20080107Tatum rebuttal.pdf

RE
Z308 JAN -4 PM 4: 34
IDAHO PUi3l1C
UTiLITIES COMMISSIC;,
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPAN FOR
AUTHORITY TO INCREASE ITS RATES
. AN CHAGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE STATE
OF IDAHO.
CASE NO. IPC-E-07-8
IDAHO POWER COMPAN
DIRECT REBUTTAL TESTIMONY
OF
TIMOTHY E. TATUM
1 Q.Please state your name.
2 A.My name is Timothy E. Tatum.
3 Q.Are you the same Timothy E. Tatum that
4 previously presented direct testimony?
5 A.Yes.
6 Q.What is the scope of your rebuttal testimony?
7 A.My testimony will focus on the issues raised
8 by the intervening parties regarding the Company's cost-of-
9 service study. It should be noted that any omission on my
10 part in addressing issues raised by the parties does not
11 indicate my concurrence with those issues.
12 Q.Dr. Peseau and Dr. Reading claim that the
13 Base Case cost-of-service methodology you presented in your
14 direct testimony is a significant departure from the cost-
15 of-service methodology that was used to prepare the cost-of-
16 service study Idaho Power presented in Case No. IPC-E-03-13
17 (U03-13 Case"). Is that true?
18 A.No. The Base Case cost-of-service study in
19 this case applies the same cost-of-service methodology used
20 in the 03-13 Case with the exception of two changes that the
21 Company agreed to make as a result of the cost-of-service
22 workshops conducted at the Commission's direction in Case
23 No. IPC-E-04-23.
24 Q.Please describe the two revisions that the
25 Company made to the cost-of-service methodology since the
TATUM, DI-REB 1
idaho Power Company
1 03-13 Case.
2 A.The two changes that the Company agreed to
3 make as a result of the workshop process are both related to
4 the preparation of the coincident peak demands used to
5 compute the allocation factors for generation- and
6 transmission-related costs. The changes included (1) a
7 revised methodology to convert billing period data into
8 calendar month data and (2) a surrogate for a demand
9 normalization methodology.
10 Q.How was the methodology used to convert
11 billing period data into calendar month data changed from
12 the 03-13 Case?
13 A.In accordance with the consensus of the
14 parties in the workshops, the method for converting billing
15 period data into calendar month data was revised to move
16 from a simple linear interpolation to a non-linear method.
17 The new method utilizes daily usage patterns to capture the
18 effects weather has on energy consumption which improves the
19 process of determining coincident peak demand
20 responsibility.
21 Q.Was this method used in Case No. IPC-E-05-28
22 (U05-28 Case")?
23 A Yes.
24 Q.Please explain how the surrogate demand
25 normalization methodology used in this case differs from the
TATUM, DI-REB 2
Idaho Power Company
1 methodology used to determine coincident peak demands in the
2 03 -13 Case.
3 A.In the 03-13 Case, the coincident peak
4 demands for each class were determined based upon demand
5 ratios from the load research data in a single year. The
6 demand normalization methodology used in this case uses the
7 five-year median demand ratios from the load research sample
8 applied to the normalized monthly energy values for each
9 customer class to determine the coincident peak demands by
10 class. This methodology reduces the effect of any atypical
1l demand ratios that might exist in a given test year due to
12 unusual weather conditions.
13 Q.Did the Company use the surrogate demand
14 normalization methodology in a cost-of-service study filed
15 in the 05-28 Case?
16 A.Yes. The surrogate demand normalization
17 methodology was used to determine the coincident peak
18 demands in the uNormalized" cost-of-service study filed in
19 the 05-28 Case.
20 Q.Dr. Peseau devotes a considerable portion of
21 his testimony to criticizing the change in the cost of
22 serving his client's loads between the 03-13 Case and this
23 case. Are the two changes that the Company agreed to
24 implement as a result of the cost-of service workshops
25 responsible for the significant difference between the
TATUM, DI-REB 3
Idaho Power Company
1 results of the study prepared for the 03-13 Case and the
2 results of the Base Case study in the current proceeding?
