20040415Volume VII Part II.pdf

Please state your name, address, and present
occupa t ion.
Please state you name and business address.
My name is Maggie Brilz.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 as
Director of Pricing.
Please describe your educational background.
In May of 1980 I received Bachelor of Arts
Degrees in Economics and Psychology from Smith College in
Northampton , Massachusetts.In 1998 I completed the
University of Idaho's Public Utilities Executive Course
in Moscow , Idaho.I have also attended numerous seminars
and conferences on pricing issues related to the utility
industry and have attended seminars and courses involving
public utility regulation.
Please describe your business experience with
Idaho Power Company.
I started emploYment with Idaho Power Company
in November of 1984 as a Financial Analyst in the
Planning Department.In 1986 I was promoted to the
position of Rate Analyst in the Rate Department.
duties as a Rate Analyst included the development of
al ternati ve pricing structures
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the analysis of the impact on customers of rate design
changes, the preparation of cost -of - service studies, and
the administration of the Company I s tariffs.In July of
1993 I was promoted to Rate Design Supervisor.In that
capacity I also became responsible for the overall rate
design acti vi ties of the Rate Department. In October of
1996 I was promoted to my current position of Director of
Pricing in the Pricing and Regulatory Services
Department.
What is the scope of your testimony in this
proceeding?
My testimony will address the Company I s class
cost -of - service study and the Company I s rate design
proposals for the tariff and special contract customers.
Class Cost-of-Service Study
Please describe the methodology used to prepare
the class cost -of - service study submitted in this
proceeding.
The class cost-of-service study submitted in
this proceeding uses the Weighted 12 Coincident Peaks
allocation method.This study uses the same methodology
as previously filed by the Company in Case No.
I006-185 , Case No. U-I006-265A , and Case No. IPC-E-94-
and used by the Commission in the allocation of the
revenue requirement among customer classes in those
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cases.
What procedures were used in the preparation
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of the fully distributed or embedded class
cost -of - service study?
There are two general steps used in preparing a
fully distributed or embedded 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.The next step is to establish a
methodology for the separation of those costs among
customer classes.
What total costs of providing electric service
have been allocated to the various customer classes in
the class cost-of-service study?
The total costs of providing electric service
to the Idaho jurisdiction included on Mr. Obenchain '
Exhibit No. 30 have been allocated to the various
classes.
What methodology was used for the separation of
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.
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Please explain the meaning of classification.
Classification refers to the identification of
cost as being either customer-related, demand related , or
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energy-related.These three cost components are used to
reflect the fact that an electric utility is not simply
in the business of selling electric energy, even though
it may sometimes appear to the customer that only energy,
as measured in kilowatt hours, is purchased.In fact,
the customer is also buying the ability to have service
available at any point in time. Secondly, the customer is
buying capacity or the ability to receive as much power
as is required at a point in time. Most power supply
facilities (generation and transmission) generally are
considered to fall into this capacity category. And
finally, the customer is buying energy or the ability 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 use.
What are some examples of customer , demand-
and energy-related costs?
Examples of customer related costs are the
investment in meters , a portion of the investment
associated with distribution facilities , the costs
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associated with meter reading and billing, and the costs
associated with maintaining the availability of service
regardless of whether service is actually taken.
Demand-related costs are investments in generation
transmission , and distribution plant and the associated
operation and maintenance expenses necessary to
accommodate the maximum demand imposed on the Company '
system.Energy-related costs are generally the variable
costs associated with the operation of the generating
plants, such as fuel , although due to the hydro
production capability of the Company, a portion of the
hydro and thermal generating plant investment is usually
classified as energy-related.
Please discuss the approach used to classify
customer-, demand-, and energy-related costs.
The Company has used the Electric Utility Cost
Allocation Manual published by the National Association
of Regulatory Utility Commissioners as its primary guide
to the classification of customer-, demand-, and
energy-related costs.
Please explain the meaning of
funct ional i za t ion.
In addition to classification, costs must be
functionalizedi that is , identified with utility
operating functions. Operating functions recognize the
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different roles played by the various facilities in the
electric utility
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system. In the Company I 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. 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 thus arrive at a breakdown of
utility rate base and income 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.
Have you prepared or supervised the
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preparation of the fully distributed or embedded class
cost-of-service study submitted in this proceeding?
Yes. Using the cost information provided to me
by Mr. Obenchain, I prepared the fully distributed or
embedded class cost -of - service study.This study was
prepared using the Weighted 12 Coincident Peaks
allocation method.It is identified as follows:
Exhibit Description
Exhibit No. 37 Functionalization and
Classification of Costs
Exhibit No. 38 Summary of Functionalized Costs
Exhibit No. 39 Allocation to Classes
Exhibit No. 40 Development of Weighted Demand
and Energy Allocators
Exhibit No. 41 Revenue Requirement Summary
Please describe Exhibit No.3 7.
Exhibit No. 37 contains 115 pages and consists
of 10 Cost Functionalization and Classification Tables.
The functionalization and classification of each
component of rate base, operating revenue and expense is
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
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Additions and Deletions to Rate Base
Operating Revenues
Operation and Maintenance Expenses
Depreciation and Amortization Expense
Taxes Other Than Income Taxes
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
, the constant "PI-S" is used to allocate the total
investment in steam production plant to the appropriate
functions.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 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
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preferable by this 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 55.26 percent.The
computation of the Idaho jurisdictional 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 ratio of the fixed and
variable portions of the Company I s system peak during the
three-year period 2000 through 2003. The fixed portion of
the Company I s system peak was set equal to the
near-minimum , or first percentile, hourly system load
during this three-year period. The variable portion was
set equal to the remaining share of the peak load.
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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 I 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.3 7.
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 been functionalized based on the
distribution plant investment against which the advances
apply.Accumulated deferred taxes have been
functionalized based on total plant investment.
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Additions to rate base consist of materials and supplies,
which have been
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functionalized based on the appropriate plant function
fuel inventory, which has been functionalized based on
energy product ion , and prepaid items, which have been
functionalized based on labor expenses or the appropriate
plant function depending on the type of prepayment.
Deferred conservation expenses have been functionalized
based on the Idaho jurisdictional load factor resulting
in 55.26 percent of the deferred expenses being
functionalized to energy production and the remainder
being functionalized to demand production.
Please describe the functionalization of other
revenue shown on Table 4 of Exhibi t No.3 7 .
Other 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. 37.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 plant.
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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 9 of Exhibit No. 37. Referring to pages 91 through
105 of Table 9 , 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
678 , the labor related supervision and engineering
expense is functionalized based on lines 679-683 which
represent the cumulative labor as functionalized for
Accounts 536 through 540 shown on page 91 of Exhibit No.
37. 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 686-689.Total functionalized labor expense serves
the additional purpose of functionalizing employee
pensions and other labor-related taxes and expenses.
Table 9 details the development of all labor-related
functionalization factors used in this study.
Q. Please describe the functionalization of
depreciation expense, taxes other than income , and income
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taxes shown on Tables 6, 7 , and 8 , 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 total 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.3 8.
Exhibit No. 38 summarizes in row format the
functionalized costs for each component of rate base and
expenses shown across the columns on Exhibit No. 37.
Please describe Exhibit No.3 9.
Exhibit No. 39 details the allocation of the
summarized costs shown on Exhibit No. 38 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 contract customer.The Exhibit includes the
following tables:
Table No.Descript ion
Plant in Service
Accumulated Reserve for Depreciation
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Amortization Reserve
Customer Advances for Construction
Accumulated Deferred Income Taxes
Acquisition Adjustment
Working Capi tal
Deferred Programs
Subsidiary Rate Base
Substation CIAC
Other Revenue
Operation & Maintenance Expenses
Depreciation Expense
Amortization of Limited Term Plant
Taxes Other Than Income
Provision for Deferred Income Taxes
Investment Tax Credit Adj ustment
State Income Tax
Federal Income Tax
Allocation Factor Summary
Briefly describe the manner in which you
allocated the summarized costs shown on Exhibit No. 38 to
each class of service as shown on Tables 1 through 17 of
Exhibit No. 39.
In an effort to weight the monthly
contributions to the total system peak in a fashion which
reflects the marginal costs of the Company I s seasonal
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load requirements, I have allocated demand- related costs
according to a Weighted 12 Coincident Peaks allocation
method.
Is the Weighted 12 Coincident Peaks methodology
used in the current class cost -of - service study the same
methodology used in previous studies filed with the
Commission?
The philosophical approach is the same in that
the methodology is intended to strike a balance between
backward-looking costs already incurred and
forward-looking costs to be incurred in the future.
However , the nature of the Company I s marginal costs has
changed since the early 1990s.As a resul t, the
methodology used to compute the weighted demand-related
allocation factors has been revised slightly.
How has the nature of the Company's marginal
costs changed since the early 1990s?
According to the Company's 2002 Integrated
Resource Plan (IRP), the Company has identified capacity
deficits in the months of June, July, August, November,
and December only.During all other months, no capacity
deficits currently exist.The deficits in the five
months cited above are driving the need for additional
peaking resources.Consequently, the Company faces
capaci ty, or generation-related, marginal costs in only
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five months of the year.During the remaining seven
months , the Company has no current need for additional
resources. Hence there is no generation-related marginal
cost for these seven months. In the early 1990s the
Company I S analysis showed a generation-related marginal
cost for all months of the year except September and
October.
Does the Company I s analysis for
transmission-related marginal costs show the same result
as for generation capacity?
, it shows slightly different results.
Again , according to the Company's 2002 IRP , the Company
currently anticipates transmission deficits during only
the months of June, July, and August.As a result, the
Company faces transmission-related marginal costs during
only these same three months.
What are the weighted allocation factors used
in the cost-of-service study?
The allocation factor DI0 is used to allocate
generation capacity-related costs.The allocation factor
D13 is used to allocate transmission-related costs.The
allocation factor EI0 is used to allocate energy-related
costs.The detail for the development of the weighted
allocation factors can be found on Exhibit No. 40.
How has the Company used the marginal costs to
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determine the Weighted 12 Coincident Peaks allocation
factors?
First, the actual coincident peaks for each
customer class were used to derive actual DI0 and D13
ratios.Second, the actual coincident peaks weighted by
the five monthly marginal costs for generation and the
three monthly marginal costs for transmission were used
to derive weighted DI0 and D13 ratios.Finally, the
average of the actual and weighted DI0 and D13 ratios
were computed for use in allocating costs among customer
classes.
Was the methodology used to compute the
demand-related weighted allocation factors used to
compute the weighted energy-related allocation factors?
No.Because the Company operates its system by
continually balancing energy generation and purchases, it
faces monthly marginal energy costs.Therefore the
methodology used to determine the weighted energy
allocation factors is the same as that used in the
Company' s previous filings.The monthly marginal energy
costs were used to weight the normal i zed monthly energy
usage for each customer class and special contract
customer.I then totaled the resul ts for each customer
class and divided the customer class totals by the
jurisdictional total weighted value to establish the EI0
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ratio for each class.
Were any other changes incorporated into the
derivation of the weighted demand and energy allocation
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factors?
Yes.In order to identify costs by summer and
non-summer seasons to facilitate the Company's rate
design proposals, I calculated weighted factors for both
the summer season, defined as the months of June , July,
and August, and the non-summer season , defined as all
other months.Accordingly, the summer and non-summer
weighted demand allocation factors used for the
allocation of the demand-related portion of production
plant and for the allocation of transmission plant are
designated as DI0S, DI0NS, D13S, and D13NS, respectively.
The summer and non-summer weighted energy allocation
factors are designated as EI0S and EI0NS, respectively.
Have the marginal costs been used to develop
the Company I 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 I s revenue
requirements.
What was the method by which you allocated
costs associated with distribution plant?
The allocation of the capacity components of
distribution plant, both primary and secondary, was by
use of the coincident group peak demands for each
customer class identified as demand allocation factors
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D20, D30 , D50, and D60. The allocation of the customer
components of
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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 related expenses which
require allocation are meter reading expenses, customer
records and collections, uncollectible accounts, and
customer assistance expense. The meter reading and
customer account 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.Customer
assistance expenses were allocated based on the average
number of customers in each class.
Does Exhibit No. 39 include a listing of the
allocation factors used to allocate to classes the
various costs shown on Tables 1 through 17?
Yes.Table 20 of Exhibit No. 39 includes a
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 18 and 19?
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The state and federal income taxes for the
Idaho jurisdiction provided to me by Mr. Obenchain were
allocated to each customer class and special contract
customer on the basis of income before income taxes.The
worksheet showing this allocation is included in my
workpapers.Tables 18 and 19 show the functionalization
of these allocated taxes to each customer class.
What method was used to functionalize the state
and federal income taxes as shown on Table 18 and Table
19 of Exhibit No. 39?
State and federal income taxes 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
$59,945,913 allocated to the residential class on Tables
1 through 10 of Exhibit No. 39 represents 9.33 percent of
the total rate base amount of $642,356,205 allocated to
the residential class.The state and federal income
taxes allocated to the residential class ($783,038 and
$6,799,290 , respectively) are multiplied by this same
percent to establish the summer power supply production
components of $73 075 and $634 523 shown on Table 18 and
Table 19.This same methodology is used for all
functional components and customer classes shown on
Tables 18 and 19.
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Please describe Exhibit No. 41.
Exhibit No. 41 is the revenue requirement
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summary based on the results of the class cost-of-service
study.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
Mr. Obenchain.I have provided the results from this
section to Mr. Gale.Mr. Gale I s testimony addresses the
allocation of revenue requirement among the customer
classes.
Were any adj ustments made to the Company I s data
for any of the customer classes for purposes of the class
cost -of - service study?
Yes.Currently, seven customers receive
service under Schedule 19, Transmission Service level.
After a review of these customers I facilities, it was
determined that the facilities configuration for four of
the seven customers is the same as the facilities
configuration for customers taking service under Schedule
19, Primary Service level.However, these four
customers , unl ike Primary Service level customers, are
currently paying a facilities charge for a portion of the
investment in substation facilities required to provide
service.In order to treat these customers consistently
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Idaho Power Company
with other customers in the same situation , the Company
intends to transfer these
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four customers to Primary Service level and discontinue
the monthly facilities charge on the substation
investment.An adj ustment, as detailed by Mr. Obenchain
in his testimony, has been made to the amount of annual
facilities charge revenue to reflect this change.
Does the Company I s class cost -of - service study
treat each service level on Schedule 9 and Schedule 19 as
a separate customer class?
