "a reasonable - and most often used - alternative" to allocate
substation and primary line costs?
No. On page 97 of the NARUCManual, the discussion references the selection
of allocators for all demand-related distrbution costs. Specifically, the manual
states:
"Local area loads are the major factors in sizing distrbution
equipment. Consequently, customer-class noncoincident
demands (NCPs) and individual customer maximum
demands are the load characteristics that are normally used
to allocate the demand component of distrbution facilties.
The customer-class load characteristic use to allocate the
demand component of distrbution plant (whether customer
class NCPs or the summation of individual customer maximum
demands) depends on the load diversity that is present at the
equipment to be allocated. The load diversity at distrbution
substations and primar feeders is usualy high. For this reason,
customer-class peaks are normally used for the alocation of
these facilities." (p. 97)
As previously stated, the Company selected weighted monthy distrbution peaks
for allocating distrbution substations and priar lies because load diversity is
recognid when these facilties ar designed. In addition, when discussing major
costing methodologies, the NARUC Manual does not imply that a "one-size-fits-
all" approach is indicative of industr practices as evidenced by the following:
Paice, Di-Reb-7
Rocky Mountan Power
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"This manual only discusses the major costing methodologies.
It recognizes that no single costing methodology wil be superior
to any other, and the choice of methodology wil depend on the
unique circumstaces of each utiity." (p. 22)
Mr. Schoenbeck's reference to the NARUC manual appears to be taen out of
context.
What are the implications of Mr. Schoenbeck's proposal?
The test period in this case identifies the sum of the 12 DCP's at input being
3,565,097 KW and the sum of the 12 monthly NCP's for all customers at input
being 12,547,715 KW. Considering that the sum of non-coincident peaks is more
than thee and one-half times greater than customer demand at the time of the
distrbution system peak, the cost to build substations would be significantly
higher if they were designed to serve the undiversifed load, or NCPs, of all
customers. As explained earlier, substations are built to meet the simultaneous
peak load of connected customers. In reference to the Company's methodology,
Mr. Schoenbeck asserts on page 14 of his diect testimony that "the distribution
demand allocation factor ignores the localized diversity that exists on the
Company's distrbution system." In fact, it is Mr. Schoenbeck's propose 1 NCP
methodology that ignores the localed diversity that exists on the Company's
distrbution system.
Doe the Company employ a 12 DCP method to allocate distribution
demand-related costs in jurisdictions other than Idaho?
Yes. This methodology is used by the Company to alocate substations and
prima lines in cost of service studies filed in Calfornia, Oregon, Uta, and
Wyoming.
Paice, Di-Reb - 8
Rocky Mounta Power
1 Q.
2
3 A.
What are your conclusions regarding Mr. Schoenbeck's allocation
proposals?
I recommend the Commssion reject Mr. Schoenbeck's proposals to 1) allocate
4 demand related Generation and Transmission costs using 2 CPW IS and 2) to
5 allocate distrbution substations and priar lines using a 1 NCP for reasons cited
6 above.
7 Irgation Class Loads
8 Q.
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10 A.
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14 Q.
15 A.
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What does Mr. Schoenbeck propose regarding irrigation class demands used
in the cost of servce study?
Mr. Schoenbeck asserts that irgation class demands used by the Company in the
cost of service study are inappropriate. He proposes using one of two methods to
more appropriately determne the level of curtailment associated with irgation
customers.
Do you agree with Mr. Schoenbeck's proposal?
No. The Company indicated in response to ilPA Data Request 16, provided as
Exhibit No. 83, that the level of curilment for the irgation load control
progra was reflected in the historic five year average (2005-2009) actual load
researh sample data for the irgation class. Using either one of Mr.
Schoenbeck's methods to calculate a load adjustment value does not necessarly
provide a more appropriate level of curailment, his estimation methods are only
diferent.
Paice, Di-Reb - 9
Rocky Mounta Power
1 Response to Direct Testimony of Ms. Teri Ottens
2 Customer-Related Costs
3 Q.
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7 A.
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15 Q.
16 A.
In her testimony, Ms. Ottens states that she cannot understand how anyone
analyzing utilty costs can specify which of those costs are "customer
related." Please explain how the Company determies which costs are
"customer related" and why they are importnt.
The cost of service study procedures fied in my dict testimony, Exhibit No. 83,
Tab 1, explains that customer-related costs are diectly related to the number of
, customers served. These costs include meters, meter readig, meter maintenance,
service drops, biling and customer service. Whether a customer tus on their
lights or not, the Company must provide customers with access to electrcity,
accurtely measure electrc consumption, provide a bil, and answer a customer's
phone calls. Assigning these costs based upon the number of customers promotes
faiess and sends the correct price signal.
Doe this conclude your rebuttal testimony?
Yes, it does.
Paice, Di - Reb - 10
Rocky Mounta Power
Case No. PAC-E-I0-07
Exhibit No. 81
Witness: C. Craig Paice
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Rebuttal Testimony of C. Craig Paice
Rebuttl COS - Summar by Rate Schedule
November 2010
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Case No. PAC-E-I0-07
Exhibit No. 83
Witness: C. Craig Paice
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Rebutt Testimony of C. Craig Paice
IIP A Data Request 16
November 2010
PAC-E-I0-07/Rocky Mountain Power
June 28, 2010
LIP A Data Request 16
Rocky Mountain Power
Exhibit No, 83 Page 1 of 1
Case No. PAC-E-1O-Q7
Witness: C. Craig Paice
IIPA Data Request 16
With respect to Exhibit 49, Tab 5, page 7, please answer the following:
A. Are all of these values actual? If not, please provide and explanation of how they
were normalized and the workpapers that support the normalization.
B. What level of curtailment of Schedule 10 load is reflected on line 23? Is this level
of curtailment the same as occured in 2008 and 2009 or is expected to be
incured in 201O?
C. What is the level of curilment that is reflected in each month on line 26 for the
Irgation load?
Response to LIP A Data Request 16
A. The values presented reflect estiates of forecast class demand levels at the time
of the merged Company system peak. Base year load measurements (census) and
estimates (sample data) are adjusted to match test year energy levels.
B. The level of curtailment of Schedule 10 load reflected on line 23 is derived from
the historic five year average (2005-2009) of actual load researh sample data
adjusted to test period energy. Because the load curlment progrm operated
durng most of this five year period, the load curilment program impact is
reflected in the five year average data. The level of curtent is based on this
five year average and does not represent any individual year or any specific
curailment amount.
C. No class load data is shown on lie 26. Please refer to the Company's response to
par B. above.
Recordholder:
Sponsor:
C. Craig Paice / Scott D. Thornton
C. Crag Paice