3 A.No. As Mr. Hessing correctly points out in
4 his direct testimony, energy-related costs have increased
5 more rapidly than demand- and customer-related costs since
6 the 03-13 Case. For example, since the settlement of the
7 05-28 Case, operating expenses (excluding taxes) have
8 increased by approximately 27 percent with 86 percent of
9 that increase being classified as energy-related. As a
10 result, customers who use more energy - higher load factor
11 customers - receive a larger share of the revenue increase
12 than has been the case in prior rate case proceedings.
13 Q.Has the Company presented a cost-of-service
14 study using a methodology consistent with the Base Case
15 methodology in any prior Idaho rate case proceedings?
16 A.Yes. The Base Case study applies the same
l7 methodology used to prepare the uNormalized" study presented
18 to the Commission in the 05-28 Case.
19 Q.Did the results of the uNormalized" study
20 presented in the 05-28 Case allocate a larger share of the
21 revenue increase to higher load factor customers than in
22 prior rate case proceedings?
23 A.Yes. The uNormalized" study prepared in the
24 05-28 Case yielded results similar to the Base Case study in
25 the current proceeding. Furthermore, in the 05 - 28 Case, the
TATUM, DI-REB 4
Idaho Power Company
1 Company presented a second study using a cost-of-service
2 methodology identical to that used in the 03-13 Case which
3 it called the "Traditional" study. The UTraditional" study
4 presented in the 05-28 Case also produced results similar to
5 the Base Case study in the current proceeding.
6 Q.On pages 41 through 44 of his testimony, Dr.
7 Peseau claims that the Company has incorporated an
8 uaveraging" element into its traditional method of computing
9 the weighted twelve coincident peak demand allocation
10 factors that has not been previously sanctioned by the
II Commission. Is Dr. Peseau accurately presenting the facts?
12 A.No. In the 03-13 Case, the Company applied
13 the same Uaveraging" approach, as described by Dr. Peseau,
14 in the development of the weighted twelve coincident peak
15 demand allocation factors. While Dr. Peseau also took issue
16 with the Company's use of the Uaveraging' approach in that
17 case, the Commission ultimately approved the Company's
18 weighted twelve coincident peak demand methodology in Order
19 No. 29505.
20 Q.Dr. Peseau points out on page 44 of his
2l testimony that since the 03-13 Case, the number of months in
22 which the marginal cost weighting factors are applied to the
23 coincident peak demands has increased to include the months
24 May and September. He argues this results in unonsensical"
25 cost assignment. Has the Company determined the numer of
TATUM, DI-REB 5
idaho Power Company
1 months used to seasonalize the coincident peak demands in a
2 manner differently from the previously approved methodology?
3 A.No. In the 03-13 Case, the generation and
4 transmission marginal costs were seasonalized according to
5 the projected monthly peak hour capacity deficits identified
6 in the Company's most recent Commission-accepted Integrated
7 Resource Plan (UIRP"). In this case, the Commission-
8 accepted 2006 IRP was used in the same way. The 2006 IRP
9 analysis projects additional capacity deficits in May and
10 September which are reflected in the weighting factors.
11 Q.Dr. Peseau argues that including the months
12 of May and September in the marginal cost analysis is
l3 erroneous because those months have Utypically been low cost
14 months" for Idaho power's system. Is that a legitimate
15 critique of your approach?
l6 A.No. Whether or not May and September have
17 been Utypically low cost months" for Idaho Power's system in
18 the past is not relevant in this instance. Including those
19 months in the marginal cost weighting factor process today
20 is consistent with the approved methodology. I explain the
21 reasoning for using marginal cost weightings in the
22 derivation of the demand- and energy-related allocation
23 factors on page 25 of my direct testimony:
24 uThe use of marginal cost weighting is25 intended to strike a balance between26 backward-looking costs already incurred27 and forward-looking costs to be incurred
TATUM, DI-REB 6
Idaho Power Company
1 1n the future."