No, it does not.The three service levels,
Secondary, Primary, and Transmission , available on both
Schedule 9 and Schedule 19 are intended to provide
flexibility in serving customers depending on the
customer I S facility requirements.For example, customers
who own their own substations are served at Transmission
Service level whereas customers who utilize non-dedicated
Company-owned facilities are served at Secondary Service
level.Customers who own their own secondary facilities
or who pay a facilities charge to the Company for use
the dedicated secondary facilities, are served at Primary
Service level.After the adj ustment I just described for
the four Schedule 19 Transmission Service level
customers, only three customers will be served at the
Transmission Service level on Schedule 19.In addition
only one customer is served at Secondary Service level
under Schedule 19.The remaining 100 customers are
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served at Primary Service level.Therefore, for Schedule
19, the Transmission and Secondary customers are combined
with the Primary Service level customers to form a single
customer class for cost allocation purposes.For
Schedule 9, the three Transmission Service level and the
112 Primary Service level customers are combined to form
a single customer class for cost allocation purposes
while the Secondary customers remain separate. This
grouping of the various service levels prevents a very
small group of customers from being treated as a single
customer class.
The Company I s class cost -of - service study
separately identifies contributions in aid of
construction (CIAC) for distribution substations.
this treatment of substation CIAC a departure from past
practices?
Yes.In the past , the Company's class
cost-of-service studies have included only the net amount
of distribution substation investment.Consequently, no
direct recognition of CIAC paYments has historically been
made on a customer class basis.As a result , all
customer classes that were allocated a portion of
distribution substation plant were provided a portion of
the benefit associated with CIAC paYments.
What changes have been made to the current
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class cost -of - service study to address the CIAC issue?
First, rather than using net distribution
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substation investment (Accounts 360 , 361, and 362) as the
amount to be functionalized, classified, and allocated to
classes, as has been the practice in previous studies
the current study uses the "net plus CIAC" distribution
substation investment.Second , I directly assigned to
each customer class the distribution substation CIAC
amount specifically contributed by each class.Thus the
class-specific CIAC contributions were used as direct
offsets to the allocated distribution plant investment
for each customer class in the derivation of net rate
base.This methodology directly attributes the benefit
associated with CIAC paYments to the specific classes
that made the contributions.
Mr. Obenchain referred to an adj ustment made to
treat the monthly Operation & Maintenance (O&M) charges
paid by Micron under its special contract as retail sales
revenue.Would you please explain the rationale for this
adj ustment?
Micron currently pays a monthly O&M charge
based on the total cost of the substation facilities
required to deliver power and energy to its facility.
The Company is proposing to eliminate the separate O&M
charge and incorporate the costs associated with the
substation facil i ties into Micron' s standard charges.
The adj ustment to Micron I s sales revenue was made in
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order to establish an appropriate base revenue amount.
Rate Design
What are the obj ecti ves the Company is striving
to achieve through its rate design proposals?
The Company is striving to achieve two main
obj ecti ves.First, the Company is striving to establish
prices which primarily reflect the costs of the services
provided. Cost-based prices provide customers with clear
signals about the costs of receiving service, reduce
subsidies wi thin customer classes , and result in a more
equi table recovery of the costs of providing service.
Second, the Company is striving to give customers price
signals that reflect the variation in the costs of
providing service during different times of the year and
day.Mr. Gale addresses in his testimony the Company '
policy regarding its pricing obj ecti ves.
How does the Company propose to implement these
objectives?
The Company proposes to implement these
obj ecti ves by pricing the individual rate components
closer to cost , by implementing seasonal pricing for
Schedules 1 , 7 , 9 and 19 , and by implementing time-of -use
pricing for all customers taking service under Schedule
19.
Q. How does the Company plan to price the rate
components closer to cost?
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Historically, the energy charge on metered
service schedules has been set at levels that recover not
only the costs associated with providing energy but also
a portion of the fixed costs associated with delivering
energy and providing customer-related services.The
Company plans to emphasize increases to both the demand
and customer charges so that these components are more
reflective of cost.This plan will result in less
non-energy related costs being recovered through the
energy charge.
Why is the Company proposing seasonal rates for
Schedules 1, 7 , 9, and 19?
The Company faces its highest power supply
costs during the months of June , July, and August.The
Company also faces its highest peak usage during these
same three months.In fact, it is the peak usage during
these three months , along with the usually low hydro
condi tions during the months of November and December,
which are driving the need for the Company to seek new
peaking resources and to emphasize peak reduction in
demand-side management programs utilizing the energy
efficiency rider funds. Seasonal rates, which are higher
in the months of June , July, and August than during the
other nine remaining months, are intended to signal
customers that consumption during the summer months is
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more costly.It is hoped that this signal will encourage
reduced consumption during the
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peak months.
Why is the Company not proposing seasonal rates
for Schedule 24, irrigation service?
Irrigation service is by definition seasonal.
The pricing structure for Schedule 24 already takes into
account the seasonal nature of irrigation service.
Why is the Company proposing time-of-use rates
for Schedule 19 service?
Besides being more costly during the summer
months , energy is more costly during certain hours of the
day.The implementation of time-of-use rates for
Schedule 19 customers, who currently have the metering in
place to accommodate the hourly pricing, will provide the
economic signal that energy is more costly during both
the peak hours of the day and the peak months of the
year.Again , like strictly seasonal rates, it is hoped
that time-of-use rates will encourage reduced consumption
both during the summer months as well as during the daily
peak hours.
What are the specific pricing obj ecti ves for
the Company I s various service schedules?
First, the Company plans to place more emphasis
on the customer and demand components in its overall rate
structure.Second, the Company plans to initiate
seasonal energy pricing on all metered service schedules
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and both seasonal energy and seasonal demand pricing on
all metered service schedules that are also demand
metered.And finally, the Company plans to implement
mandatory time-of-use pricing for all customers taking
service under Schedule 19.The Company does not plan to
change the current seasonal pricing structure for
irrigation service, nor does it plan to implement
seasonal pricing for unmetered schedules or for the
special contract customers.
How are the seasons defined for the Company '
pricing proposals?
The summer season is defined as June 1 through
August 31.The non-summer season is defined as September
1 through May 31.
Are you proposing any changes to the criteria
for determining service schedule eligibility?
I am not proposing any changes to the usage
criteria for determining eligibility for service under
Schedules 7 , 9, and 19.However , I am proposing a change
to the process used to review customers' eligibility.
Would you please explain the change being
proposed?
Yes.Currently, each customer taking service
under Schedule 7 , 9, or 19 is assigned an anniversary
date that coincides with the date on which service under
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the schedule first began.Each year during the billing
period in which the customer I s anniversary date falls,
the
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customer I S usage during the past twelve months is
reviewed to determine continued eligibility.Customers
whose usage during the annual review period has changed
such that they are no longer eligible for the existing
schedule are moved to the appropriate schedule beginning
with the next billing period.Al though this process
works well under most situations, there are cases in
which there is a lag between changes in usage and the
actual annual review. For example, under the current
method where the annual review occurs on the customer '
anniversary date, a customer taking service under
Schedule 7 whose account is reviewed on July 1 may decide
to install an additional piece of equipment that causes
the monthly usage to increase over 3,000 kWh per month.
This increase in usage would make the customer eligible
for service under Schedule 9 after just three months.
However , because the customer I s account will not be
reviewed again until the following July 1 , the customer
will continue receiving service under Schedule 7. In
order to more closely match any change in usage with the
most appropriate service schedule, I am proposing to
eliminate the annual review on the customer ' s anniversary
date.In its place , I propose to review each customer ' s
account monthly.Based on this monthly review of the
customer's most recent twelve months of usage, transfers
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to the appropriate service schedule will be timelier.
The
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language on Schedules 7, 9 , and 19 has been modified to
reflect this change in process.
Are you proposing any other changes that are
common to several service schedules?
Yes.I am proposing that the Customer Charge
included on Schedules 1, 7 , 9, 19, 24 , and 25 be renamed
to Service Charge.
Why is this change being proposed?
The current Customer Charge is intended to
recover costs that do not vary with the amount of energy
or capacity used.These costs include such items as a
portion of the investment in distribution facilities, the
investment in meters and service drops, meter reading,
billing, and other customer service related expenses.
The term Service Charge is more descriptive of these
costs and, I believe , will be more easily explained to
customers.
What change is being proposed to the power
factor requirement for Schedules 9, 19, and 24?
Currently, Schedules 9 , 19, and 24 provide a
means by which the measured kW may be adjusted if the
customer I S power factor is less than 85 percent.I am
proposing this provision be revised to allow for the
measured kW to be adjusted if the customer I s power factor
is less than 90 percent.This revision will more
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directly target cost recovery from those customers whose
poor power
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factors result in the need for additional facilities
investment by the Company. In order to provide ample time
for customers to work with Company representatives to
identify and implement solutions to improve power factor
I am proposing the 90 percent power factor requirement
not become effective until November 1 , 2004.
Are you proposing any changes to the
contracting provisions for large customers requiring
000 kilowatts (kW) or more of capacity?
Yes. I am proposing that any customer , except a
customer receiving service under a special contract, who
requires 1 000 kW or more of capacity at a single point
of delivery enter into a service agreement with the
Company specifying the amount of capacity required.
entering into an agreement, the customer will have
certainty that facilities are in place to provide the
agreed upon level of capacity and the Company will have
information useful for its planning purposes.I have
added a section to Rule C , Service Agreement, specifying
this provision.I have also added a Uniform Service
Agreement in tariff format to Rule
Are you proposing any changes not directly
related to the Company I s rate design?
Yes.Based on previous Commission Orders, the
unit avoided energy cost for cogeneration and small
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power production available under Schedule 89 is to be
adj usted during the course of every Idaho Power general
rate proceeding.Using the methodology previously
ordered by the Commission, I have adjusted the unit
avoided energy cost utilizing updated variable operation
and maintenance costs and variable fuel costs for the
Valmy plant.
Have you prepared or supervised the preparation
of certain exhibits relating to your rate design
testimony?
Yes.I am sponsoring the following exhibits
relating to rate design:
Exhibi t Description
Exhibit No. 42 Class Cost-of-Service Unit Costs
Exhibit No. 43 Summary of Revenue Impact and
Calculation of Proposed Rates
Exhibi t No. Billing Comparisons and Rate Design
Impacts of Proposed Rates
Exhibit No. 45 Derivation of Schedule 19 Charges
Exhibit No. 46 Derivation of Schedule 24 Charges
Exhibit No. 47 Derivation of Schedule 45 Standby
Charges
Exhibit No. 48 Proposed Tariff in Legislative Format
Exhibit No. 49 IPUC No. 27 , Tariff No. 101
Please describe Exhibit No. 42.
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Exhibit No. 42 shows the unit cost for each
function for metered service schedules as determined
through
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the fully distributed or embedded 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.The uni t
costs shown on Exhibit No. 42 form the basis of the
component charges for each service schedule.
Please describe Exhibit No. 43.
Page 1 of Exhibit No. 43 is titled Summary of
Revenue Impact.Each service schedule and special
contract customer is listed with its number of customers,
energy sales, and current revenue level.Column 5 shows
the revenue adj ustment to each customer class.Column 6
shows the revenue to be recovered by the rate design
proposals based on the 2003 test year. Page 1 also lists
the mills per kWh and percentage change in revenue for
each customer class and special contract customer.
Pages 2 through 22 of Exhibit No. 43 indicate the
rate calculations made, by billing component, for each
service schedule and special contract customer.
Please describe Exhibit No. 44.
Exhibi t No. 44 shows the impact on customers
bills of the proposed rate designs for Schedules 1, 7 , 9,
19,, and 25.
Please describe Exhibit No. 45 and Exhibit No.
46.
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Exhibit No. 45 details the derivation of the
charges for Schedule 19.Exhibit No. 46 details the
derivation of the charges for Schedule 24.
Please describe Exhibit No.4 7.
Exhibit No. 47 details the derivation of the
updated charges for Standby Service under Schedule 45.
Please describe Exhibit No. 48 and Exhibit No.
49.
Exhibit No. 48 includes the Company s rules,
regulations, and service schedules indicating in
legislative format the changes made to those rules,
regulations, and schedules.Exhibit No. 49 is the
proposed Idaho Public Utilities Commission No. 27 , Tariff
No. 101 This exhibit contains all the changes to the
Tariff proposed by the Company in this proceeding.
How have you organized your discussion of the
Company I S rate design proposals?
I have divided my discussion of the Company '
proposed rate designs into six sections.The first
section includes the discussion for the proposed rate
structures for the Company I s non-demand metered
schedules.The second section addresses the Company '
proposals for demand-metered schedules.The third
section includes the discussion for the proposed rate
structures for the Company s non-metered schedules. The
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fourth section addresses the Company I s proposals for the
special contract customers.The fifth section includes
the rate design proposals for the Company's "rider
schedules for standby and alternate distribution service.
The final section addresses the Company's proposals for
its miscellaneous special contracts.
NON-DEMAND METERED SCHEDULES
What are the Company's non-demand metered
service schedules?
Residential Service and Small General Service,
Schedules 1 and 7 respectively, are metered for
kilowatt-hour (kWh) use only.
What is the present rate structure for
Residential Service under Schedule
Presently, residential customers pay a Customer
Charge of $2.51 and a base Energy Charge of 4.93039 per
kWh.
What is the revenue requirement to be recovered
from Residential Service customers taking service under
Schedule I?
Based on Mr. Gale I s Exhibi t No. 61 , the annual
revenue to be recovered from Schedule 1 customers is
$255,076,727.
Please describe the rate design proposal for
Schedule 1.
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The rate design proposal for Schedule 1 is
included on page 2 of Exhibit No. 43.The Service Charge
is increased from $2.51 to $10.00 per month.The $10.
Service Charge represents approximately 40 percent of the
cost-of-service result of $24.61 shown at line 300 on
page 1 of Exhibit No. 42.Both a summer and a non-summer
Energy Charge are established with the summer charge 25
percent greater than the non-summer charge.The Ene rgy
Charge during the summer is 6.13759 per kWh.The Ene rgy
Charge during the non-summer is 4.91019 per kWh.
What impact does this rate design have on
Residential Service customers?
The typical monthly billing comparison for
Residential Service customers appears on page 1 of
Exhibit No. 44.
Do you believe the increase in the Service
Charge from $2.51 to $10.00 per month is detrimental to
low income customers?
No, I do not.
Are you proposing any other changes to
Schedule I?
Yes.I am making what I consider housekeeping
changes to clarify that residential service is not
applicable if service is utilized for a commercial
purpose or if the customer s equipment does not conform
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to the Company' s specifications for residential service.
What is the present rate structure for Small
General Service under Schedule
Customers taking service under Schedule 7 pay a
Customer Charge of $2.51 and a base Energy Charge of
96499 per kWh.Demand is not metered for Schedule 7
customers.
What is the revenue requirement to be recovered
from Small General Service customers taking service under
Schedule 7?
Based on Mr. Gale I s Exhibit No. 61, the total
annual revenue to be collected from Schedule 7 customers
is $20,328,148.
Please describe the rate design proposal for
Schedule 7.
The rate design proposal for Schedule 7 is
included on page 3 of Exhibit No. 43.The Service Charge
is increased from $2.51 to $10.00 per month.The $10.
