20070611Tatum Direct Part I.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE STATEOF IDAHO.
IDAHO POWER COMPANY
DIRECT TESTIMONY
TIMOTHY TATUM
CASE NO. IPC-O7-
.. - ~.. (,, -..-
Please state your name and business address.
My name is Timothy E. Tatum and my business
address is 1221 West Idaho Street, Boise, Idaho.
By whom are you employed and in what capacity?
I am employed by Idaho Power Company (Company)
as a Senior Pricing Analyst in the pricing and Regulatory
Services Department.
Please describe your educational background.
I received a Bachelor of Business
Administration degree in Economics from Boise State University
in 2001.In 2005, I earned a Master of Business
Administration degree from Boise State University.I have
also attended electric utility ratemaking courses including
Practical Skills For The Changing Electrical Industry" a
course offered through New Mexico State University s Center
For Public Utilities,Introduction to Rate Design and Cost of
Service Concepts and Techniques " presented by Electric
Utili ties Consultants, Inc. and Edison Electric Institute
Electric Rates Advanced Course.
Please describe your work experience with Idaho
Power Company.
I became employed by Idaho Power Company in
1996 as a Customer Service Representative in the Company
Customer Service Center.Over the first two years I handled
customer phone calls and other customer-related transactions.
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In 1999 , I began working in the Customer Account Management
Center where I was responsible for customer account
maintenance in the areas of billing and metering.
In June of 2003, after seven years in customer
service, I began working as an Economic Analyst on the Energy
Efficiency Team.As an Economic Analyst, I maintained proper
accounting for Demand-Side Management (DSM) expenditures,
prepared and reported DSM program accounting and acti vi ty to
management and various external stakeholders, conducted cost-
benefi t analyses of DSM programs , and provided DSM analysis
support for the Company s 2004 Integrated Resource Plan (IRP).
In August of 2004, I accepted a position as a
pricing Analyst in Pricing and Regulatory Services.As a
pricing Analyst, I provided support for the Company s various
regulatory activities including tariff administration,
regulatory ratemaking and compliance filings, and the
development of various pricing strategies and policies.
In August of 2006, I was promoted to Senior Pricing
Analyst. As a Senior pricing Analyst my responsibilities have
expanded to include the development of complex financial
studies to determine revenue recovery and pricing strategies.
What is the scope of your testimony in this
proceeding?
My testimony will address the Company s class
cost-of-service studies.
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How many cost-of-service studies have you
prepared as part of this general rate case proceeding?
I have prepared four cost-of-service studies
that I will describe in greater detail later in my testimony.
Please describe in general terms the process
used to prepare the class cost-of-service studies.
There are two general steps used in preparing a
class cost-of - service study.The first step is to determine
the total costs of providing electric service, adj usted for
normal weather and water conditions.These costs have been
provided to me by Ms. Schwendiman on Exhibit No.2 9 .The next
step is to establish a methodology for the separation of those
costs among customer classes.
What methodology is used to separate costs
among customer classes?
The methodology for separating costs among
classes consists of a three-step process generally referred to
as classification , functionalization, and allocation.In all
three steps, recognition is given to the way in which the
costs are incurred by relating these costs to the way in which
the utility is operated to provide electrical service.
Please explain the meaning of classification.
Classification refers to the identification of
a cost as being either customer-related , demand-related, or
energy-related.These three cost components are used to
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reflect the fact that an electric utility makes service
available to customers on a continuous basis, provides as much
service, or capacity, as the customer desires at any point in
time, and supplies energy, which provides the customer the
abili ty to do useful work over an extended period of time.
These three concepts of availability, capacity and energy are
related to the three components of cost designated as
customer, demand and energy components, respectively. In order
to classify a particular cost by component, primary attention
is given to whether the cost varies as a result of changes in
the number of customers, changes in demand imposed by the
customers, or changes in energy used by the customers.
What are some examples of customer-, demand-
and energy-related costs?
Examples of customer-related costs are the
plant investments and expenses that are associated with meters
and service drops, meter reading, billing and collection, and
customer information and services as well as a portion of the
investment in the distribution system.These investments and
expenses are made and incurred based on the number of
customers, regardless of the amount of energy used, and are
therefore generally considered to be fixed costs.Demand -
related costs are investments in generation, transmission , and
a portion of the distribution plant and the associated
operation and maintenance expenses necessary to accommodate
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the maximum demand imposed on the Company s system.Energy-
related costs are generally the variable costs associated with
the operation of the generating plants, such as fuel.
However, due to the hydro production capability of the
Company, a portion of the hydro and thermal generating plant
investment has historically been classified as energy-related.
What did you use as your primary guide in
classifying costs as either customer-, demand-, or energy-
related?
I used the Electric Utility Cost Allocation
Manual published by the National Association of Regulatory
utility Commissioners as my primary guide to the
classification of customer-, demand-, and energy-related
costs.
Please explain the meaning of
functionalization.
In addition to classification , costs must be
functionalized; that is, identified with utility operating
functions. Operating functions recognize the different roles
played by the various facilities in the electric utility
system. In the Company s accounts these various roles are
already recognized to some degree , particularly in the
recording of plant costs as production-, transmission-, or
distribution-related. However , this functional breakdown is
not in sufficient detail for cost-of-service purposes.