2
3 The role of the seasonalized marginal cost weighting
4 approach is to provide the forward-looking aspect to the
5 allocation factors. While the historical seasonality of the
6 costs imposed on Idaho Power's system is quite important to
7 consider in the overall assignment of costs, it is not
8 relevant in the context of a forward-looking adjustment
9 factor. According to the 2006 IRP, the Company anticipates
lO a need for additional generation and transmission resources
11 to successfully serve loads in May and September prior to
l2 the end of 20ll. As a result, the marginal costs have been
13 seasonalized in recognition of this need to serve loads.
14 Q.Mr. Yankel recommends the introduction of a
l5 uGrowth Corrected" component into the derivation of the
l6 allocation factors for generation and transmission related
l7 costs. Do you agree with Mr. Yankel' s recommendation?
l8 A.No. Mr. Yankel' s method does not reasonably
.
19 apportion costs among customer classes. What Mr. Yankel
20 proposes is to inject an additional growth-related weighting
21 factor into the existing weighted twelve coincident peak
22 demand method. Mr. Yankel' s growth-related weighting
23 factors are based on the energy sales growth forecast from
24 the Company's Sales and Load Forecast for the 2006 IRP.
25 This method results in an allocation of costs that is
26 predominately driven by forecasted energy sales growth and
TATUM, DI-REB 7
Idaho Power Company
1 fails to give adequate recognition to the impact that
2 existing loads have on costs.
3 Q.Is Mr. Yankel' s use of forecasted energy
4 sales to weight the class coincident peak demands
5 reasonable?
6 A.No. Mr. Yankel' s use of forecasted energy
7 sales to weight the class coincident peak demands is not
8 reasonable for two reasons. First, Mr. Yankel' s method
9 assumes that energy sales by class will grow at the same
lO rate as class coincident peak demands. This assumption is
11 not consistent with the Company's 2006 IRP analysis which
l2 anticipates that system peak demands will grow at a much
l3 faster rate than average demands or energy sales. Secondly,
14 Mr. Yankel derives his growth-related weighting factors for
l5 each customer class based upon the anticipated change in
l6 energy sales within each class. As a result, the class-
l7 specific weighting factors produced by Mr. Yankel do not
l8 consider the magnitude of each class's energy sales growth
19 relative to the overall system energy sales growth. For
20 example, Mr. Yankel suggests a growth-related weighting
2l factor of LO. 65 percent for residential customers based on
22 residential energy sales growth of 5l8, 000 megawatt-hours
23 (MWh). For industrial customers, Mr. Yankel suggests a
24 growth-related weighting factor of 13.54 percent based on
25 energy sales growth of 330,000 MWh within the industrial
TATUM, DI-REB 8
Idaho Power Company
1 class. It is not reasonable to suggest that residential
2 customers should experience a smaller growth-related
3 adjustment than industrial customers considering that
4 residential energy sales growth represents a much larger
5 percentage of the overall system energy sales growth.
6 Q.Does Mr. Yankel' s proposed method allocate
7 costs to customer classes in a manner that sufficiently
8 recognizes their contribution to the summer peak?
9 A.No. In fact, Mr. Yankel' s method removes the
lO very recognition of cost seasonality that the weighted
II twelve coincident peak demand method is intended to provide.
l2 For example, Mr. Yankel' s method results in an allocation of
13 demand-related generation costs to irrigation customers that
14 is roughly one-third the cost assignent that results from
15 the Company's Base Case study. Furthermore, Mr. Yankel' s
l6 method assigns approximately half of the demand-related
17 generation costs to irrigation customers that would occur
18 under a traditional un-weighted twelve coincident peak
19 demand method, which provides no seasonal cost recognition.
20 Considering that the irrigation class's peak annual demand
21 occurs during the summer months when generation costs are at
22 their highest, Mr. Yankel's results are counter intuitive.
23 Q.On page 38 of your direct testimony, the 3
24 CP/12 CP study is identified as the preferred cost-of-
25 service approach. However, Dr. Peseau states on page 47 of
TATUM, DI-REB 9
idaho Power Company
1 his testimony that he believes the 3CP / Average Energy
2 approach to be your preferred approach. Is Dr. Peseau
3 correct in his assertion that the 3 CP / Average Energy
4 methodology is your preferred approach?