Service Charge represents approximately 40 percent of the
cost-of-service result of $26.01 shown at line 360 on
page 2 of Exhibit No. 42.Both a summer and a non-summer
Energy Charge are established.The Energy Charge during
the summer is 7.28689 per kWh.The Energy Charge during
the non-summer is 5.82839 per kWh.As is the case for
residential service , the Schedule 7 Energy Charge during
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the summer is 25 percent greater than the Energy Charge
during the non-summer.
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What is the impact of this rate design on Small
General Service customers?
Page 2 of Exhibit No. 44 shows the billing
comparison between the existing rates and rate structure
and the proposed rates and rate structure for typical
billing levels.
Are you proposing other changes to Schedule
As I will explain in more detail as I describe
the proposed changes to Schedule 24 , Irrigation Service,
I am proposing to add language to Schedule 7 that
clarifies that it is not applicable to agricultural
irrigation service after October 31 , 2004.
DEMAND-METERED SCHEDULES
What are the Company I s demand-metered
schedules?
The Company s demand-metered schedules are
Large General Service, Large Power Service , and
Irrigation Service, Schedules 9 , 19 , and 24
respectively.In addition, Schedule 25, Irrigation
Service Time-of-Use Pilot Program, while not open to new
participants , is still available to those who were taking
service as of October 1 , 2002.
How are Schedule 9 and Schedule 19
interrelated?
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Both Schedule 9 and Schedule 19 provide service
at Secondary, Primary, and Transmission Service levels.
As customers I loads change, they can transfer between
Schedule 9 and Schedule 19 while continuing to take
service at the same service level.Both Schedule 9 and
Schedule 19 have a Demand Charge and a Basic Charge.The
Demand Charge is assessed on peak demand each month while
the Basic Charge is assessed on the average of the two
highest peak demands for the current 12 -month period.
What is the current relationship between prices
on Schedule 9 and Schedule 19?
Currently, the Basic Charge, the Demand Charge,
and, with a slight deviation , the Customer Charge are the
same within service level for both Schedule 9 and
Schedule 19.For example, the Basic Charge for Primary
Service level is $0.77 per kW per month for both Schedule
9 and Schedule 19 for Secondary Service level , the Basic
Charge is $0.36 per kW per month for both Schedule 9 and
Schedule 19.The Energy Charges for Primary and
Transmission Service level for Schedule 9 are
approximately 2.25 percent greater than the corresponding
Energy Charges for the same service level for Schedule
19.
Why has this relationship been established?
This relationship has been established to be
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reflective of cost and to facilitate customer transitions
from Schedule 9 to Schedule 19 and vice versa.
Does the Company I s rate design proposal for
Schedule 9 and Schedule 19 customers maintain this
pricing relationship between schedules?
The rate design proposal for Schedule 9 and
Schedule 19 maintains the relationship between the Basic
Charge and the Demand Charge on each of the schedules.
However, because time-of -use pricing is being proposed
for Schedule 19 and not for Schedule 9, a direct
relationship between the energy components is not
maintained.
What is the present rate structure for
Schedule 9?
Service under Schedule 9 is taken at Secondary,
Primary, or Transmission Service level.One hundred
twel ve customers take service at Primary Service, three
customers take service at Transmission Service, and
919 customers take service at Secondary Service.All
customers taking service under Schedule 9 pay an Energy
Charge, a Demand Charge, a Basic Charge, and a Customer
Charge. Customers taking Primary or Transmission service
may also pay a Facilities Charge.
Please describe the rate design proposal for
Schedule 9.
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The Company is proposing both seasonal Energy
Charges and seasonal Demand Charges for Schedule
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addition , the Company is proposing increases to both the
Service Charge and the Basic Charge.
Does the rate design proposal have the same
overall impact in terms of the percentage increase in
revenue requirement for customers taking service under
Secondary, Primary, and Transmission Service levels?
No. The results of the cost-of-service study
indicated an overall increase in revenue of 8 percent for
Secondary Service level customers and 24 percent for
Primary and Transmission Service level customers (refer
to line 233 on page 1 of Exhibit No. 41).In order to
recognize this cost difference between service levels,
the rate design proposal for Primary and Transmission
Service level targets an average overall increase of 20
percent.
What is the Service Charge for Schedule
The Service Charge for Secondary Service under
Schedule 9 is $21.This amount represents approximately
55 percent of the cost-of-service result of $37.74 shown
at line 480 on page 3 of Exhibit No. 42.The Service
Charge for Primary and Transmission Service is $500.
This amount is the same charge established for Schedule
19 Primary Service and Schedule 19 Transmission Service
and reflects the cost associated with the automated
metering of customers at these voltage levels.
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What is the Basic Charge for Schedule
The Basic Charge for Secondary Service is $.
per kW of basic load capacity per month.The $.65 charge
reflects approximately 50 percent of the cost of service
for distribution facilities as shown at line 480 on page
3 of Exhibit No. 42.For Primary Service, the Basic
Charge is $1.12 per kW of basic load capacity.The Basic
Charge for Transmission Service is $.57.The Basic
Charge for Primary Service and the Basic Charge for
Transmission Service are the same as those for Schedule
The derivation of the $1.12 and $.57 charges is19.
detailed later in my discussion of the Schedule 19 rate
design.
What is the Demand Charge for Schedule
The Demand Charge for Secondary Service for the
summer season is $4.00 per kW and for the non-summer
season is $3.35 per kW per month.For Primary Service,
the Demand Charge during the summer season is $3.94 per
kW.During the non-summer season the Demand Charge for
Primary Service is $3.25 per kW.The Demand Charge for
Transmission Service is $3.80 per kW during the summer
season and $3.15 per kW during the non-summer season.
For the non-summer season , the Demand Charges for
Secondary, Primary, and Transmission Service are the same
as those for Schedule 19.The derivation of both the
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summer and non-summer Demand Charges is described in more
detail in my discussion of the Schedule 19 pricing
design.
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What is the Energy Charge for Schedule
The Energy Charge for Secondary Service is
94429 per kWh during the summer and 2.56169 per kWh
during the non-summer.For Primary Service , the Energy
Charge is 2.56599 per kWh during the summer and 2.18239
during the non-summer.The Energy Charge for
Transmission Service is 2.50879 per kWh during the summer
and 2.13379 per kWh during the non-summer.
How were the Energy Charges derived?
The differential between the summer and
non-summer energy costs resulting from the class
cost-of-service study for Schedule 9 is approximately
percent (refer to Exhibit No. 42, page 3, line 480) .The
Energy Charges for Primary Service were set to reflect
this cost differential.The Energy Charges for
Transmission Service were set to maintain the current
relationship between the Energy Charges for Primary and
Transmission Service. The Energy Charges for Secondary
Service were set to recover the residual revenue
requirement for the class while attempting to maintain a
summer and non-summer differential close to 18 percent.
Are you proposing any other changes to Schedule
As I will explain in more detail as I describe
the proposed changes to Schedule 24 , Irrigation Service
I am proposing to add language to Schedule 9 that
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clarifies that it is not applicable to agricultural
irrigation service after October 31 , 2004.
What is the revenue requirement to be recovered
from Schedule 9?
Based on Mr. Gale's Exhibit No. 61, the total
annual revenue to be collected from customers taking
service under Schedule 9 is $123 864 097.
What is the impact of this rate design on Large
General Service customers?
As can be seen from page 3 of Exhibit No. 44
approximately 30 percent of the customers taking Schedule
9 Secondary Service receive an increase in their annual
bills less than the 15 percent overall increase for the
Secondary Service customers as a whole.Another 28
percent of the Secondary Service customers receive an
increase of 15 percent to less than 20 percent.For
Primary and Transmission Service level customers,
approximately 43 percent of the customers receive an
increase less than the 20 percent overall increase
targeted for this group.Page 4 of Exhibit No. 44 shows
the impact of the rate design proposal on customers
taking service under Schedule 9 Primary or Transmission
Service.For all service levels , customers with higher
load factors receive less of an increase than customers
wi th lower load factors.
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What is the present rate structure for Schedule
19?
Service under Schedule 19, just like service
under Schedule 9 , is provided under Secondary, Primary,
or Transmission Service levels. All customers taking
service under Schedule 19 pay an Energy Charge , a Demand
Charge, a Basic Charge, and a Customer Charge. Customers
taking Primary or Transmission Service may also pay a
Facilities Charge. In addition, Schedule 19 includes a
000 kW minimum billing demand and basic load capacity.
What is the rate design proposal for Schedule
19?
The Company is proposing seasonal time-of-use
rates be implemented on a mandatory basis for all
customers taking service under Schedule 19.Under the
Company s proposal , On-Peak , Mid-Peak , and Off-Peak
energy prices would be in effect during the three summer
months from June 1 through August 31.During all other
months Mid-Peak and Off-Peak energy prices would be in
effect.In addition to seasonal energy rates, the
Company is also proposing summer and non-summer demand
charges as well as an on-peak demand charge during the
summer. Al though the Company is proposing an increase to
both the Service Charge and the Basic Charge , no
seasonality is being proposed for these charges.
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What is the Service Charge for Schedule 19?
For all service levels, the Service Charge is
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$500 per month. This amount represents approximately
percent of the cost-of-service result of $712.36 shown at
line 720 on page 5 of Exhibit No. 42.
What is the Basic Charge for Schedule 19?
The Basic Charge for Secondary Service is $.
per kW per month , the same as that for Schedule 9
Secondary Service.For Primary Service, the Basic Charge
is $1.12 per kW per month.This amount is approximately
equal to the cost-of-service result of $1.11 shown on
line 720 on page 5 of Exhibit No. 42.For Transmission
Service the Basic Charge is set to $.57 per kW per month
to maintain the existing relationship between the Primary
and Transmission Service levels.
Please describe the Company I s proposal for
time-of-use energy charges.
During the three summer months, the Company is
proposing three time-of-use blocks.The On-Peak block is
defined as 1 p. m. to 9 p. m. Monday through Friday.The
Mid-Peak block is defined as 7 a. m. to 1 p. m. and 9 p. m.
to 11 p. m. Monday through Friday and 7 a. m. to 11 p.
Saturday, Sunday, and holidays.The Off - Peak block is
defined as 11 p.m. to 7 a.m. every day. During the
non- summer months, the Company is proposing just two
time-of -use blocks.The Mid-Peak block during the
non-summer is defined as 7 a.m. to 11 p.m. Monday through
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Idaho Power Company
Saturday.The Off -Peak block is defined as 11 p. m. to
m. Monday through Saturday and all hours on Sunday and
hol idays .All times are in Mountain Time.
What are the specific proposed energy prices?
The Energy Charges by service level and time
period for each season are:
Time
Period
- - - - - - - - - - -
Service Level- -
- - - - - - - - - -
Secondary Primary Transmission
Summer
On-Peak 43549 79919 73689
Mid-Peak 03759 47499 41989
Off-Peak 77459 26069 21039
Non-Summer
Mid-Peak 66619 17239 12399
Off-Peak 49289 03119 98599
Please describe the Company I s proposal for
Demand Charges.
During the three summer months, the Company is
proposing to implement a two-tiered Demand Charge for
monthly peak demand. The Demand Charge for Billing
Demand, which is the average kW supplied during the
15-minute period of maximum demand during the billing
period, is $3.61 per kW for Secondary Service, $3.50 per
kW for Primary Service , and $3.39 per kW for Transmission
Service.For all service levels , an additional charge of
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$0.45 is assessed for each kw of On-Peak Billing Demand,
which is the average kW
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supplied during the 15-minute period of maximum demand
during the billing period for the on-peak hours.For
customers whose peak demand during the billing period
occurs during the on-peak period, the Billing Demand and
the On-Peak Billing Demand will be the same.However
for customers whose peak demand occurs during the
mid-peak or off -peak period, the Billing Demand will be
greater than the On-Peak Billing Demand.During the
non- summer months , only Billing Demand will apply. There
is no On-Peak Billing Demand during the non-summer
months.The Demand Charges for the non-summer months are
$3.35 per kW for Secondary Service, $3.25 per kW for
Primary Service, and $3.15 per kW for Transmission
Service.
Would you please provide an example of how the
summer Billing Demand and On-Peak Billing Demand will
affect customers?
Yes.Assume a Primary Service level customer
has a peak demand for the billing period of 1 500 kw
which occurs during the on-peak period.In this
situation the Billing Demand and the On-Peak Billing
Demand will equal 1 500 kW. This customer will pay a
total of $3.95 for each kw of peak demand since the
Billing Demand and On-Peak Billing Demand are the same
($3.50 per 1,500 kW of Billing Demand plus $.45 per 1,500
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kW for On-Peak Billing Demand) .However if this same
customer has a peak demand for the
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billing period of 1,500 kw that occurs during the
mid-peak or off-peak period with the highest peak demand
during the on-peak period equal to 1,200 kW , the On-Peak
Billing Demand will be less than the Billing Demand.
this situation , the customer will, on average, pay only
$3.86 per kw of peak demand ($3.50 per 1 500 kW
Billing Demand plus $.45 per 1,200 kW of On-Peak Billing
Demand) .
Are you aware of any utilities that charge for
both peak demand during the month and on-peak demand
during the month in a manner similar to the Billing
Demand and On-Peak Billing Demand you are proposing for
the summer season?
Yes.I am aware of at least three utilities
that have similar pricing for demand:Southern
California Edison charges for the monthly peak demand
the monthly on-peak demand, and the monthly mid-peak
demand under its Schedule TOU-Pacific Gas and Electric
charges for the monthly peak demand, the monthly
peak-period demand, and the monthly partial-peak-period
demand under its Schedule E-19 and Colorado Springs
Utilities charges for both monthly on-peak and monthly
off-peak demand under its Schedule E8T and E8S.Both
Southern California Edison and Pacific Gas and Electric
charge for on-peak demand during the summer season only.
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What approach was taken in determining the
pricing proposal for Schedule 19?
A two-step approach was taken.First , seasonal
charges that did not differentiate by time-of -use were
developed.After the seasonal charges were developed,
the next step was to create the time-of-use charges for
the demand and energy components wi thin each season.
Exhibit No. 45 details the derivation of the seasonal
non time-of -use differentiated charges as well as the
derivation of the seasonal , time-of -use charges.
How were the seasonal charges developed?
The Energy Charges for each season were
established to approximate the 17 percent cost
differential between summer and non-summer energy costs
resul ting from the class cost -of - service study for
Schedule 19 while at the same time maintaining the
current relationship between the Energy Charges for each
service level and recovering the residual revenue
requirement given the proposed Service, Basic, and Demand
Charges.The Demand Charge for Primary Service was
developed by first establishing the non-summer Demand
Charge at $3.25 per kW , which is approximately 10 percent
greater than the Schedule 19 Primary Service
cost-of-service result of $2.95 shown at line 720 on page
5 of Exhibit No. 42 and approximately equal to the
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Schedule 9 Primary Service cost-of-service result of
$3.29 per kW shown at line 540 on page 4 of Exhibit
No. 42.The summer Demand
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Charge for Primary Service was then established at $3.
per kW to reflect a 20 percent differential between the
summer and non-summer Demand Charges.The Demand Charges
for both non-summer and summer for Secondary and
Transmission Service were then set to maintain the
current relationship for these charges between the three
service levels. The non-summer Demand Charge was set to
$3.35 per kw for Secondary Service and to $3.15 per kW
for Transmission Service.The summer Demand Charge was
set to $4.00 per kW for Secondary Service and to $3.
per kW for Transmission Service.