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Individual plant items are examined and, where possible, the
associated investment costs are assigned to one or more
operating functions so that the costs may be allocated among
classes of customers.
Please explain the process of allocation.
The process of allocation is merely one of
apportioning the total jurisdictional cost among classes by
introducing allocation factors into the process. An allocation
factor is nothing more than an array of numbers which
specifies the class value or share of a total jurisdictional
quantity.
Once individual costs have been allocated to
the various classes of service, it is possible to total these
costs as allocated and arrive at a breakdown of utility rate
base and expenses by class. The results are stated in a
summary form to measure adequacy of revenues for each class.
The measure of adequacy is typically the rate of return earned
on rate base compared to the requested rate of return.
Has the overall design of the class cost-of-
service model remained unchanged since the Company s last
general rate proceeding?
Yes. Aside from changes to some of the
allocation factor inputs to the model , which I describe later
in my testimony, the overall design of the model remains
unchanged since the last rate case proceeding.
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Please provide a general overview of the class
cost-of-service model.
The class cost-of-service model is comprised of
two separate Microsoft Excel workbooks. The first workbook,
called the Assign Module, performs the functionalization and
classification processes I described earlier.This workbook
categorizes the Idaho jurisdictional costs identified by FERC
account into operating functions, such as production,
transmission, distribution , metering, customer service, etc.
It also categorizes the functional costs into demand-, energy-
and customer-related classifications.For example , the Assign
Module categorizes the Company s investment in steam plant
into the production function and the demand- and energy-
related classifications.
The second workbook, called the Functionalized
Cost Module , or FC Module for short, performs the class
allocation process.This module allocates the functionalized
and classified costs developed in the Assign Module to the
various customer classes.For example, the FC Module
allocates the demand- and energy-related production costs
identified in the Assign Module to each of the Company
customer classes and special contract customers.Each of the
maj or operations performed by this module are shown as
separate worksheets to make the allocation process transparent
and easy to understand.
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In the Company s last general rate case
proceeding, Case No. IPC-05-28, changes were made to the
methodology used to prepare the study. will you please review
the nature of those changes?
In Order No. 29505 issued in the Company s 2003
general rate proceeding, Case No. IPC-E- 03 -13, the Commission
opened Case No. IPC-04-23 for the purpose of evaluating
cost-of-service issues raised during that general rate
proceeding.Three "cost-of-service " workshops were held with
interested parties between November 2004 and February 2005.
During the workshop discussions, Idaho Power committed to
revise the methodology used to convert billing period data to
calendar month data and to prepare two cost-of-service studies
as part of its next general rate case filing, one using a
surrogate for a demand normalization methodology and one using
the traditional methodology. Idaho Power fulfilled that
commitment in its last general rate case proceeding, Case No.
IPC-05-28.
Was the "workshop methodology " for converting
billing period data to calendar month data also used in the
current rate case proceeding?
Yes. Customers are billed throughout each month
and billing periods, or cycles , typically include portions of
more than one calendar month.Prior to the last rate case
proceeding, billing period data was converted into calendar
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month data using a simple linear interpolation.Daily
consumption during the billing period was assumed to be flat
and weather effects were ignored.The aggregate calendar
month data was then used in the determination of the
coincident peak demands for each customer class.
Under the new "workshop methodology , billing
period data is now converted into calendar month data using a
nonlinear method based on load research data that utilizes
actual daily usage patterns.Total daily consumption is
assumed to fluctuate in proportion to the fluctuations in the
daily consumption of the load research sample customers.This
methodology captures the effects of weather on energy
consumption and improves the process of determining coincident
peak demand responsibility.
In the Company s last general rate case
proceeding, two cost-of -service studies were prepared, one
using a surrogate demand normalization methodology and one
using the traditional methodology. Has the Company selected a
preferred method for determining the class coincident peak
demands for use in this case?
Yes. After evaluating the two approaches for
determining the class coincident peak demands, Idaho Power
Load Research Department has recommended the surrogate demand
normalization methodology as the preferred approach. This
normalized" approach serves to mitigate the impact of unusual
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weather conditions that may exist in a test year.
Please describe the methodology Idaho Power
employed in determining normalized coincident peak demands as
part of this proceeding.
The surrogate demand normalization methodology
uses the five-year median demand ratios from the load research
sample applied to the normalized monthly energy values for
each customer class to determine the coincident peak demands
by class.This methodology reduces the effect of any atypical
demand ratios that might exist ln a given test year due to
unusual weather conditions.
Have you incorporated any changes into the
cost-of-service methodology to address growth on the Company
system?
Yes. In an effort to recognize the Company
increased investment in generation resources necessary to meet
the summer peak load , two of the four cost-of-service studies
prepared as part of this proceeding allocate production plant
costs based on the nature of the load being served.Under
this new approach, production plant costs associated with
serving summer peak load are allocated separately from costs
associated with serving the base and intermediate load. That
, the costs associated with building and operating
combustion turbines, which are used primarily to serve summer
peak loads, have been allocated to customers differently than
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the costs associated with the Company s other generation
resources.
For the two cost-of-service scenarios that
allocate production plant costs on a segmented basis, how did
you arrive at the two cost categories of base/intermediate and
peak?