5 A.No. Dr. Peseau is mistaken in his statement
6 that my preferred cost-of-service study uses the 3
7 CP/Average Energy approach. On page 38, lines 19 and 20, of
8 my direct testimony, I state that the 3 CP/l2 CP method
9 applies the Company's preferred approach. I explain my
10 rationale for rejecting the 3 CP/Average Energy method on
1l pages 39 and 40 of my testimony.
12 Q.In discussing his concerns with the 3 CP/l2
13 CP method, Dr. Peseau makes the statement:
14
15
l6
17
18
19
202l
22
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24
25
26
UQui te apart from the fact that the
methodology cannot be squared wi th sound
cost of service logic and theory, the
attempt to pick and choose plants that
will be assigned to demand and energy in
different proportions, as Mr. Tatum
does, is apt to lead to complete chaos
in future proceedings, as each party
tries to claim a disproportionate share
of low cost plants for its own
individual load profile."
Q. Do you agree wi th Dr. Peseau' s prediction of
27 future problems?
28 A.No. What I have proposed is a standard
29 ratemaking approach. The 3 CP/l2 CP method incorporates an
30 allocation approach that is quite similar to the Base-
31 Intermediate-Peak (UBIP") method endorsed by the National
TATUM, DI-REB 10
Idaho Power Company
1 Association of Regulatory Utility Commissioners (UNARUC") in
2 its most current Electric Utility Cost Allocation Manual
3 dated January 1992. On page 60 of the NARUC manual the BIP
4 method is presented with the following description:
5 uThe BIP method is a time-differentiated
6 method that assigns production plant7 costs to three rating periods: (l) peak
8 hours, (2) secondary peak ( in termedia te ,
9 or shoulder hours) and (3) base loading10 hours. This method is based on the
1l concept that specific utility system
l2 genera tion resources can be assigned in13 the cost of service analysis as serving14 different components of load; i. e. ,15 base, intermediate, and peak loadl6 components. "
l718 The Electric Utility Cost Allocation Manual
19 continues on page 6l with the following discussion of the
20 BIP method:
2l uThere are several methods that may be22 used for allocating these categories23 of costs to customer classes. One
24 common allocation method is as25 follows: (1) peak production plant26 costs are allocated using an27 appropriate coincident peak allocation28 factor; (2) intermediate production29 plant costs are allocated using an30 allocator based on the classes'31 contributions to demand in the32 intermediate or shoulder period; and33 (3) base load production plant costs34 are allocated using the classes'35 average demands for the base or off-36 peak rating period."
37
38 The NARUC BIP method has been around for many years
39 and incorporates much of the same cost of service logic and
40 theory that I applied in the 3 CP/12 CP method.
TATUM, DI-REB LL
Idaho Power Company
1 Q.Dr. Goins recommends that the Company depart
2 from using the Idaho jurisdictional load factor to classify
3 hydro and steam production plant as demand and energy.
4 Similarly, Dr. Reading recommends the Company move away from
5 using the Idaho jurisdictional load factor for the
6 classification of hydro production plant. Has the
7 Commission supported the use of the jurisdictional load
8 factor to classify steam and hydro production plant to
9 demand and energy in past rate case proceedings?
10 A.Yes. The Commission has supported the use of
11 the jurisdictional load factor to classify production plant
12 as demand and energy beginning with its Order No. l7856
13 issued in Case No. U-1006-185 in 1983. Following Order No.
14 17856, the Company has used this method in all cost-of-
15 service studies filed with this Commission.
l6 Q.Dr. Reading recommends that hydro production
17 plant be classified as 75 percent demand and 25 percent
l8 energy with steam production plant continuing to be
19 classified according to the traditional load factor
20 approach. Do agree wi th Dr. Reading's rationale supporting
21 his recommendation?
22 A.While I do not disagree that moving to a
23 method that classifies a larger percentage of production
24 plant as demand may be appropriate, I believe that such a
25 method should be based upon, at least in part, studies and
TATUM, DI-REB l2
Idaho Power Company
1 analyses using data specific to Idaho Power's system. Dr.