Why was a 20 percent differential established
between the summer and non-summer Demand Charges?
A 20 percent differential approximates the
seasonal differential for energy-related costs and
provides consistency with the differential between the
summer and non-summer Energy Charges.
What is the cost differential between summer
and non-summer demand-related costs that is supported by
the cost -of - service study?
The differential between the summer and
non-summer demand-related costs supported by the
cost-of-service study is approximately 80 percent (refer
to line 720 on page 5 of Exhibit No. 42).
Q. How were the time-of -use Energy Chargesdeveloped?
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Idaho Power Company
The first step in developing the time-of-use
Energy Charges was to determine the charge for the
Mid-Peak time period for each season.As a starting
point, the Mid-Peak charge was set equal to the seasonal
Energy Charge established through the process I just
described. For example , as a starting point , the summer
Mid-Peak Energy Charge for Primary Service was set to
46869, the value of the seasonal , non time-of -use
differentiated summer Energy Charge (refer to page 1 of
Exhibit No. 45).For the summer charges, the second
step involved determining the amount of increase or
decrease from the Mid-Peak charge needed to establish the
On-Peak and Off-Peak charges so that the target price
differentials for the three time blocks were met.For
the non- summer charges, the second step involved
determining the amount of decrease from the Mid-Peak
charge needed to establish the Off-Peak charge so that
the target differential for the two time blocks was met.
The final step involved minor adjustments to each charge
to establish prices that recovered the revenue
requirement amount.
What were the target price differentials
between the various time blocks that the Company was
striving to achieve?
For the summer months, the target price
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Idaho Power Company
differential between the on-peak and off-peak time
periods is 25 percent.According to the Company I s Power
Supply
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Planning Department , this differential represents the
approximate difference in cost between an average market
price for energy during the summer months of June , July,
and August and a flat market price for the calendar year.
The price differentials between the on-peak and mid-peak
prices and the mid-peak and off -peak prices resulted from
an iterative process in which the Company attempted to
maintain the mid-peak price as close to the flat seasonal
charge as possible , give a price signal to encourage
shifting of load from the on-peak period to either the
mid-peak or off-peak period , and recover the revenue
requirement.For the non-summer months , the price
differential between the mid-peak and off -peak prices
resulted from an iterative process in which the Company
attempted to maintain the same relationship as the summer
mid-peak and off -peak prices while recovering the revenue
requirement.
How were the time-of -use Demand Charges
developed?
The Demand Charges for the non-summer months
for each service level were set equal to the seasonal,
non time-of-use differentiated charges (refer to Exhibit
No. 45 discussed earlier) The summer Demand Charge for
Primary Service was derived by applying the same
percent differential as was established for the summer
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Idaho Power Company
On-Peak and Mid-Peak Energy Charges to the summer non
time-of -use
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Idaho Power Company
differentiated Demand Charge of $3.94. The result of this
calculation is $3.50.The summer Demand Charges for
Secondary and Transmission Service were then set to
maintain the current relationship between the service
levels.The difference between $3.94 and $3.50, or $.
(rounded), is the summer On-Peak Demand Charge.The
On-Peak Demand Charge is set at $.45 for each service
level in order to help make the adoption of this new
charge simple for all customers.
Does your rate design proposal include any
revisions to the provision for a Facilities Charge under
Schedule 19?
No.Customers taking Secondary Service will
not be subj ect to a Facilities Charge. Customers taking
Primary Service will continue to be required to either
own all facilities , including transformers, beyond the
point of delivery or pay the Company a monthly Facilities
Charge of 1.7 percent times the Company s investment in
those facilities.Customers taking Transmission Service
will be required to own their own substations and all
other facilities beyond the point of delivery.In some
si tuations, customers taking Transmission Service may pay
a monthly Facilities Charge of 1.7 percent times the
Company I S investment in certain facilities.
Q. What is the total annual revenue requirement to
be collected from Large Power Service customers?
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Idaho Power Company
Based on Mr. Gale I s Exhibit No. 61 , the total
annual revenue requirement to be collected from Schedule
19 is $ 62 703 671.
What is the impact of the rate design on Large
Power Service customers?
As can be seen from page 5 of Exhibit No. 44
approximately 25 percent of the customers taking service
under Schedule 19 receive an increase in their annual
bills less than the 14 percent overall increase for the
Schedule 19 customers as a whole.Another 33 percent
receive an increase of 14 percent to less than 16
percent.For the Schedule 19 customer group as a whole,
customers with higher load factors receive less of an
increase than customers with lower load factors.
Are you proposing any other changes to Schedule
19?
Yes.Currently, customers are required to sign
a Uniform Large Power Service Agreement with the Company
in order to receive service under Schedule 19.If the
customer refuses to sign the Agreement, service continues
to be provided under Schedule 9, although technically,
based on the eligibility criteria for Schedule 9 , the
customer is not eligible. for service under Schedule 9.
Over the past several years the Company has experienced
an increase in the number of customers with loads greater
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Idaho Power Company
than 1,000 kW who meet the criteria for service under
Schedule 19 but who choose not to enter into an
Agreement.The reasoning stated by some of the customers
for not entering into an Agreement is the reluctance to
make a 12 -month commitment for service, particularly by
some of the companies that operate nationally.In order
to ensure that customers are placed on the appropriate
service schedule based on their usage characteristics,
am proposing to eliminate the requirement that a Uniform
Large Power Service Agreement be signed in order to
receive service under Schedule 19.Without the
requirement to enter into an Agreement, customers will be
transferred onto and off of Schedule 19 automatically
based on their usage.In addition, customers whose
operations are going out of business will no longer be
required to provide a twelve-month notice to the Company
prior to having Schedule 19 service discontinued.
Rather , as these customers I usage declines , they will be
transferred to the appropriate general service schedule
as indicated by the monthly review process.I have added
language to Schedule 19 indicating that all Uniform Large
Power Service Agreements will be cancelled effective June
, 2004.
What contracting requirements , if any, will
customers taking service under Schedule 19 have?
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Idaho Power Company
Customers taking service under Schedule 19 will
be required to enter into a Service Agreement with the
Company specifying the level of capacity required to
serve their facilities.I described this Service
Agreement earlier in my testimony.
Are you proposing any changes to the
eligibility criteria for receiving service under Schedule
19?
No.Schedule 19 will remain available to
customers who have three or more billing periods during a
twel ve-month period in which the metered demand equals or
exceeds 1,000 kW.However, Customers whose loads are
anticipated to immediately exceed 1 000 kW may request to
take initial service under Schedule 19.
What is the current rate structure for Schedule
24?
Service under Schedule 24 is classified as
being either "in-season" or "out-of-season"The
in- season for each customer begins with the customer '
meter reading for the May billing period and ends with
the customer I s meter reading for the September billing
period.The out-of-season encompasses all other billing
periods.
Within the in-season , customers pay both an Energy
Charge and a Demand Charge for the metered usage.During
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Idaho Power Company
the out-of-season , customers pay an Energy Charge only.
For the in-season , customers are subject to a $10.
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Idaho Power Company
Customer Charge.The Customer Charge during the
out-of-season is $2.50.
Both Secondary Service and Transmission Service
levels are available under Schedule 24 , although no
customers are currently taking Transmission Service.
Please describe the rate design proposal for
Schedule 24.
I am proposing to keep the overall rate
structure for the irrigation season as it is currently.
Consistent with the Company I s overall obj ecti ves, I
propose to move the individual rate components closer to
cost by emphasizing increases in the demand and customer
components and the inclusion of less non-energy related
costs in the energy charges.
What approach did you take in determining the
amount of increase for each rate component?
I first considered the percentage of overall
revenue requirement identified by demand, energy, and
customer component for irrigation service resulting from
the cost-of -service study.These percentages established
the target for each component and are shown in column 5
on Exhibit No. 46.Second, I determined the percentage
of overall revenue by component currently provided by the
existing base rates.These percentages are shown in
column 4 on Exhibit No. 46.The difference, or gap,
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Idaho Power Company
between the target and the actual percentage was then
determined for each component.Customer, demand, and
energy charges were then established at a level that
adjusted revenue by 15 percent of the gap.Exhibi t No.
46 illustrates the approach taken for each rate
component.
How were the rates for Transmission Service
determined?
Once the component rates for Secondary Service
were determined, the charges for Transmission Service
were established to maintain the same relationship
between service levels as currently exists.
What is the Service Charge for Schedule 24?
The Service Charge for Secondary Service during
the in-season is $25 per month.The Service Charge for
Transmission Service during the in-season is $500 per
month.This amount is the same charge established for
Schedule 9 and Schedule 19 Transmission Service.For
both Secondary and Transmission Service, the Service
Charge during the out-of-season is $2.50 per month.
What is the Demand Charge for Schedule 24?
The Demand Charge for Secondary Service is
increased from $3.58 to $5.40 per kW per month.The
Demand Charge for Transmission Service is increased from
$3.37 to $5.08 per kW per month.The Demand Charge is
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Idaho Power Company
billed to Schedule 24 customers during the in-season
only.
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Idaho Power Company
What is the Energy Charge for Schedule 24?
The Energy Charge for Secondary Service is
increased from 2.84169 per kWh to 3.26349 per kWh during
the in-season and from 3.61729 per kWh to 4.57319 per kWh
during the out-of-season.The Energy Charge for
Transmission Service is increased from 2.70219 per kWh to
10359 per kWh during the in-season and from 3.43969 per
kWh to 4.34909 per kWh for the out-of-season.
What is the impact of the rate design on
Schedule 24 irrigation service customers?
Page 6 of Exhibit No. 44 shows the billing
impact of the proposed rate design.As can be seen from
page 6 of Exhibit No. 44 , approximately 23 percent of the
customers taking service under Schedule 24 receive an
increase in their annual bills of less than 25 percent,
the total overall percentage increase for the class as a
whole.Another 31 percent of the customers receive an
increase of just 3 percent or less above the overall
class increase of 25 percent.The remaining customers
receive an increase in their annual bills of 32 percent
to greater than 50 percent.
What are the usage characteristics of the
Schedule 24 customers receiving increases less than and
greater than 25 percent?
Because the rate design places an increased
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Idaho Power Company
emphasis on capacity, the higher a customer I s load
factor
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Idaho Power Company
the more beneficial the rate structure tends to be in
terms of the overall impact to the annual billing.
can be seen from page 6 of Exhibit No. 44, customers with
the highest percentage increase in annual bills have the
lowest load factors.
What changes are being proposed for Schedule
25, Irrigation Service Time-of -Use Pilot Program?
Schedule 25 currently provides continued
service until October 1, 2007 for those participants who
were enrolled in the pilot program on October 1 , 2002.
The Company is not proposing any changes to this ongoing
service availability at this time.However , the Company
is proposing to revise the Schedule 25 Service and Demand
Charges to be consistent with the charges for Schedule 24
and to increase the time-of -use rates to recover the
revenue requirement.
What are the rates being proposed for Schedule
25?
I am proposing that the in-season and
out-of-season Service Charges, the Demand Charge , and the
out-of -season Energy Charge proposed for Schedule 24 be
implemented for Schedule 25.Under this proposal the
in-season Service Charge is $25 per month , the
out-of-season Service Charge is $2.50 per month , the
Demand Charge is $5.40 per kW per month , and the
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Idaho Power Company
out-of-season Energy Charge is 4.57319 per kWh.The
$3.00 per month in-season Meter Charge remains the same.
For the in-season, the On-Peak Energy Charge is 5.71109
per kWh , the Mid-Peak Energy Charge is 3.26349 per kWh,
and the Off-Peak Energy Charge is 1.63179 per kWh.
Would you please describe the methodology used
to determine the in-season Energy Charges for Schedule
25?
As is currently the case, the Mid-Peak Energy
Charge is set equal to the in-season Energy Charge under
Schedule 24 , or 3.26349 per kWh.The differential
between the On-Peak Energy Charge and the Off-Peak Energy
Charge is the same as that currently in place for
Schedule 25.That is , the On-Peak Energy Charge is 75
percent greater than the Mid-Peak Energy Charge while the
Off-Peak Energy Charge is 50 percent less than the
Mid-Peak Energy Charge.
What is the impact of these changes on the
Time-of-Use Irrigation Service customers?
The overall increase for the customer group as
a whole is 25 percent, the same percentage increase as
for the irrigation customer class as a whole. As can be
seen from page 7 of Exhibit No. 44, approximately
percent of the customers taking service under Schedule 25
receive an increase in their annual bills of less than 25
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Idaho Power Company
percent.Another 27 percent of the customers receive an
increase of just 3 percent or less above the overall
class increase of
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Idaho Power Company
25 percent.
What are the usage characteristics of the
Schedule 25 customers receiving increases less than and
greater than 25 percent?
As is the case with Schedule 24 , the rate
design for Schedule 25 places an increased emphasis on
capaci ty.As a resul t , the higher a customer's load
factor, the lower the overall percentage increase.
Conversely, the lower a customer' s load factor , the
higher the overall percentage increase.
Are any other changes to Irrigation Service
being proposed?
Yes.Currently, irrigation customers who
request service be reconnected or transferred into their
name are not charged an account processing charge or a
reconnect ion charge if they provide ten working days
advanced notice of the date reconnect ion or transfer of
service is desired.This "waiver" of the account
processing charge is unique for irrigation customers as
all other customers receiving metered service are
assessed an account processing charge or a reconnect ion
charge when service is transferred or reconnected. I am
proposing that irrigation customers be treated similarly
to all other customers who request a service reconnect ion
or transfer by assessing either a service reconnect ion
838 BRILZ, DI
Idaho Power Company
charge or a service establishment charge in each
situation where the service is performed.
Will irrigation customers still be required to
provide ten working days advance notice of the date they
desire to have service reconnected or transferred?
No.The Company will process requests for
service reconnect ions and transfers in the same manner as
these requests are now processed for all other customers.
In almost all situations, these requests will normally be
processed wi thin three working days.
Why is the Company proposing to add these
charges for irrigation service at this time?
Since the Company routinely began leaving
irrigation service connected on a year-round basis in
1996, the number of customers requesting service
disconnections has declined dramatically.Prior to 1996,
irrigation service was disconnected for approximately 80
percent of the Company I s irrigation customers at the end
of the pumping season.Over the winter of 2002
irrigation service was disconnected for only about 20
percent of the Company 's 15 280 irrigation customers.