This new production cost allocation method is
based on the concept that the costs associated with each of
the Company s generation resources can be categorized
according to the type of loads being served. Currently, Idaho
Power has three distinct time-based production costing periods
that are driven by customer loads. The costing periods are
base, intermediate and peak. The base period is equivalent to
a low load or off-peak time period where loads are at the
lowest, normally during the nighttime hours. The intermediate
time period represents the shoulder hours which are driven by
the mid-peak loads that typically occur throughout the winter
daytime and in the early morning and late evening during the
summer months. The peak category is driven by the peak loads
that occur during summer afternoons and evenings. Since the
same generation resources are typically utilized to serve both
the base and intermediate loads, those two categories have
been combined for cost allocation purposes. The generation
resources that serve the peak loads, i. e., combustion
turbines, are normally only utilized for that single purpose.
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Consistent with that concept , the costs associated with peak-
related resources have been segmented into a second category
for cost allocation purposes.
Please explain how production plant costs have
been classified as serving base and intermediate load.
The production plant costs that have been
classified as serving base and intermediate load are captured
in Accounts 310-316, Steam Production, and Accounts 330-336,
Hydraulic Production. The costs identified under the Steam
production category represent the Company s investment in the
coal-fired generation facilities. The costs identified under
the Hydraulic production category represent the Company
investment in its hydro-electric generation facilities.
How do you propose to identify the fixed
generation costs associated with serving the peak load?
Accounts 340-346 , Other Production , contain the
Company s investment in gas-fueled production plant. The
production plant investment captured in Accounts 340-346
represents the Company s investment in the combustion turbine
generation facilities used to serve peak demands.
Have you attempted to identify any other
production plant used to serve summer peak demands that is not
booked to Accounts 340-346?
No. While the Company s hydro facilities are
often managed to serve the peak hours, I have not allocated
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any portion of the hydro plant investment as summer peak-
related. I have simply identified the investment in combustion
turbine generation resources that were constructed
specifically to meet the summer peak loads.
Do the proposed changes to the cost-of-service
methodology focus solely on the allocation of generation
costs?
Yes. In recent years, the Company s system peak
has grown at a much faster pace than average demand. With a
comparison of Figures 4 -1 and 4 - 2 on pages 39 and 40 of the
2006 IRP , which I have included in my workpapers, it is clear
that this trend is expected to continue into the future. In
response to the changing system load profile, combustion
turbines have been added as a cost-effective means to serve
peak load. Thi~ shift in resource mix has caused the Company
to investigate alternative methods for allocating generation
costs.
The Company s investment in transmission and
distribution facilities has also grown in recent years. Is
there not a need to adjust the allocation method for those
functional categories?
No. The Company s historical approach to cost
allocation for transmission and distribution facilities is an
effective method for equitably assigning costs to customer
classes during periods of growth. Under the historical
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allocation method, transmission and distribution costs are
properly segmented according to the manner in which the costs
are imposed on the system. As a result, the cost
responsibility of each class can be effectively identified
through a combination of direct cost assignment and cost
allocation based on the appropriate demand- or customer-based
factors.
How does the new allocation approach differ
from the methodology used in prior rate case proceedings?
Historically, Idaho Power has allocated all
fixed generation costs based on the average of the twelve
monthly coincident peaks weighted by the monthly marginal
generation cost. This historical approach has attempted to
incorporate a forward-looking component into the current costs
through the use of marginal cost weighting. This method has
been effective in allocating costs to customer classes based
on peak demand during the higher cost months. However , there
is potential to disproportionately allocate fixed base and
intermediate generation costs that do not vary greatly between
the summer and non-summer seasons to the higher cost summer
months.
To address this issue, I have prepared two similar
studies that allocate fixed generation costs associated with
serving peak load using an average of the three coincident
peak demands (3 CP) occurring in June, July, and August. The
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two "3 CP" studies are identical with the exception of the
allocation of production plant costs associated with serving
base and intermediate load. The first study, called the "
CP/12 CP" method , allocates production plant costs associated
with serving base and intermediate load using an average of 12
monthly coincident demands (12 CP), without marginal cost
weighting. The second study, called the "3 CP/Average Energy
method, allocates production plant costs associated with
servlng base and intermediate load using an un-weighted
average energy approach. Each of these new allocation methods
isolates the costs associated with peaking resources and
allocates the costs according to the load that is causing the
investment.
Have you incorporated any changes to the
methodology used to determine allocation factors for energy-
related costs in the current studies?
No. The energy-related allocators continue to
be derived using the marginal cost weighting approach used in
prior rate case proceedings. However , for comparative
purposes, a cost-of-service scenario has been prepared using
non-weighted demand and energy allocators.
Please describe the four cost-of-service
studies submitted as part of this proceeding.
The four separate cost-of-service studies
submitted as part of this rate case proceeding include a "Base
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Case"study consistent with the "Normalized" method filed in
the last rate case proceeding,as well as a parallel study
addition,
using "Non-Weighted" demand and energy allocators.