2 Reading supports his 75/25 demand to energy approach for
3 classifying hydro production plant because it is the same
4 approach used by PacifiCorp. Withoút further study, I do
5 not believe that the fact that PacifiCorp follows this
6 approach provides a sufficient basis for a change of this
7 magni tude.
8 Q.Dr. Goins recommends that both hydro and
9 steam production plant be classified as 60 percent demand
10 and 40 percent energy. What is your opinion of Dr. Goins'
11 recommendation?
l2 A.It is my understanding that Dr. Goins' 60/40
13 classification method is based on the ratio of the weighted
14 energy allocation factors in the unon-capacity deficit
15 months" to the deficit months. While this recommendation
16 has some appeal, without additional study I am not convinced
17 that this method is superior to the Company's historical
18 load factor approach.
19 Q.Do you believe the recommendations of Dr.
20 Goins and Dr. Reading to classify a larger share of the
2l Company's investment production plant as demand-related
22 warrant further consideration?
23 A.Yes, I do. At the time the Commission
24 adopted the jurisdictional load factor method as its
25 preferred method, Idaho Power's system was energy
TATUM, DI-REB l3
Idaho Power Company
1 constrained. Since that time, the Company's system has
2 become capacity constrained. With that in mind, the time
3 may be right to reevaluate the classification method.
4 Q.Dr. Goins and Dr. Reading also recommend that
5 the Company classify a larger share of FERC Account 555,
6 Purchased Power, as demand. On what basis does the Company
7 currently classify Purchased Power expenses booked to FERC
8 Account 555?
9 A.FERC Account 555 is classified as either
10 demand-related or energy-related according to an uas-billed
LL basis. " That is, purchased power expenses are classified as
12 either demand- or energy-related based upon the structure of
13 the power purchase contract between the Company and the
L4 energy seller. The FERC Account 555 has two sub-accounts:
15 555.1, Purchased Power (non-PURPA purchases), and 555.2,
16 Cogeneration and Small Power Production (PURPA purchases) .
L7 Sub-account 555.L, Purchased Power, is classified as Uenergy
18 only" to align wi th the structure of the purchase
19 agreements. Sub-account 555.2, Cogeneration and Small Power
20 Production, is classified as approximately 98 percent energy
21 and approximately 2 percent demand.
22 Q.How did the Company arrive at the split
23 between demand and energy for sub-account 555. 2?
24 A.Prior to July L983, each cogeneration and
25 small power production agreement contained both a capacity
TATUM, DI-REB 14
Idaho Power Company
1 and energy payment component.The Commission's Order No.
2 l8l90, issued July 2l, 1983, directed the Company to
3 restructure its cogeneration and small power project rates
4 to include only an energy-based component.The demand-
5 related dollar value booked to Account 555.2 represents the
6 sum of the fixed capacity payments agreed to under the
7 active contracts executed prior to the issuance of Order No.
8 18190, with the remainder of sub-account 555.2 being
9 classified as energy.
10 Q.Do you believe the recommendations of Dr.
LL Goins and Dr. Reading to classify a larger share of the
12 Company's Purchased Power expenses booked to FERC Account
13 555 as demand warrant further exploration?
14 A.Yes. As Dr. Goins correctly points out on
15 page L6 of his testimony, the Company's purchased power
16 expenses have grown in recent years to represent a larger
17 share of the overall revenue requirement. This growth in
18 purchase power expenses has occurred as market purchases and
19 PURPA proj ects have become further integrated into the
20 Company's system. With that in mind, it seems appropriate
2L to reevaluate the classification method for the FERC Account
22 555.
23 Q.If the Commission desires to explore further
24 the cost-of-service issues raised in this proceeding, is the
25 Company prepared to facilitate such an investigation?
TATUM, DI-REB 15
Idaho Power Company
1 A.Yes. If directed by the Commission, the
2 Company is prepared to convene a workshop where interested
3 parties to this case can discuss and evaluate potential
4 revisions to the cost-of-service methodology.
5 Q.Does this conclude your direct rebuttal
6 testimony?
7 A.Yes, it does.
TATUM, DI-REB l6
Idaho Power Company