1996, the Company performed approximately 9 000 service
reconnect ions for irrigation customers.In 2003, only
400 service reconnect ions for irrigation customers were
performed.The Company believes it is equitable to have
839 BRILZ, DI
Idaho Power Company
those customers who require the reconnection service pay
for the service rather than having the costs shared by
all customers.Requiring customers to pay a reconnection
charge will eliminate a cross-subsidy between those
irrigation customers who require service reconnections
and those who do not.Similarly, charging the
approximately 1 250 customers who annually require the
Company to perform a special meter reading in order to
transfer service into their names is more equitable and
targets cost recovery from those customers who require
the specific service.
What are the reconnection charge and service
establishment charge for irrigation customers being
proposed by the Company?
Ms. Drake addresses the specific charges and
their derivation in her testimony.
What change is being proposed to the
eligibility criteria for Schedule 24 and Schedule 25?
The current language under the Applicability
section on both Schedule 24 and Schedule 25 states that
service is "applicable to power and energy supplied to
farm customers and organizations"Al though the Company
is confident that Schedule 24 and Schedule 25 are
intended to be available to farm customers and farm
organizations, the current wording has led to various
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Idaho Power Company
interpretations.The Company intends to clarify the
nature of service for which
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Idaho Power Company
Schedule 24 and Schedule 25 are applicable by replacing
the existing language under the Applicability section
with language that specifies that service is applicable
to power and energy supplied to agricultural use
customers operating water pumping or water delivery
systems used to irrigate agricultural crops or pasturage
and by changing the name of the schedule from simply
Irrigation Service to Agricultural Irrigation Service.
Are there any customers currently receiving
service under Schedule 24 or Schedule 25 that would no
longer be eligible for irrigation service with the
adoption of the new applicability language?
Yes.There are approximately 768 customers
currently receiving service under Schedule 24 and
Schedule 25 that would no longer be eligible for
continued irrigation service with the adoption of the new
applicability language.The maj ori ty of these customers
utilize service for the irrigation of golf courses,
cemeteries , parks, school grounds, and common areas in
subdivisions.
What is the Company' s plan for addressing this
issue?
The Company plans to allow non-agricultural
customers to continue receiving irrigation service under
Schedule 24 or Schedule 25 through October 31 , 2004.
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Idaho Power Company
Effective November 1 , 2004 , any non-agricultural
customers
843 BRILZ , DI 66a
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still receiving service under Schedule 24 or Schedule 25
would be transferred to the applicable general service
schedule.In addition, on this date , any agricultural
customer utilizing a water pumping or water delivery
system and receiving service under either Schedule 7 or
Schedule 9 would be transferred to Schedule 24.
How many agricultural customers currently
served under Schedule 7 or Schedule 9 would will be
affected by this change?
Approximately 613 customers would be
transferred from Schedule 7 or Schedule 9 to Schedule 24.
NON - METERED SCHEDULES
What are the Company I s non-metered service
schedules?
The Company I s non-metered schedules are Dusk to
Dawn Customer Lighting, Unmetered General Service, Street
Lighting Service , and Traffic Control Signal Lighting
Service, Schedules 15, 40, 41, and 42 , respectively.
What is the present rate structure for Dusk to
Dawn Customer Lighting on Schedule 15?
Customers taking service under Schedule 15 are
charged on a per lamp basis.Lamps currently served
under Schedule 15 include 100, 200, and 400 watt high
pressure sodium vapor area lighting, 200 and 400 watt
high pressure sodium vapor flood lighting, and 400 and
844 BRILZ, DI
Idaho Power Company
000 watt metal halide flood lighting. Under Schedule
15, customers pay a monthly Facilities Charge of 1.
percent for all new facilities required for service.
What is the revenue requirement to be recovered
from customers taking service under Schedule 15?
Based on Mr. Gale I s Exhibit No. 61, the annual
revenue to be recovered from Schedule 15 customers is
458,416.
The class cost-of-service study indicates that
the rates for Schedule 15 service should be reduced by
over 100 percent.Would you please explain this result?
Yes.Customers who require new facilities to
installed order to receive service under Schedule
are charged a monthly facilities charge equal 1. 75
percent the Company I s investment in those new
facilities.Prior to the implementation of the Company '
current customer information system (CIS) in 2000,
facilities charge revenue by customer class was not
available. In addition, the way in which the Company
tracks facilities for customers receiving non-metered
service does not identify the total investment in new
facilities installed to provide Dusk to Dawn Customer
Lighting Service.In prior cost -of - service studies, the
total facilities charge revenue collected from customers
was allocated to customer classes based on the identified
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I daho Power Company
facili ties investment for each class.This methodology
resulted in no facilities charge revenue being directed
to the Schedule 15 customer class.Rather , the
facilities charge revenue that should have been directed
to the Schedule 15 customer class was spread to other
customer classes.Because the detailed information on
facilities charge revenue is now available through the
CIS, the current cost -of - service study directly assigns
the appropriate amount of facilities charge revenue to
each customer class, including the Schedule 15 class.
However , the issue of tracking facilities so that new
facilities installed to provide Dusk to Dawn Customer
Lighting Service can be correctly identified has not been
resolved.As a result , although the revenue is credited
to the Schedule 15 customer class, the associated costs
associated with the plant investment are not.Prior to
filing its next general rate case, the Company will
identify a methodology for correctly determining the new
facilities associated with Dusk to Dawn Customer Lighting
Service.
Does this inconsistency in the model have
negative implications for the other customer classes?
Although it would obviously be better to have
the correct matching of the revenue and expenses, any
impact to other classes is minimal.Based on the total
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Idaho Power Company
amount of facilities revenue received from Schedule 15
customers, the maximum total original investment in new
facilities should
847 BRILZ , DI 69a
Idaho Power Company
be approximately $6 million.The net amount of this
investment included in rate base, after adjustments for
depreciation, would be something less than $6 million.
Compared to a total rate base amount for the Idaho
Jurisdiction of $1.547 billion, the plant investment
potentially attributable to the Schedule 15 customer
class represents less than four tenths of one percent of
total rate base.
Please describe the rate design proposal for
Schedule 15.
The rate design proposal for Schedule 15 is
included on page 7 of Exhibit No. 43.The monthly charge
for each lamp is simply increased on a uniform percent
basis consistent with the overall 4.99 percent increase
for the class as a whole.
Is the Company proposing any other changes to
Schedule IS?
Yes.The Company is proposing two changes
related to the facilities required to provide Dusk to
Dawn Customer Lighting.First, the Company is proposing
to allow the lighting fixture to be installed on a
customer-owned support acceptable to the Company rather
than only on a Company-owned pole.Second , the Company
is proposing that an up- front payment be made when new
facilities are needed in order to provide the service
848 BRILZ , DI
Idaho Power Company
rather than having the customer pay a monthly facilities
charge on the new facilities.
Why is the Company proposing to allow the
fixture to be installed on a customer-owned support?
The Company is proposing to allow the fixture
to be installed on a customer-owned support that is
acceptable to the Company in order to allow more
flexibility for customers.In several instances, a
customer-owned pole or other structure could adequately
provide the support needed to install a lighting fixture.
Charging the customer an additional amount to install a
new Company-owned pole when an exiting customer-owned
structure exists is unnecessary. The Company would have
the sole discretion to determine if a customer-owned
support were acceptable.In addition , the Company would
have the right to remove its lighting fixture from the
customer-owned support if it were at any time determined
by the Company that the support was unsafe or had the
potential to cause damage to it or to other customers.
Language has been added to Schedule 15 that specifies
that by requesting the installation of a lighting fixture
on a customer-owned support , the customer is indemnifying
the Company from any liability associated with the
installation of the lighting fixture on the customer '
property and granting the Company permission to enter the
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Idaho Power Company
customer's premises, including the customer-owned
support, in order to maintain its lighting fixture.
What changes are being proposed regarding the
installation of new facilities to provide Dusk to Dawn
Customer Lighting Service?
Customers who request Dusk to Dawn Lighting
Service where Company facilities are not presently
available are required to pay a monthly facilities charge
of 1.75 percent for all new facilities installed to
provide service.New facilities can include such items
as poles , anchors, and conductors.If the facilities
remain in service for their full useful lives , the
Company is made whole on the transaction.However, if
the customer requests the Company discontinue the
lighting service and remove the facilities before the end
of their useful lives, the Company is not made whole for
the transaction.In order to avoid this situation , the
Company is proposing that the customer pay the work order
cost for the installation of new facilities at the time
service is requested.No monthly facilities charge would
then be required.If the customer requests the early
removal of the lighting fixture and other facilities , the
Company would still incur the labor costs associated with
the removal.However, the Company would not be left with
facilities for which it would not be able to recover its
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Idaho Power Company
investment.
What is the present rate structure for
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Idaho Power Company
Unmetered General Service under Schedule 40?
Customers taking service under Schedule 40 pay
a flat Energy Charge based on estimated usage.Demand -
and customer-related costs are recovered through the
Energy Charge.The minimum bill for service under
Schedule 40 is $1.50 per month.
What is the revenue requirement to be recovered
from customers taking service under Schedule 40?
Based on Mr. Gale's Exhibit No. 61 , the annual
revenue to be recovered from Schedule 40 customers is
$952 976.
Please describe the rate design proposal for
Schedule 40.
The rate design proposal for Schedule 40 is
included on page 14 of Exhibit No. 43.The Energy Charge
remains flat and increases from 5.6809 per kWh to 5.9539
per kWh.
Are any other changes being proposed to
Schedule 40?
Yes.Schedule 40 is available to customers
whose loads and hours of operation are fixed such that
the monthly kwh consumption can be accurately determined.
In order to ensure that Schedule 40 remains available
only to loads that are fixed, I am proposing language
that makes Schedule 40 unavailable for loads that have
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Idaho Power Company
the potential to have variable usage.With this
additional language, customers taking service under
Schedule 40 who modify their existing equipment such that
it has the potential for variation in usage or who
install additional equipment that has the potential for
variation in usage will no longer be allowed to take
service under Schedule 40 and will be transferred to the
appropriate metered service schedule.
What the present rate structure for Street
Lighting Service,Schedule 41?
Charges for Street Lighting Service are based
on a per lamp or per pole basis.Street Lighting is
divided into two types: 1) Company-Owned, and 2)
Customer-Owned.Schedule 41 does not allow new service
for incandescent, mercury vapor , or fluorescent fixtures.
Are you proposing any changes to the rate
structure for Schedule 41?
Yes, I am.The current rate structure for
Schedule 41 assumes energy is used only for the
illumination of street lighting fixtures from dusk until
dawn.However , because of the availability of wired
outlets or energized plug-ins on the lighting standard
it is possible for customers to use energy for other
purposes, such as illuminating holiday decorations.
order to accommodate customers who desire to use
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additional energy for non-street lighting purposes , the
Company is proposing to add a metered
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Idaho Power Company
service option under Schedule 41.Customers who utilize
plug-ins on Company-owned facilities or who have wired
outlets or plug-ins on customer-owned facilities will be
required to have metered service.
Is the Company changing its standard to the
cut-off or shielded fixture?
Yes.The Company is changing its standard
light luminaire from a drop-down lens fixture to a flat
lens or cutoff fixture.The Company plans to use its
existing inventory of drop-down lenses until it is
exhausted or until March 1, whichever comes sooner.
Beginning March 1 , 2004 , the cutoff fixture will be used
excl usi vely.I have added language to Schedule 41 that
addresses the accelerated replacement of drop-down lens
fixtures with cutoff fixtures for those customers who are
interested in converting to the cutoff fixture more
rapidly than would normally occur through standard
maintenance.
Is the Company proposing changing the wattage
of fixtures available under Schedule 41?
Yes.The Company is adding a 70-watt high
pressure sodium vapor lamp.This size lamp has been the
most requested lamp from customers who have enacted "Dark
Sky " requirements.In order to minimize inventory and
better meet customer requests, the Company is proposing
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Idaho Power Company
no new service for the 200-watt high pressure sodium
fixture
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Idaho Power Company
and the addition of the 250-watt high pressure sodium
fixture to the Company-owned options.These changes will
result in the same wattage lamps being available for both
Company-owned and customer-owned systems.
Are you proposing any other changes to Schedule
41 ?
Yes.I am proposing what I consider to be two
housekeeping changes.First, Schedule 41 currently has
language specifying that underground circuits can be
installed if the customer pays a monthly Facilities
Charge of 1.75 percent times the cost difference between
overhead and underground installation charges.This
language is no longer applicable with the Company
current Rule Under the provisions of Rule H
customers are responsible for paying the total cost of
any additional facilities required, either overhead or
underground, to provide service.Therefore, I am
proposing this language be deleted.
will this change eliminate the monthly
facilities charge for customers who previously requested
underground circuits?
No.Customers who previously agreed to pay a
monthly facilities charge for the installation of
underground facilities will continue to pay the charge.
Q. What is the second housekeeping change being
proposed?
857 BRILZ , DI
Idaho Power Company
Schedule 41 currently has language stating that
the services provided by the Company for customer-owned
systems include the replacement of defective ballasts.
With the current design of lighting fixtures, the
ballasts are no longer separately replaced.Rather , the
entire fixture is replaced.Therefore, I have removed
the reference to the replacement of defective ballasts
from the section describing the services performed by the
Company for customer-owned systems.
What is the revenue requirement to be recovered
from customers taking service under Schedule 41?
Based on Mr. Gale I s Exhibit No. 61 , the annual
revenue requirement for Schedule 41 is $1 899,531.
Please describe the rate design proposal for
Schedule 41.
Rates are designed for both non-metered and
metered service.Customers who take non-metered service
will continue to pay a monthly per-lamp charge depending
on the wattage of the fixture installed.Customers who
take metered service will pay a monthly per-lamp charge
depending on the wattage of the fixture installed , a per
kWh charge for each kWh of metered usage, and a monthly
meter charge.
How were the per-lamp charges determined?
As a starting point, the average unit cost for
858 BRILZ , DI
Idaho Power Company
the fixture, bulb , and photocell was determined for each
lamp type and wattage using the information available in
the Company I s property records.Sales tax , Company
overheads, and labor expense were then added to the
average unit cost to derive a loaded facilities-related
cost.The monthly per-lamp facilities-related charge was
derived by multiplying the loaded fixture cost by 1.
percent (the monthly facilities charge rate) .For
non-metered service, the total monthly charge per lamp
equals the monthly per-lamp facilities-related charge
plus the applicable amount for the per-lamp energy
consumption.For metered service, the monthly charge per
lamp equals the sum of the monthly per-lamp
facilities-related charge plus the metered kWh times
6619 per kWh plus the $8.00 per month meter charge.
The specific rate design proposal for Schedule 41 is
included on pages 15 through 18 of Exhibit No. 43. I have
included in my workpapers details on the average unit
cost for each fixture , bulb , and photocell and the
derivation of the loaded facilities-related cost.