I have prepared the "3 CP/12 CP" and "3 CP/Average
Energy cost-of-service studies using the methods I described
on Exhibit No.
earlier. All of the studies use the cost information as shown
29,provided by Ms.Schwendiman.Each of the
studies are identical with the exception of the demand-related
allocation factors for production and transmission plant and
the energy-related allocation factors.
an illustration of the general similarities and differences
The following table is
between the four studies:
FunctionalCate Base CaseStu 3 CPj12 CPStu 3 CPjAverage
Energy Study
Non-WeightedStu
Generation
Demand
Base andIntermediate
Load
12 CP withMarginalGeneration
Cost Weighting
Peak Load
12 CP withMarginalGeneration
Cost Weighting
12 CP withoutMarginalGeneration
Cost Weighting
12 CP withoutMarginalGeneration
Cost Weighting
12 CP withoutMarginalGeneration
Cost Weighting
12 Months
Average EnergywithoutMarginal
Energy CostWeighting
3 CP withoutMarginalGeneration
Cost Weighting
3 CP withoutMarginalGeneration
Cost Weighting
GenerationEnergy 12 Months
Average Energy
with Marginal
Energy CostWeighting
12 Months
Average EnergywithoutMarginal
Energy CostWeighting
Same as Base
Case
Same as BaseCase
Transmiss ion
12 CP withMarginalTransmission
Cost Weighting
12 CP withoutMarginalTransmission
Cost Weighting
Same as BaseCase Same as BaseCase
Distribution
1 NCP j No. ofCustomers jDirectAssignment
Same as BaseCase Same as BaseCase Same as BaseCase
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Do you plan to cover each of the four cost-of-
service studies in equal detail as part of your testimony?
No. Since all four studies are exactly the same
with the exception of the derivation of the D10, D13 and E10
allocation factors , I will cover the Base Case study in
greater detail and simply describe how the other studies
differ from the Base Case.
Please identify the exhibits that comprise the
Base Case " cost-of - service study.
The Base Case cost-of-service study is
comprised of the following exhibits:
Exhibi t Description
Exhibit No. 41 Functionalization and Classification
of Costs
Exhibit No.
Exhibit No.
Exhibit No.
Exhibit No.
Exhibit No.
Exhibit No.Development of Weighted Demand and
Summary of Functionalized Costs
Allocation to Classes
Summary of Class Allocations
Revenue Requirement Summary
Class Cost-of-Service Unit Costs
Energy Allocators
please describe Exhibit No. 41.
Exhibit No. 41 contains 115 pages and consists
of 11 Cost Functionalization and Classification Tables. The
functionalization and classification of each component of rate
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base, operating revenue and expense are treated in detail in
these tables.The tables are shown in the following sequence:
Table No.Description
Electric Plant in Service
Accumulated Provision for Depreciation
Addi tions and Deletions to Rate Base
Operating Revenues
Operation and Maintenance Expenses
Depreciation and Amortization Expense
Taxes Other Than Income Taxes
Regulatory Debits/Credits
Income Taxes
Development of Labor-Related Allocator
Functionalization Allocators
What is the significance of the column headed
Allocator
" ?
This column identifies, by symbol , the basis
for each allocation. For example, for Accounts 310 through
316 , Steam Production , shown at line 20 on page 1, the
constant "PI-S" is used to allocate the total investment in
steam production plant to the production function and to the
demand and energy cost classifications.The resultant
functionalization of costs may itself serve as a basis for
subsequent allocations.This use is illustrated at line 115
on page 16 where the accumulated depreciation for steam
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production plant is allocated by the functionalization of
costs at line 20.
Please describe the classification of plant
utilized in the class cost-of-service study.
In the class cost-of-service study all steam
and hydro production plant has been classified on a demand and
energy basis using the methodology found preferable by the
Commission in prior general rate proceedings. The energy
portion of the steam and hydro production investment has been
determined by use of the Idaho jurisdictional load factor of
The computation of the Idaho jurisdictional58.53 percent.
load factor is included in my workpapers.By application of
the load factor ratio to the steam and hydro production plant
investment, the energy-related portion is easily determined.
The balance of the steam and hydro production plant investment
is then classified as demand-related.All other production
plant and transmission plant has been classified as demand-
related.
Would you describe how distribution plant has
been classified?
Distribution substation plant, Accounts 360,
361 , and 362 , has been classified as demand-related.
Distribution plant Accounts 364 , 365, 366, 367 and 368 were
classified as either demand-related or customer-related using
the same fixed and variable ratio computation method utilized
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in the Company s prior general rate case proceedings. The
fixed to variable ratio has been updated according to a system
capacity utilization measurement based on a three-year average
(2004-2006) load duration curve that is detailed in my
workpapers.
Would you please describe the functionalization
of general plant?
General plant was functionalized based on total
production, transmission , and distribution plant. As a result
a portion of general plant was assigned to each production
transmission , and distribution function based on each
function s proportion to the total.
How was the accumulated provision for
depreciation functionalized?
The accumulated provision for depreciation was
functionalized using the resulting functionalization of costs
for the appropriate plant item.For example , the accumulated
depreciation for steam production plant shown at line 115 on
page 16 is functionalized based on the functionalization of
steam production plant in service at line 20.
Please describe Table 3 of Exhibit No. 41.
Table 3 indicates the functionalization of all
other additions to and deductions from rate base.Deductions
from rate base include customer advances for construction and
accumulated deferred income taxes.Customer advances have
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been functionalized based on the distribution plant investment
against which the advances apply.Accumulated deferred taxes
have been functionalized based on total plant investment.