What is the present rate structure for Traffic
Control Signal Lighting Service, Schedule 42?
Customers taking service under Schedule 42 pay
a flat Energy Charge for each kWh of estimated energy
use.Usage is estimated based on the number and size of
859 BRILZ, DI
Idaho Power Company
lamps burning simultaneously in each signal and the
average number of hours per day the signal is operated.
There is no
860 BRILZ , DI 78a
Idaho Power Company
minimum charge under Schedule 42.
What is the revenue requirement to be recovered
from customers taking service under Schedule 42?
Based on Mr. Gale I s Exhibit No. 61 , the annual
revenue requirement for Schedule 42 is $320,719.
Please describe the rate design proposal for
Schedule 42.
The rate design proposal for Schedule 42 is
included on page 19 of Exhibit No. 43.The Energy Charge
is increased from 3.1059 per kWh to 3.4959 per kWh.
Is the Company proposing any other changes to
Schedule 42?
Yes.Over the past several years the Company
has experienced an increase in the number of traffic
lighting systems that utilize LED bulbs, traffic sensors
and camera monitoring.The wide variety of wattages
available in the LED bulbs as well as the variability in
operating hours for the red, green , and amber bulbs
facilitated by the presence of traffic sensors and
cameras makes it difficult to accurately estimate the kWh
consumption at each intersection.In order to eliminate
this "guesswork", the Company is proposing that all new
traffic control signal lighting systems installed on or
after June 1, 2004 be metered to record actual energy
consumpt ion.
861 BRILZ , DI
Idaho Power Company
Will traffic control signal lighting systems
installed prior to June 1, 2004 be required to be
retrofi tted to allow metered service?
No.Systems installed prior to June 1 , 2004
may be retrofitted with meters upon the mutual consent of
the Company and the customer.However , the Company is
not proposing at this time that existing systems be
required to convert to metered service.
SPECIAL CONTRACT CUSTOMERS
What are the Company's rate design proposals
for its special contract customers?
Other than the proposal which I described
earlier to eliminate the monthly O&M charge paid by
Micron and incorporate the costs associated with the
substation facilities into Micron's standard charges , the
Company is not proposing any changes to the rate
structures for Micron, J. R. Simplot Company, and
DOE/ INEEL .Accordingly, the existing rates for the
special contract customers are simply increased uniformly
to recover the revenue requirement as shown on Mr. Gale I s
Exhibit No. 61.The rates for Micron , J. R. Simplot
Company, and DOE/ INEEL are shown on pages 20 , 21, and 22
of Exhibit No. 43 , respectively.
STANDBY AND ALTERNATE DISTRIBUTION SERVICE
Q. Are any customers currently taking service
under Schedule 45, Standby Service?
862 BRILZ , DI
Idaho Power Company
No, there are no customers taking Schedule 45
service.
Are any revisions to Schedule 45 being
proposed?
The Schedule 45 charges are being revised to
reflect the updated cost information resulting from the
cost -of - service study.However , no other changes are
being made to Schedule 45.
Have you prepared an exhibi t showing the
derivation of the updated charges for Standby Service?
Yes.Exhibit No. 47 details the derivation of
the updated charges.The updated charges have been
deri ved using the same methodology approved by the
Commission in the Company I s last general rate case, Case
No. IPC-94-
Are any customers currently taking service
under Schedule 46, Alternate Distribution Service?
No.
What changes are being made to Schedule 46,
Al ternate Distribution Service?
The Schedule 46 Capacity Charge is being
updated from $1.26 per kW to $1.30 per kW to reflect the
current cost of providing Alternate Distribution Service.
The $1.30 amount is derived by summing the Distribution
demand revenue requirement for Substations, Primary
863 BRILZ , DI
Idaho Power Company
Lines, and Primary Transformers for Schedule 19 shown on
page 5 of Exhibit No. 42 ($1 577 379; $3,205,775; and
$274 457 , respectively) and dividing this sum by the
total billed kW of 3,903 470.This methodology is the
same as that approved by the Commission in the Company '
last general rate case, Case No. IPC-94-
MI SCELLANEOUS CONTRACTS
What are the miscellaneous contracts under
which the Company is providing service?
The Company has entered into contracts with two
customers to provide customized service otherwise
provided under standard service schedules.First, the
Company is providing standby service to the Amalgamated
Sugar Company under the provisions of a Standby Electric
Service Agreement dated April 6 , 1998.Second, the
Company is providing street lighting service utilizing
cut-off lighting fixtures to the City of Ketchum under
the provisions of an Electric Service Agreement dated
June 12 , 2001.Both of these agreements have been
approved by the Commission.
Are you proposing any changes to the standby
charges under the Standby Electric Service Agreement with
the Amalgamated Sugar Company?
Yes.I am revising the charges to reflect the
updated cost information resulting from the
864 BRILZ, DI
Idaho Power Company
cost -of - service study.The methodology used to update
the charges is the same methodology used to establish the
currently approved charges.Page 190 of Exhibit No. 48
shows the revisions to Schedule 31 to reflect these
updated charges.I have included details on the
derivation of the updated charges in my workpapers.
Are you proposing any changes to the Electric
Service Agreement with the City of Ketchum?
No.The Agreement with the City of Ketchum
includes a provision specifying that if any shielded
fixture provided under the agreement becomes available
through a standard tariff offering, either party may give
notice that they desire that shielded street lighting
service be continued under the standard tariff offering
and the Agreement will be terminated.Should the
Commission approve the Company I s revised Schedule 41, the
Company intends to provide notice to the City of Ketchum,
terminate the Electric Service Agreement, and provide
shielded service to the City of Ketchum under Schedule
41.
Does this conclude your testimony?
Yes , it does.
865 BRILZ , DI
Idaho Power Company
(The following proceedings were had in open
hearing.
MR. KLINE:And Ms. Brilz is available for
cross - examina t ion.
COMMISSIONER SMITH:Mr. Stutzman.
MR. STUTZMAN:Thank you, Madame Chairman.
CROSS-EXAMINATION
BY MR. STUTZMAN:
Ms. Brilz , at page 30 of your testimony,
you re discussing the proposal to change the name of the
customer charge to service charge.And you state starting
on line 9 that the current customer charge is intended to
recover costs that do not vary with the amount of energy
or capacity used.These costs include such item as a
portion of the investment in distribution facilities,
investment in meters, et cetera.Do you recall that
testimony?
Yes , I do.
How much is the current customer charge for
residential customers?
It is $2.51.
How much of that $2.51 is intended to
recover a portion of the investment in distribution
CSB REPORTINGWilder, Idaho
866 BRILZ (X)
Idaho Power Company83676
facilities?
The $2.51 is actually not tied specifically
at this point to any specific cost.It was established
back in the company I s 94 - 5 rate case.And at that point
we had identified a total cost , I believe, of about $17.
We recommended a 15 percent charge, which came to $2.51 to
recover some of those costs.So I cannot say specifically
that the $2.51 recovers a specific cost.You need to look
at the total components that we proposed to include in
that charge to see what the totality of the components
would be.
This Commission approved the $2.51 customer
charge?
Yes.
And when the Commission approved it, did it
indicate that it was to recover a portion of the
investment in distribution facilities?
I do not remember the Commission's wording
in the Order approving that charge.
Okay.Thank you.
MR. STUTZMAN:That I S all I have, Madame
Cha i rman .
COMMISSIONER SMITH:Mr. Richardson.
MR. RICHARDSON:Thank you, Madame
Chairman.
CSB REPORTING
Wilder, Idaho
867 BRILZ (X)
Idaho Power Company83676
CROSS -EXAMINATION
BY MR. RICHARDSON:
Ms. Brilz , would you turn to page 25 of
Now, on that page beginning on line 5 you
summarize the Company I s rate design obj ecti ves; correct?
CSB REPORTING
Wilder , Idaho
That is correct.
And you refer to Mr. Gale I s testimony as
your testimony?
addressing the Company's policy regarding pricing
obj ecti ves; correct?
Correct.
Is the policy for time-of -use pricing as
described by Mr. Gale in his direct testimony, has it been
approved and is it written anywhere in the Company policy
manual?
No, it is not written anywhere in any
policy manual at the Company.
Have you been instructed by Mr. Gale about
the Company s pricing policy on time-of -use rates?
Mr. Gale and I have had discussions
concerning the policy the Company wanted to pursue as far
as time-of -use rates go, yes.
And that policy's nowhere in writing in the
Company?
It is not written in a manual anywhere at
868 BRILZ (X)
Idaho Power Company83676
the Company.
Beginning on line 12 on page 25, you state
that it is the Company s policy to give customers price
CSB REPORTING
Wilder, Idaho
signals that reflect the variation in cost of providing
service during different times of the year and day.
I don I t say that it' s the Company s policy.
I say that it's one of the obj ecti ves we're striving to
And isn t that one of the objectives
instructed by the Company s policy?
Well , the Company' s overall policy guides
the objectives , yes.
But you re not implementing that policy
relative to time-of -day price signals for any class other
than Schedule 19; correct?
The Company has only proposed time-of-use
pricing for Schedule 19 customers in this proceeding,
In fact, at line 22 , page 25, you
state that only schedule 19 is being singled
That is correct.
you see that?
Is it a rate design objective for the
Company to implement time-of -use rates in this case for
achieve.
correct.
explicitly
out; correct?
869 BRILZ (X)
Idaho Power Company83676
any other class?
In this case, no.
Yes.
No.
Does the Company's rate design policy
regarding time-of-use rates require any studies or
analysis to be conducted to determine the cost and
benefits of implementing mandatory time-of-use rates for
any class before proposing such a rate in a general rate
case?
In determining the policy to pursue
time-of -use rates for Schedule 19 customers, the Company
looked at the overall obj ecti ves we were trying to achieve
with our system.And it fits with our objectives stated
in our 2002 IRP which was, the Company would pursue
pricing options that would help match what we were trying
to achieve through the resource obj ecti ves.
But the question was, does your policy
require that you conduct a study or analysis of the cost
and benefits of implementing a mandatory time-of-use rate
for any class before proposing such rates in a general
rate case?
Well, the study that the Company did was
looking at what it is we're trying to achieve with our
overall system and our resources, and determining what
CSB REPORTING
Wilder, Idaho
870 BRILZ (X)
Idaho Power Company83676
would be the best way to try to approach that.And
through those discussions it was determined that the best
way to proceed was to propose time-of-use pricing for
Schedule 19 customers.
So you reference a study and then you
describe that study as "those discussions"m trying to
just ask a very narrow question.And that is, did you
conduct a study of the costs and benefits of time-of-use
rates for the Schedule 19 for this case?
If you are asking did we conduct a study
that tried to identify specifically what types of impact
any load shifting might have as far as impacts to the
system, no.
Okay.Now , I'm confused because I was not
asking about a study on time-of-use rates and you said a
study on load shifting.Is that the same thing in your
mind?
m not sure what you re asking about as
far as a study.m trying to let you know that we I ve
discussed what our obj ecti ves are and what we felt was the
best proposal to meet those obj ecti ves.m not clear on
what you ' re expecting as far as a study, what that might
be.
Why don't you describe for me the
discussions that you've had.What went on inside the
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Wilder , Idaho
871 BRILZ (X)
Idaho Power Company83676
Company, the universe of things that went on inside the
Company, that led you to propose mandatory time-of -use
rates for the industrial class?
You referenced discussions.Let's start
wi th those.
Okay.In looking at what we wanted to do
to meet our pricing obj ecti ves, which is to match price
wi th cost, so we want to establish rates that are based on
And we want to give customers price signals thatcost.
indicate the different cost of providing service during
different times of the year.We've discussed ways that we
can make that happen.Included in those discussions we
look at what we committed to in our resource planning
process and determined that the best proposal that we
should put forth at this point is a mandatory time-of-use
pricing proposal for Schedule 19 customers.
Did you analyze the impact of that proposal
on the Schedule 19 customers?
We have, through working wi th our
individual customers , identified what each individual
customer might experience with time-of-use rates.For the
Company as a whole it's revenue neutral.
Prior to filing your case, did you analyze
the potential impact of time-of-use rates on the Schedule
19 customers?
CSB REPORTING
Wilder , Idaho
872 BRILZ (X)
Idaho Power Company83676
Prior to filing, yes, we did.
With each individual Schedule 19 customer?
We looked at the impact on each individual
customer prior to filing our case.
Now , isn't it true that the only reason you
selected Schedule 19 for time-of -use rates, and not other
schedules, is that they have the metering in place to
allow the imposition of those rates?
No, that is not the only reason.
What are the other reasons you selected
Schedule 19 and not other classes for the imposition of
time-of-use rates in addition to the fact they happen to
have the metering in place?
Schedule 19 customers have a load size that
provides meaningful opportunity to address some of the
issues you try to get through time-of -use pricing.What
we I re trying to do is match more closely the cost of
providing service with the price offered customers.
Schedule 19 customers have a better ability to understand
that connection.It is not uncommon for customers the
size of Schedule 19 customers to be required to take
time-of -use pricing in various parts of the country, and
throughout the West.And we took those considerations
into account.
Wouldn't customers like your special
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Wilder , Idaho
873 BRILZ (X)
Idaho Power Company83676
contract customers also fit that bill?
Special contract customers could.But
you re trying to get a specific amount of revenue from a
particular customer class.It wouldn' t make any
difference to them whether it's a flat rate or a
time-of -use rate because they operate basically on a
constant basis.
So you don't anticipate any time of use
price signal benefit to a special contract customer?
Not at this point.
So special contract customers don t have
any ability to shift loads to less expensive times of day?
Well, the Company is not proposing at this
point that they do have the ability.We're not proposing
that we have any type of time-of -use pricing for schedule
19 customers.Whether they have the ability to shift I do
not know.
I missed part of that answer.Could you
repeat it please?Maybe if you spoke a little closer to
the microphone.
Okay.
Tha t woul d be helpful.
We don I t have any plans this point as
part of this proposal to recommend time-of-use pricing for
special contract customers.
CSB REPORTING
Wilder , Idaho
BRILZ (X)
Idaho Power Company
874
83676
And the reason for that is because why?
It didn't fit with what we were planning to
put forth in this proposal.What we wanted to do is
target our Schedule 19 customers as a group to implement
time-of -use pricing.
And did I hear you correctly say that the
special contract customers do not have the ability to take
advantage of the benefits, if you will , of time-of-use
rates?
I don't know if they have the ability to
take advantage of time-of -use rates.
And you re aware that the Schedule 9 class
has actually asked that you put , at least on a voluntary
or pilot program basis, time-of -use rates in place for
them?
Yes.
And ye t you chose to go with the Schedule
19 class.Can you tell me why you did that opposed to
going wi th a class that was actually asking for such
rates?
Well, again , I think I've answered.
targeted the Schedule 19 customers because it fit with our
obj ecti ve of trying to identify a group of customers that
we feel is able to manage the pricing, understand the
pricing, and they have the ability to record the usage.
CSB REPORTING
Wilder , Idaho
875 BRILZ (X)
Idaho Power Company83676
You mentioned the metering is an aspect of it.And it fit
wi th our obj ect i ve .
Do your obj ecti ves also - - are Schedule 9
customers also able to manage their loads?Is that too
small of a load class to be beneficial?What I s the
distinction between the two classes in terms of
implementing your time-of-use policy?
Well , I believe it should be taken in
I recognize that anytime you add a new pricingsteps.
structure it requires more assistance with your customers
working through some of the communications and
understanding.And we want to take the implementation in
steps.
Do you propose the elimination of
residential level pay plans?
I haven't addressed level pay in anyNo.
part of my testimony.
And the Company has a residential level pay
plan place;correct?
That correct.
And how does that jive with your policy of
sending price signal s?
The customers on the level pay would still
get their information each month indicating what their
actual bill was.The level pay is put in place to help
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
876
83676
facility the paYment of bills for residential customers.
The level pay plan basically averages last
year I s bills, maybe taking into account intermediate rate
changes, and just divides by 12; right?
I don t have the specific algorithm but
basically that I s the idea.
Basically that I s the idea.Doesn I t that
eliminate price signals in terms of what the customer pays
each month and seasonally for electricity?
Well , the customer still sees on each
monthly bill what the actual charge is for that month.
They just are asked to pay the level pay amount as, again
as I stated, to help in the bill paying process.They
still get the information.
Would you agree with the characterization
that the imposition of time-of-use rates on Schedule 19
that's it radical change?
I don't think I would define it as radical.
I definitely would say it's a change.
Would you agree that a proposed increase in
rates of 500 percent is a radical change?
It I S a large increase percentage, yes.
Would you characteri ze it as rate shock?
When you take the -- if all by itself, it
would be a large increase.
CSB REPORTING
Wilder , Idaho
BRILZ (X)
Idaho Power Company
877
83676
What about a proposed rate increase of 9000
percent.Is that radical?
CSB REPORTING
Wilder , Idaho
Again , taken in isolation, it I S a large
And you would say that would be rate shock,
too, wouldn t you?
If it was the only component that you were
talking about, you could say it would be, yes.
Would you agree with that changing from a
single demand charge and a single energy charge to three
different demand charges and five different energy
charges, constitutes a radical change?
Again , I wouldn I t classify it as radical.
I would say it is a change.
And are you proposing to increase the
factor for this class from 85 percent to
Yes.
And are you proposing to change the
anniversary date for all of Schedule 19 customers, the
contract anniversary dates?
We have proposed a change in the way in
which we conduct the annual review for each of our
customers on schedule 7 , 9 and 19.
And are you proposing to abolish all the
increase.
minlmum power
percent?
878 BRILZ (X)
Idaho Power Company83676
existing uniform large power service agreements and
require all Schedule 19 customers to enter into new
uniform service agreements?
We have proposed to eliminate the
requirement to sign a uniform large power service
agreement as a condition for taking service on Schedule
And in its place have customers sign a service19.
agreement that would guarantee a level of capacity
available to those customers.
All of these changes that I've just listed
are being proposed for this customer class in one rate
case.
Don t you think cumulatively that all of
these changes combined add up to a radical change in the
Schedule 19?
I wouldn't say that it was radical, no.
Now, you made a correction earlier in your
testimony on page 46 where you changed 7: 00 a. m. 9: 00
m. to 7:00 a.Do you recall that?
Uh-huh , yes.
Now, would you agree that the more
complicated a system is the more likely there will be
errors in implementing it?
The more complicated something is the more
potential there would be if there s misunderstanding.
CSB REPORTING
Wilder , Idaho
BRILZ (X)
Idaho Power Company
879
83676
Correct.With all the vetting and editing
and review your testimony endured before you file it with
the Commission, even you made an error in implementing
time-of -use rates for Schedule 19 customers.
There was a typo in my testimony, yes.
Do you know what a rate scavenger is?
m afraid I don't.
Would you accept that a rate scavenger
is a term used by some utilities with complex time-of-use
rates, to describe individuals who, for a percentage of
the take, do nothing but review utility bills for errors.
They obtain agency status from large companies and then go
to the utility and review in detail billing records for
errors.
Does Idaho Power have any experience with
such individuals now?
I am not aware of any rate scavengers
approaching Idaho Power, no.
Would you expect to see them appear on the
horizon if you implement a complex time-of-use rate
structure such as you have proposed?
I have no idea.
Does your proposal to increase the service
charge from $5.54 for secondary and $85.71 for primary,
and transmission Schedule 19 customers to $500 include a
CSB REPORTING
Wilder , Idaho
BRILZ (X)
Idaho Power Company
880
83676
monthly automated meter reading charge of $365?
m not sure what you're asking.Could you
ask that again?
Do the proposed service charges include a
$365 charge for monthly automated meter reading for
Schedule 19 customers?
I would have to double-check to see if any
component was in there for that.I don't know the number
specifically that you re referring to.
Does your Exhibit 42 show that a
residential meter only costs $1.55 to read manually each
month?
Could you direct me to where you I re
looking?
I can if you give me a second.I think
it's page 1 of Exhibit 42, line 281.
That line shows a monthly cost of $1.
associated with the meter reading function for residential
customers.
And on page 4
- -
page
excuse me,line 7 0 1 see that costs the Company
$365 read an industrial customer meter automatically.
That line shows $365.70 for the meter
reading function for Schedule 19 customers, yes.
Do you find it a bit odd that it costs 200
CSB REPORTING
Wilder , Idaho
BRILZ (X)
Idaho Power Company
881
83676
times more to automatically read a Schedule 19 meter, than
it does to manually read a residential meter?
No, when you look at the totality of what'
included in the meter-reading function.
Could you explain some of that totality to
us?
That includes the phone lines thatYes.
are attached to each of those meters.It includes
personnel who are dedicated to managing the meter-reading
function on a daily basis, gathering the electronic
information , processing the information, and providing it
to the company s billing system.
How many Schedule 19 customers do you have?
About 105, 106, in that area.
Do you anticipate that this function
going to get a lot more costly reading these meters for
time-of-use rates?In other words, it costs 300 bucks to
read a single industrial customer s meter now
automatically.And you're going to impose three different
demand charges, and five different energy charges, and
depending on the day of the week , the month of the year
and the hour of the day, you might have a different rate.
That I s going to get pretty complicated for this person or
people who are current charging this $360 or whatever a
month to read a meter.
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
882
83676
Actually, the software will be modified to
be able to translate the meter readings that come through.
So once the system modifications have been done, although
there may be initially with verification and checking some
additional time involved, I wouldn I t anticipate there
would be any significant change in the cost going to
time-of -use metering - - time-of -use rates.
Later on at a point in your testimony you
talk about changing the voltage factor from 85 to 90 and
say, well , giving the customer a chance to get used to
that you suggested a sort of a grace period of until
November to implement that.Do you recall that?
Yes, I do.
Now , would you agree that going to
mandatory time-of-use rates potentially is, for many of
these customers , more radical than going to 90 percent
vol tage factor?
I couldn't presume what individual
customers might expect.
Pardon?m sorry?
I couldn I t presume to guess what they might
anticipate or perceive.
Did you ever consider doing some sort of
grace period where the Industrial Customers are on their
flat rate , not time of use, but billing them sort of dummy
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
883
83676
bills as if they were under time of use so that they could
have the opportunity to attempt to get used to how to
operate their plant under time-of-use rates?
, did not anticipate that.
Do you think that might be something the
Industrial Customers would like?
I don't think that it's necessary given the
information that we've provided our customers.I believe
that they re very capable customers, able to understand
the pricing, and will be able to know what's going on and
understand.
Do you think the fact that I'm sitting here
asking these questions suggests , perhaps, something else?
No.
Does the Company propose any changes to its
line extension policy for Schedule 19 customers?
The Company has proposed no changes toNo.
its line extension policy.
Do you recall Mr. Teinert' s testimony
questioning the company s line extension policy for
Schedule 19 customers?
I do.
And do you know whether the Commission
Staff that a docket be opened for the purpose of
clarifying the line extension policy and the schedule 19
CSB REPORTING
Wilder, Idaho
884 BRILZ (X)
Idaho Power Company83676
tariff in a different proceeding than this?
m not aware of any recommendation.
If the Company s line extension policy
caused - - overestimates the customer's ultimate load,
could that fact increase the contribution in aid of
construction the customer pays the Company?
The Company s line extension policy, as far
as I am aware, does not have any implications for
contributions in aid of construction in what I'
prepared.
Now , you referenced earlier , I may have
mischaracterized it, but the power factor minimum from
to 90 percent.And you proposed it to that because the
Company is - - the delivery system is constrained; is that
correct?
The Company I s required to operate its
delivery system at unity power factor.Our proposal to
increase the requirement for Schedule 19 customers from
percent to 90 percent just simply moves the requirement
that the Company currently faces closer to or requires
customers to get closer to that requirement than the
Company currently faces.
Do you recall the Company's response to the
Industrial Customers' first production request No. 48
inquiring as to whether or not the Company s reliability
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
885
83676
indexes have shown a steady improvement in the last
several years?
I don't recall that I saw that response.
Would you agree with me that a steady
improvement in reliability indexes is or is not an
indication of a constrained delivery system?
m going to obj ect .I thinkMR. KLINE:
this is beyond the scope of her examination
- -
of her
direct testimony.
COMMISSIONER SMITH:Mr. Richardson.
MR. RICHARDSON:I'll withdraw the
question, Madame Chairman.
BY MR. RI CHARDSON :
Have the Industrial Customers Schedule 19
customers paid an energy efficiency rider under Schedule
91 since the inception of Schedule 91?
Yes.
And did the Company discontinue industrial
conservation programs for Schedule 19 back in 1997?
Yes.
And did the Company begin again
- -
- did
the Company only begin again administering industrial
conservation programs for Schedule 19 customers in October
of 2003?
That is correct.
CSB REPORTING
Wilder, Idaho
BRILZ (X)
Idaho Power Company
886
83676
That happens to coincide with the month
that you filed this general rate case?
Coincidentally, yes, it does.
Did any of the energy efficiency fund
charges collected from Schedule 19 go to programs
administered for Schedule 19 customers prior to October of
2003?
No.
Given the Company's absence of an
industrial conservation program until just last October,
is it reasonable for the Schedule 19 class to request that
funds generated by their Schedule 91 energy efficiency
fund charges be self-directed to conservation programs in
their facilities that are served by Idaho Power?
I believe the way that the Schedule 91
rider funding mechanism has been set up now is an
appropriate way to collect funds, and manage funds, and
utilize funds, for an energy conservation program.
And at page 31, you state that in order to
gi ve customers time to get used to the new power factor
from 85 to 90 you re proposing a grace period until
November.Since some Industrial Customers are highly
seasonal like the Amalgamated Sugar Company, which really
doesn t get going until the fall , would you agree that a
longer grace period would be more appropriate like, say, a
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Wilder , Idaho
BRILZ (X)
Idaho Power Company
887
83676
full year?
I don't believe a longer grace period is
needed.Customers who have powe r factor issues right now
know who they are.We have been able identify them,
can work with them between now and November and be
prepared to address the issue.I don't think an
addi tional time frame is necessary.
Well if a customer has an 88 percent power
factor right now,that customer doesn'have a power
factor issue with you right now.
No.But customers know what their power
factors are.
But it will have an issue with you after
November 1st?
Correct.
Isn t it true that the Company uses weather
normalized energy for resource planning in the calculation
of revenue requirements?
m not sure what the Company uses for
resource planning.For our cost-of-service modeling we
use normalized energy values.
And why do you do that?
It's an attempt to capture what would be
expected on a normal basis in any given year.
Now , don t you think that this case
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Wilder, Idaho
BRILZ (X)
Idaho Power Company
888
83676
presents the Commission with a substantial change in the
load profile because rate payers are being asked to pay
increased fixed charges for peaking generation plants
based on peak needs?
The proposals that we put forth have
identified costs by customer class based on the loads they
impose on the system at various times of the year.
Okay.Thank you.
Madame Chairman, that'MR. RICHARDSON:
all I have.
COMMISSIONER SMITH:Thank you, Mr.
Richardson.
Mr. Miller , it looks like you want
to jump in here.
MR. MILLER:I would , if the Commission
would permit, just a few questions on a couple of topics.
CROSS - EXAMINATION
BY MR. MILLER:
Ms. Brilz , the first topic I wanted to
introduce, although I don't think we can pursue it to
conclusion, we have to wait for your rebuttal to discuss
it further, has to do with the different service levels
wi thin Schedule And I believe your testimony and your
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Wilder, Idaho
BRILZ (X)
Idaho Power Company
889
83676
direct testimony in that area is found on page 40 and 41
of your direct testimony.
And while the parties are finding their way
to that testimony, let me just ask you some general
background questions.
As I understand it within Schedule 9 there
are actually three different service levels.There'
primary, secondary, and - - there's transmission , primary
and secondary.Could you briefly explain for the
Commission the difference in eligibility requirements for
the three service levels?
Customers taking transmission serviceYes.
under Schedule 9 own their own substations and we deliver
power right to the substation.They then take service at
the substation.
Primary service level customers receive
service at a primary voltage either 12-5 or 34-5 and we
deliver basically to the property line and the customer
then owns all of the facilities past that point of
delivery or pay a facility charge to Idaho Power for use
of those facilities.
Secondary customers take service at a
secondary voltage and generally we provide the service
right there to their business, right outside their
business.
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Wilder , Idaho
BRILZ (X)
Idaho Power Company
890
83676
wi th respect to the primary customers you
indicated that many of them have company-owned facilities
beyond the point of delivery for which they pay a monthly
facility charge.
That is correct.
And the, as I understand it, and correct
me, the revenue from those charges flows back through
somehow the cost-of-service study to reduce the revenue
requirement for that class?
Tha t is correct.
with that background then , I'd like to
direct your attention to page 41, starting at line
where you indicate that the cost-of-service study
indicated an increase in revenue of 8 percent for
secondary customers, but a 24 percent increase for primary
and transmission service level customers.
Given the, I don't want to say modest
differences between the three service levels, and also
given that it appears that intuitively I think the primary
ought to be less expensive to serve than the secondary,
the result of your study appears, let me just suggest, to
be counter intuitive.That is, why is there a 24 percent
increase for primary and an 8 percent increase for a class
that intuitively is more costly to serve?
Then , as I say, I think we 'll get into this
CSB REPORTING
Wilder, Idaho
891 BRILZ (X)
Idaho Power Company83676
further in your
- -
when we get to rebuttal and see some of
the other witnesses, but just to introduce topic, could
you try and explain for me and the Commission that
apparent counter-intuitive result?