Additions to rate base consist of fuel inventory, which has
been functionalized based on energy production, and materials
and supplies, which have been functionalized based on the
appropriate plant function.Deferred conservation expenses
have been functionalized based on the Idaho jurisdictional
load factor resulting in 58.53 percent of the deferred
expenses being functionalized to energy production and the
remainder being functionalized to demand production.
Please describe the functionalization of other
operating revenue shown on Table 4 of Exhibit No. 41.
Other operating revenue is functionalized based
on either the functionalization of the related rate base item
or, in the situation where a particular revenue item may be
identified with a specific service , the functionalization of
the specific service item.
Briefly describe the method by which operation
and maintenance expenses were functionalized.
The functionalization of operation and
maintenance expenses is detailed on Table 5 of Exhibit No. 41.
In general, the basis for the functionalization may be readily
interpreted from the exhibit, particularly since in most cases
the functionalization is the same as that for the associated
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plant.
How is supervision and engineering expense
treated throughout the allocation of operation and maintenance
expenses?
For each applicable expense account in each
functional group, the labor component is separately
functionalized in accordance with the detail provided on Table
10 of Exhibit No. 41. Referring to pages 91 through 105 of
Table 10, it can be seen that the total of allocated labor in
each functional group becomes the basis for the
functionalization of supervision and engineering expense. For
example , for Account 535 at line 675 , the labor-related
supervision and engineering expense is functionalized based on
lines 676-680 which represent the cumulative labor as
functionalized for Accounts 536 through 540 shown on page 91
of Exhibit No. 41. In a similar fashion, the allocation of
supervision and engineering associated with hydraulic
maintenance expense , Account 541 , is based on the composite
labor expense for Accounts 542 through 545, as expressed by
lines 683-686.Total functionalized labor expense serves the
additional purpose of functionalizing employee pensions and
other labor-related taxes and expenses. Table 10 details the
development of all labor-related functionalization factors
used in this study.
Please describe the functionalization of
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depreciation expense, taxes other than income, and income
taxes shown on Tables 6 , 7, 8 and 9 , respectively.
Depreciation expense is functionalized based on
the function of the associated plant.Taxes other than income
are also functionalized based on the function of the source of
the tax. Deferred income taxes are functionalized based on
plant investment.The functionalization of federal and state
income taxes is based on the functionalization of total rate
base and expenses and is discussed in more detail in my
testimony regarding the allocation of costs to classes of
customers.
Please describe Exhibit No. 42.
Exhibit No. 42 summarizes in row format the
functionalized costs for each component of rate base and
expenses shown across the columns on Exhibit No. 41.
Please describe Exhibit No. 43.
Exhibit No. 43 details the allocation of the
summarized costs shown on Exhibit No. 42 to each class of
customer including the special contract customers.The
exhibit also includes a summary of results showing the actual
rate of return earned for each customer class and special
The exhibit includes the following tables:contract customer.
Table No.Description
Plant in Service
Accumulated Reserve for Depreciation
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Amortization Reserve
Substation CIAC
Customer Advances for Construction
Accumulated Deferred Income Taxes
Acquisition Adjustment
Working Capital
Deferred Programs
Subsidiary Rate Base
Plant Held For Future Use
Other Revenues
Operation & Maintenance Expenses
Depreciation Expense
Amortization of Limited Term Plant
Taxes Other Than Income
Regulatory Debits/Credits
provisions for Deferred Income Taxes
Investment Tax Credit Adjustment
State Income Taxes
Federal Income Taxes
Allocation Factor Summary
allocated the summarized costs shown on Exhibit No. 42 to each
Briefly describe the manner in which you
class of service as shown on Tables 1 through 21 of Exhibit
No. 43.
The demand-related generation and transmission
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costs have been allocated to customer classes based on a
methodology that incorporates both actual and marginal-cost-
weighted coincident peak demands.The energy-related
generation costs have been allocated to customer classes based
on a methodology that incorporates both actual and marginal-
cost-weighted normalized monthly energy consumption.
What is the reasoning for using marginal cost
weightings in the derivation of the demand- and energy-related
allocation factors?
The use of marginal cost weighting is intended
to strike a balance between backward-looking costs already
incurred and forward-looking costs to be incurred in the
future. This approach inj ects into the allocation process
recognition of the influence seasonal load profiles have on
cost causation.
Please describe the methodology used to derive
the demand-related allocation factors used to allocate
generation costs in the Base Case Study.
The demand-related factors used to allocate
generation costs were derived using the same methodology as
that used in the Company s previous two general rate cases,
Cases No. IPC-03-13 and Case No. IPC-05-28.First, ratios
based on the sum of the actual coincident peak demands for
both the summer and non-summer seasons were calculated for
each customer class.Second , weighted coincident peak demand
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values were derived by multiplying the actual monthly
coincident peak demands by the monthly marginal costs.
Corresponding ratios for both the summer and non-summer
seasons were then calculated for each customer class. Finally,
the actual summer and non- summer ratios were averaged with the
weighted summer and non-summer ratios to derive the demand-
related allocators D10S and D10NS, respectively.These
factors where used to allocate demand-related generation costs
to the customer classes.
Have the generation capacity marginal costs
used in the current study been updated since the Company
previous study in Case No. IPC-05-28?
The generation capacity marginal costsYes.
have been updated to reflect the costs associated with the
marginal peaking resource identified in the Company s 2006
Integrated Resource Plan, or IRP.The generation capacity
marginal cost was seasonalized based on the monthly peak-hour
generation deficiencies which the Company expects to encounter
during the next five years of the planning period based on the
U percentile water and 70u percentile load criteria used for
planning purposes.These deficiencies are detailed on page 78
of the 2006 IRP Technical Appendix.I have included a copy of
this page in my workpapers.During the first five years (2007
through 2011) of the remaining planning period covered by the
IRP , the months in which peak-hour deficits exist are May,
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Idaho Power Company
June, July, August, September, and December.The relative
sizes of the five-year average monthly deficiencies were used
to define the share of the annual capacity cost assigned to
each month.
How were the demand-related transmission
marginal costs determined?
The transmission marginal costs reflect the
costs associated both with the backbone segment of
transmission required to integrate new resources into the
system and with the planned system expansions needed to
maintain reliable service as the Company s loads continue to
The marginal costs associated with the backbone systemgrow.
were seasonalized based on the same methodology used for
generation capacity, that is the relative sizes of the five-
year average monthly peak-hour deficiencies identified in the
2006 IRP were used to define the share of the annual capacity
cost assigned to each month.The marginal costs associated
with the planned system expansions were seasonalized based on
the monthly share of the proj ected peak-hour load growth.The
total demand-related transmission marginal costs for each
month were then derived by adding the monthly values for both
the backbone system and the planned system expansions.
What factor was used to allocate transmission
costs to the customer classes?
The allocation factor D13 was used to allocate
TATUM DI
Idaho Power Company
transmission costs to customer classes.This factor was
derived using the same methodology as that used in the
Company s previous general rate case.First , ratios based on
the sum of the actual coincident peak demands were calculated
for each customer class.Second, weighted coincident peak
demand values were derived by multiplying the actual monthly
coincident peak demands by the monthly transmission marginal
Corresponding weighted ratios were then calculated forcosts.
each customer class.Finally, the actual ratios were averaged
with the weighted ratios to derive the non-seasonalized
transmission allocation factor D13.
Please describe the methodology used to derive
the energy-related allocation factors.
The energy-related allocation factors, E10S and
E10NS, were derived through a three-step process.First,
summer and non-summer ratios based on each class
proportionate share of the total normalized energy usage for
the test year were determined.Next, summer and non- summer
ratios based on the monthly normalized energy usage for each
customer class weighted by the monthly marginal cost were
calculated.Finally, the two sets of ratios were averaged to
derive the summer and non-summer energy-related allocation
factors E10S and E10NS, respectively. This is the same method
used to derive the E10S and E10NS allocators in Case No. IPC-
05-28.
TATUM DI
Idaho Power Company
Have the generation energy marginal costs used
in the current study to derive the E10S and E10NS allocation
factors been updated since the Company s previous study in
Case No. IPC-05-28?
Updated marginal energy costs wereYes.
calculated by quantifying the difference in net power supply
costs resulting from the addition of 50 megawatts of load to
all hours of the Company s base case system simulation run for
the five-year period 2007 through 2011.
Have you included information regarding the
derivation of the Company s updated marginal costs with your
testimony?
Yes. I have included a copy of the Company
2007 Marginal Cost Analysis in my workpapers.
Have you prepared an exhibit that details the
derivation of the weighted demand and energy allocation
factors?
Exhibit No. 47 details the derivation ofYes.
the allocation factors D10S, D10NS, D13, E10S, and E10NS used
in the Base Case study.
Have the marginal costs been used to develop
the Company s revenue requirement?
No. The marginal costs have been used solely
for purposes of developing allocation factors and not for
purposes of developing the Company s revenue requirement.
TATUM DI
Idaho Power Company
What was the method by which you allocated
costs associated with distribution plant included on Exhibit
No. 42 to each class of customers?
The allocation of the capacity components of
distribution plant , both primary and secondary, was by use of
the non-coincident group peak demands for each customer class
identified as demand allocation factors D20, D30, D50 , and
D60. The allocation of the customer components of distribution
plant, both primary and secondary, was by use of the average
number of customers identified as customer allocation factors
C20, C30, C50 and C60.
What was the method by which you allocated
costs associated with customer accounting and customer
assistance expenses?
The principal customer accounting expenses
which require allocation are meter reading expenses, customer
records and collections, and uncollectible accounts.The
meter reading and customer records and collection expenses
were allocated based upon a review of actual practices of
Idaho Power Company in reading meters and preparing monthly
bills. The allocation of uncollectible amounts again was based
upon a review of actual Idaho Power Company data.Cus tomer
assistance expenses were allocated based on the average number
of customers in each class.
Does Exhibit No. 43 include a listing of the
TATUM DI
Idaho Power Company
allocation factors used to allocate to classes the various
costs shown on Tables 1 through 21?
Table 22 of Exhibit No. 43 includes aYes.
listing of each allocation factor.
How did you allocate state and federal income
tax to each customer class and special contract customer as
shown on Tables 20 and 21 of Exhibit No. 43?
The state and federal income taxes for the
Idaho jurisdiction , provided by Ms. Schwendiman , were
allocated to each customer class and special contract customer
according to each class s allocated share of rate base.The
worksheets showing this allocation are included in my
workpapers .
What method was used to functionalize the state
and federal income taxes as shown on Table 20 and Table 21 of
Exhibit No. 43?
Once the state and federal income taxes were
allocated to each customer class, they were functionalized
based on the functionalization of total rate base and expenses
for each class.For example , the total summer power supply
production rate base amount of $60,681 160 allocated to the
residential class on Tables 1 through 10 of Exhibit No. 43,
and shown in summary form on page 1 of Exhibit No. 44 at line
10, represents 7.33 percent of the total rate base amount of
$827 606,274 allocated to the residential class.The state
TATUM DI
Idaho Power Company
and federal income taxes allocated to the residential class
($1 252 514 and $20 552 493, respectively) are multiplied by
this same percent to establish the summer power supply
production components of $91 836 and $1 506,935 shown on Table
20 and Table 21 of Exhibit No. 43.This same methodology is
used for all functional components and customer classes shown
on Tables 20 and 21.
Please describe Exhibit No.4 5 .
summary based
service study.
Exhibit No. 45 is the revenue requirement
on the results of the Base Case class cost-of-
The section headed "Revenue Requirement for
Rate Design" details the sales revenue required from each
customer class and special contract customer. The sales
revenue required includes return on rate base, total operating
expenses, and incremental taxes computed using the net-to-
gross multiplier of 1.642 provided to me by Ms. Schwendiman.
Please describe Exhibit No.4 6.
Exhibi t No.4 6 shows the unit cost for each
function for metered service schedules as determined through
the Base Case class cost-of -service study.The billing units
shown in the column labeled (E) reflect the billing demands,
normalized billing energy, basic load capacity, and number of
billings.
Please describe how the "Non-Weighted" study
scenario differs from the Base Case study.
TATUM DI
Idaho Power Company
The Non-Weighted scenario is identical to the
Base Case study with the exception that the demand and energy
allocators - D10S, D10NS, D13 , E10S, and E10NS - were not
weighted by marginal costs.Under this scenario, the demand
and energy allocators were determined using the actual test
year system coincident peak demands and the normalized energy.
The Summary of Revenue Requirement for this scenario, which
details the revenue requirement for each customer class, is
included as Exhibit No. 48.
How do the results from the Non-Weighted study
in which no marginal cost weightings are used compare with the
results from the Base Case study?
The use of demand and energy allocators that do
not include a marginal cost weighting result in a lower
revenue requirement for Small General service, Dusk-to-Dawn
Customer Lighting and Irrigation Service and a higher revenue
requirement for all other customer classes, including the
special contract customers , than does the use of the
traditional marginal-cost-weighted demand and energy
allocators used in the Base Case.
As you mentioned earlier in your testimony, the
3 CP/12 CP" study applies a different approach to allocating
production plant costs than does the Base Case. Have you
prepared any exhibits that detail the 3 CP/12 CP cost-of-
service study?
TATUM DI
Idaho Power Company
Yes. The 3 CP/12 CP cost-of-service study is
comprised of the following exhibits:
Exhibi t Description
Exhibit No. 49 Functionalization and Classification
of Costs
Exhibit No. 50 Summary of Functionalized Costs
Exhibit No. 51 Allocation to Classes
Exhibit No. 52 Summary of Class Allocations
Exhibit No. 53 Revenue Requirement Summary
Exhibit No. 54 Class Cost-of-Service Unit Costs
Exhibit No. 55 Development of Weighted Demand and
Energy Allocators
Please describe how the 3 CP/12 CP study
differs from the Base Case study.
The Base Case and 3 CP/12 CP cost-of-service
studies are identical with the exception of the demand-related
allocation factors for production plant.
What are the demand-related allocation factors
for production plant?
The derivation of the demand and energy
allocators used in the 3 CP/12 CP scenario are shown on
Exhibi t No. 55. In order to avoid confusion among the various
factors used in the model , I have used the names "D10BS" and
D10BNS" to describe the factors used to allocate the
TATUM DI
Idaho Power Company
production plant associated with serving the base and
intermediate loads. The name "D10P" is used to describe the
allocation factor used to allocate the production plant
associated with serving the peak loads.
How were the demand-related allocation factors
for the 3 CP/ 12 CP study derived?
As can be seen in Exhibit No.5 5, the D10BS and
D10BNS represent the non-weighted average twelve coincident
peak demands for the summer and non-summer seasons
respectively. The allocator D10P represents the non-weighted
average three coincident peak demands for the summer months of
June , July and August. The allocators for transmission plant
and the energy allocators are the same as those used in the
Base Case study.
Why did you choose to derive the D10BS, D10BNS
and D10P allocation factors with no marginal cost weighting?
The segmentation of production plant costs into
basel intermediate and peak allows for a cost allocation
approach that recognizes the seasonality of the loads
associated with each category of investment. Therefore , there
is no need for marginal cost weighting since the seasonal
nature of the loads is reflected in the allocation factors.
How does this approach differ from that used
for the Base Case?
Under tne Base Case approach, all production
TATUM DI
Idaho Power Company
plant costs, which include base, intermediate and peak , are
allocated using the same allocation factors, i. e., D10S and
D10NS. In the Base Case , the marginal cost weighting is
applied to provide a seasonal recognition to cost causation
similar to that automatically recognized through the "3 CP"
studies.
How do the results from the 3 CP/12 CP study
compare to the results from the Base Case study?
The results from the 3 CP/12 CP scenario are
shown on Exhibit No. 53. The results from the Base Case study
are shown on Exhibi t No.4 5 .As can be seen from comparing
these two exhibits , the 3 CP/12 CP results indicate a lower
revenue requirement for Small General Service and Irrigation
Service and a slightly higher revenue requirement for all
other service schedules and special contract service than do
the results of the Base Case.
Please describe how the "3 CP/Average Energy
study differs from the Base Case study.
The Base Case and 3 CP/Average Energy cost-of-
service studies are identical with the exception of the
demand-related allocation factors for production plant. Under
the 3 CP/Average Energy study, the production plant costs are
segmented in the same manner as in the 3 CP/12 CP study, that
is, into basel intermediate and peak. The 3 CP /Average Energy
study is also identical to the 3 CP/12 CP study in its method
TATUM DI
Idaho Power Company
of allocating production plant costs associated with serving
the peak loads, i. e., using the D10P allocation factor based
on the non-weighted average of the three coincident summer
peak demands. However , what makes the 3 CP / Average Energy
study different from the other studies is the method used to
allocate the costs associated with serving base and
intermediate loads. Under the 3 CP / Average Energy study, the
base/intermediate-related production costs are allocated using
factors derived from the non-weighted monthly normalized
energy usage for each customer class. These factors are simply
the E10S and E10NS energy-related allocation factors with no
marginal cost weighting applied.
How do the results from the 3 CP/Average Energy
study compare to the results from the Base Case study?
The results from the 3 CP/Average Energy
scenario are shown on Exhibit No. 56.The resul ts from the
Base Case study are shown on Exhibit No. 45.As can be seen
from comparing these two exhibits, the 3 CP/Average Energy
resul ts indicate a lower revenue requirement for Residential
Service, Small General Service and Irrigation Service and a
higher revenue requirement for Large General Service at both
the secondary and primary service levels, Dusk-to-Dawn
Customer Lighting, Large Power Service, Unmetered General
Service, Street Lighting Service, Traffic Control Lighting
Service and DOE, Simplot and Micron special contract service
TATUM DI
Idaho Power Company
than do the resul ts of the Base Case.
Are there any similarities in the results among
the four cost-of-service studies that you have performed as
part of this proceeding?
Although the absolute values areYes.
different , the results from all four studies indicate that the
Small General Service (Schedule 7), Large Power
Service (Schedule 19), Irrigation Service (Schedule 24), Traffic
Control Lighting Service (Schedule 42) and special contract
(Micron , Simplot, and DOE) customers should have an increase
in rates which is greater than the overall average increase
requested by the Company.In addition , the results indicate
that only the Dusk-to-Dawn Customer Lighting Service (Schedule
15) should have a decrease in rates from the current level.
Exhibit No. 57 includes in summary form the results from all
four cost-of-service studies.
After reviewing the results of each study, do
you have a preferred cost-of-service approach?
Yes. The 3CP/12CP study applies my preferred
approach.
Why is the 3 CP/12 CP study your preferred
approach to cost allocation?
Of the four studies, the 3 CP /12 CP approach is
the most effective in allocating production plant costs to
customer classes consistent with the cost impact the class
TATUM DI
Idaho Power Company
loads impose on the utility system. Over the last five years,
Idaho Power has added three combustion turbine generation
units to serve summer peak loads. Since the costs associated
with these new units are driven primarily by summer loads, it
is appropriate to allocate the cost of those new resources
according to each class s contribution to the summer peak
loads. However, production plant costs associated with serving
the base and intermediate loads are driven more by the monthly
peaks throughout the entire year. By separating the production
plant into the two categories, the generation costs can be
allocated according to the most appropriate cost driver.
The 3 CP/Average Energy study also separates
the peak-related production plant from all other production
plant for cost allocation purposes. Why was the 3 CP/12 CP
method selected over the 3CP/Average Energy method as the
preferred approach?
As I mentioned earlier , the only difference
between the 3 CP/12 CP study and the 3 CP/Average Energy study
is the method of allocating production plant costs associated
with serving base and intermediate load. Under the 3CP/Average
Energy method, production plant costs associated with serving
base and intermediate load are allocated based on each
customer class s annual energy consumption. While annual
energy consumption is a primary driver of the need for base-
load generation resources, resource planning and operational
TATUM DI
Idaho Power Company
decisions related to serving intermediate loads are more
capacity driven. Considering that the production plant
investment being allocated serves both base and intermediate
loads, it is more appropriate to allocate those costs based on
12 monthly coincident demands rather than average energy.
Did you discuss all four studies internally
before deciding on your recommendation?
Yes. I arrived at my final recommendation after
discussing the results of each of the four studies with Ms.
Brilz , the Company s Pricing Director. Following that
discussion I provided the class cost-of-service unit costs,
detailed on Exhibit No. 54 , to Ms. Brilz for her use in
determining the component charges for each service schedule.
Does this conclude your testimony?
Yes, it does.
TATUM DI
Idaho Power Company
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