That goes back to when we established
service levels, which was at the conclusion of the 94-
case.What we were attempting to do was meet several
obj ecti ves specifically re+ated to what we were seeing as
issues between customer right on the cusp there as far as
their load size goes for qualifying for Schedule 19.What
we wanted to do in establishing service levels was create
an easier way for customers to move back and forth between
Schedule 9 and 19 without introducing a number of
administrative issues.So when we established the service
levels we looked at the similarity between the schedule
and the larger Schedule 9 customers that would become the
first group of Schedule 9 primary service level customers.
And identified that for many
- -
in many instances they
were very, very similar in that we provide service to a
primary point of delivery and they take service at that
point either owning or paying a facilities charge on all
of the facilities beyond the point of delivery.
The specific rates that were set at the
conclusion of the 94-5 case were not based on a
cost-of-service modeling but rather looking at some
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Wilder, Idaho
892 BRILZ (X)
Idaho Power Company83676
obj ecti ves we were trying to meet in establishing rates
that seemed reasonable at the time to create this new
service level concept.
As we have had experience now with
customers on Schedule 9 primary, and in fact we have more
customers on Schedule 9 primary service than we do
Schedule 19 we have been able to look at the specific load
characteristics of those customers and in this particular
instance have included them as a class within the
cost-of-service modeling and have more specific results
now for that particular group of customers.
Okay.Well , I think that introduces the
topic and we'll come back to it after we've seen other
witnesses testimony on this topic as well as yours.So,
thanks for the introduction.
Just one other area.When you were
preparing your cost-of-service study were you instructed
by senior management to jigger the results in such a way
that showed a larger deficiency for the irrigation class?
No.
Did you undertake on your own initiative to
jigger the results of the study for those purposes?
No.
Is the cost -of - service study as presented
part of the some plan or scheme to favor urban customers
CSB REPORTING
Wilder , Idaho
893 BRILZ (X)
Idaho Power Company83676
at the expense of the agricultural class?
No, it is not.
What did you undertake to accomplish with
your cost -of -service study?
We were attempting to identify by each
customer class, the cost to serve that customer class.
And is that
- -
that was your goal.And are
you relatively satisfied that you accomplished it?
CSB REPORTING
Wilder , Idaho
Yes, I am.
MR. MILLER:Those would be all my
questions, Madame Chairman.
questions?
BY MR. PURDY:
COMMISSIONER SMITH:Mr. Ward, do you have
MR. WARD.Thank you.No questions.
COMMISSIONER SMITH:Mr. Gollomp.
MR. GOLLOMP:No questions.
COMMISSIONER SMITH:Mr. Purdy.
MR. PURDY:Just briefly, Madame Chairman.
CROS S - EXAMINATION
Ms. Brilz , could you turn to page 30 of
your direct testimony, please?
you see that?
Specifically line 10.
894 BRILZ (X)
Idaho Power Company83676
Yes.
You were asked a question about this
earlier but I just want to focus in on a few select words
starting with , costs that do not vary with the amount of
energy or capacity used.
Now , in the context of that question and
answer, is that just another way of saying fixed costs?
Essentially, yes.
Okay.And is that consistent with the
policy that I believe Mr. Gale has testified to, which is
to try to recover fixed costs through fixed charges?
Yes.
All right.Again , I don't want to go
beyond the scope of your direct.We'll save my further
questions on that area for rebuttal.
The only other question I had, had to do
with a couple of questions Mr. Richardson asked you about
the residential class level pay program.
And my first question is, do you have any
idea what percentage of residential class customers take
advantage of that program?
I do not.Off the top of my head, no.
don't know.
Would you say it's intuitive that it'
probably most desirable for people who have a hard time
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Wilder , Idaho
895 BRILZ (X)
Idaho Power Company83676
paying their monthly power bills?
It's most desirable for people who want to
level out their paYments and know what they can expect on
a monthly basis.
Okay.But you don't have any idea what
percentage of the class , again , takes advantage of the
program?
I don't.
Okay.Ultimately, though, if I understand
your testimony correctly, a customer who's taking
advantage of the program over whether it's a six month or
twelve month cycle , will pay their full bill for the year?
That is correct.
So with respect to sending a proper price
signal, while it allows them to level out the monthly
paYment, ultimately they still pay, if you have a seasonal
rate in place for example, they'll still pay that higher
seasonal rate.
They will pay that higher seasonal rate and
each month they'll see the actual charge for that
particular month.
They see that on their bill?
They see it on their bill.
MR. PURDY:Okay.That's all I have.
Thanks.
CSB REPORTING
Wilder , Idaho
896 BRILZ (X)
Idaho Power Company83676
COMMISSIONER SMITH:Mr. Eddie.
MR. EDD IE:Thank you.I do have a few
questions.
CROSS-EXAMINATION
BY MR. EDDIE:
Ms. Brilz , if you could go to page 26 of
your testimony.I assume you're in accord with Mr. Said
on this that Idaho Power does have a dual capacity
constraint throughout the year , summer time as well as
November and December?
I missed the first part of your question.
That you simply agree that there is a peak
period of capacity constraint in November and December?
We have capacity needs, yes, in June, July,
August , November , December.
Why did the Company not propose some sort
of price signal to address that winter time peak?You
proposed a summer time rate for residential customers but
no similar rate for that November-December peak?
The June , July, and August time frame has a
more significant peaking issue.And it is what comes up
repeatedly in looking at when do we need specific
resources.And we determined that that would be a better
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Wilder, Idaho
897 BRILZ (X)
Idaho Power Company83676
approach to target the summer months as opposed to
identifying a two-month time frame at the beginning of the
winter season.And so we decided to stick with the three
summer months as the target.
But it's different, different societal or
physical factors that are driving different peaks.
other words , the winter peak is driven by winter heating,
whereas the summer peak is driven by air conditioning and
irrigation load; correct?
The winter peaking has more of a space
heating component to it, yes.
Is it fair to say that the winter peak is
not addressed by the Company I s pricing program , pricing
proposal in this case?
We have not proposed any pricing that
addresses the winter peak.
Okay.I think we'll come back to that on
rebuttal but why don't we change
- -
if you could look at
page 4 of your testimony.
Really, page 4 and 5 , but on page 4 , I believe
Mr. Stutzman asked you about this, but you included as an
example of customer related costs
- -
down at the bottom of
page 4 - - that there's a portion of the investment
associated when distribution facilities are included.
Physically what are you talking about?
CSB REPORTING
Wilder, Idaho
898 BRILZ (X)
Idaho Power Company83676
What portion of distribution facilities are you talking
about that are related, that are customer related?
Okay.Potentially all components of the
distribution system have a customer component to them.
Meaning that you need to install and build your facilities
to meet some component of having a customer there whether
the customer takes service or not in any particular point
in time.
So if you were to look at other parts of my
testimony, you would see that it includes basically
components of substations, transformers , lines, other
components of the system including meters, meter reading,
and customer assistance expenses.
Couldn't you say that all the assets of the
Company that serve its system are customer related to some
extent because customers are who you're selling to?
Generally you don't look at trying to
identify a customer component at investments above the
delivery system or the distribution system.Generally
it's the distribution system that you look to identify a
customer component.
The distribution facility that you
identified , I presume you're talking about your Exhibit
, the list of different components of the distribution
system?
CSB REPORTING
Wilder , Idaho
899 BRILZ (X)
Idaho Power Company83676
Exhibit 42 does show that, yes.
That list of items, and I believe it'
roughly lines 265 through 274 , on page 1 of Exhibit 42
those lines , for example, serve multiple customers.For
example, primary customer lines.Would that, the next
line, 266 , would that serve more than one customer?
Yes.
Are there any of these in line 265 through
274 that serve only one customer?
No.Not at the residential level.
Thank you.You note on page 5 of your
testimony that in designating the different types of costs
the Company looked to the electric utility cost of a
station manual picked by the National Association of
Regulatory Commissioners as a primary guide for that
classification.Is there any other documentation you
looked to in designating those customer-related charges?
Not any published documentation , no.
relied historically on what we've traditionally done in
looking at the NARUC guide.
Okay.Turning to page 36 of your
testimony, if you would.You note that Exhibit 42 , which
is at the top of page 36, that Exhibit 42 , the analysis
reflected therein show a cost of service result of $24.
for the residential class.And that $10 is 40 percent of
CSB REPORTING
Wilder, Idaho
900 BRILZ (X)
Idaho Power Company83676
that amount.Why 40 percent?
In looking at what appeared to be
reasonable, we wanted to move towards what we'
identified as our cost.But we recognize that at times
you do need to take other considerations into account.
And it was our belief that moving to the full $24 from
$2.51 would be too great a move at one time.But that
moving to $10 would be a reasonable step to take at this
point.
So there's no magic in the 40 percent
number , it's arithmetic after you reached $10 from the
outset?
It's what appeared to be reasonable to us.
You mentioned just now that there are other
factors that are taken into account in analyzing the
change in rates.Could you mention some of those other
factors that might influence your decision of what amount
to request for a service charge as you have in this case?
Well , in this particular case what we took
into account was what the potential increase would be, or
the impact would be if we moved from $2.51 to $24 and
decided that that could be too much of an increase.Could
be perceived as rate shock.And that minimizing the
increase to the $10 would be a reasonable step at this
point.
CSB REPORTING
Wilder , Idaho
901 BRILZ (X)
Idaho Power Company83676
Was the potential disparate impact upon
low-usage customers versus high-usage customers one of the
factors you considered?
No.
Potential impact on low- income customers,
was that a factor you considered?
Not directly, no.
All right.m going to ask you just one
last set of questions about Exhibit 42.So if you could
turn to that, please.Page 1 of the Exhibit 42.
The Company receives other revenues apart from the sale of
kilowat t -hours; is that correct?
The Company receives other revenues for a
number of other activities that are undertaken , yes.
CSB REPORTING
Wilder , Idaho
For example, rental of pole space
Yes.
- - on distribution lines?
Yes.
What about connection and disconnection fee
charges to customers?
Those are also collected.
This is a fairly broad question and I'll
narrow it if you want me to, but what I'd like you to do
is explain for the Commission , and for the parties, how
those other revenues are treated on Exhibit 42.Are
902 BRILZ (X)
Idaho Power Company83676
there, for example , disconnect and reconnect fees?In my
mind, I would connect that type of revenue with most
likely line 278, install on customer premises.
Are all of the revenues associated with
disconnect and reconnect fees taken out of line 278 or are
they taken out some other way?
They're taken out on a more global basis.
They are entered into the process of determining the
overall revenue requirement for a customer class at a
higher level as opposed to at a specific functionalized
level that you see here on Exhibit 42.
And are the rental of space on poles to
other utilities or cable companies similarly treated?Not
taken out of the distribution network lines 265 through
274, but treated as a global detriment to the revenue
requirement?
Gi ve me a minute and let me look through
some of the other exhibits and I'll see if I can be more
specific for you.
Sure.
If you look at Exhibit 39, page 23, you
will see that we do have in that particular spreadsheet
where we allocate the other revenues by functional
category to the various customer classes , which ultimately
as you sum up the various components, will identify by
CSB REPORTING
Wilder , Idaho
903 BRILZ (X)
Idaho Power Company83676
functional category the overall revenue requirement that
is needed.
On Exhibit 42 what you see is what we
ul timately need to recover from customers from sales of
energy after we set the unit component cost.So the
components of other revenue have been taken into account
when you get to Exhibi t 42.And what Exhibit 42 is
attempting to show is what we need to collect from the
rate components themselves to recover revenue requirements
from the customer classes.
Let me ask you a similar question in this
way.If all of the revenues taken from , for example,
connection and disconnection fees were taken out of line
278 , install on customer premises , rather than spread as
you re articulating I think across the revenue
requirement, would that 20.7 cents reflected in column
of this line 278 be higher or lower?
Okay.First, I do want to clarify we do
not have disconnection charges.
Okay.
But any connection fees that we would
charge, if they were to all go to line 278 , the 20 cents
that you see there would be lower.
Okay.Similarly, if all of the revenues
and I'm not going to get too particular with you here
CSB REPORTING
Wilder , Idaho
904 BRILZ (X)
Idaho Power Company83676
but all of the revenues associated with the rental of pole
space to other companies such as cable companies or phone
companies, were taken out of the list of costs for
distribution networks would those figures in lines 265
through 274 , column I , be higher or lower than if the
revenues were spread across the entire revenue
requirement?
m not sure I'm understanding or following
you exactly on that.
Okay.The difficulty I'm having is that
there are nine lines for distribution and I presume that
all of them to some extent may serve for pole rental
space.
Yes.And what we have attempted to do in
the functionalization of the other revenues is attach the
revenue to the source of the revenue.So, for example, if
it is a pole attachment revenue , we attempt to give credit
to the pole investment function so that we're matching the
offset of the revenue with the investment that we have in
that facility that's generated the revenue.
And is that -- so are you saying that it'
treated differently in this instance?Is it treated
m sorry, I'm not articulating this question very well.
Are those rental revenue incomes treated differently on
the distribution system than , for example, the other
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Wilder , Idaho
905 BRILZ (X)I daho Power Company83676
analogy I made which is for connection fees which were
taken - - which could be taken out of install on premises
for example, line 278?
I believe that all of the other revenues
incl uding connection fees , pole rentals, any other revenue
classified as other is treated in similar fashion.
Okay.
MR. EDDIE:Nothing further.Thank you.
COMMISSIONER SMITH:Thank you , Mr. Eddie.
It's my intention, after I've asked my
three simple questions , to adj ourn for the day and come
back with Ms. Bril z in the morning.And Mr. Budge wi
cross-examine and then there will be questions from the
other Commissioners possibly.
EXAMINATION
BY COMMISSIONER SMITH:
Just so I have it clear in my mind today.
Ms. Brilz , with regard to the level pay, does that start
at a certain time of the year for every customer or is it
individualized for different customers?
My understanding is at this point that
customers can start on level pay at any point.Ms. Fullen
could probably confirm that for us, but that's my
CSB REPORTING
Wilder, Idaho
906 BRILZ (Com)
Idaho Power Company83676
understanding.
All right.I'll ask her that question.
You were discussing with Mr. Richardson -- no, was it Mr.
Miller , the primary service under Schedule 9
Uh-huh.
- -
as differentiated between secondary and
transmission service.
Uh-huh.
And it seemed to me that the conclusion
should draw from your answer was that essentially primary
service has been underpriced since the last rate case.
That is my conclusion.
And finally, did Idaho Power always have a
service charge as part of its rate structure?
No.Actually prior to the 94-5 case, we
had a minimum charge.And a service charge was adopted at
the conclusion of the 94-5 case.
And what do you see as the difference
between a minimum charge and a service charge?
A service charge is a component that is
billed the customer each month that attempts to recover
some component of cost that is there every month whether
or not the customer consumes electricity or not.And a
minimum basically sets a level that a customer is required
to pay if consumption doesn't match the quantity of energy
CSB REPORTING
Wilder , Idaho
907 BRILZ (Com)
I daho Power Company83676
included in that minimum.
So in other words, the minimum charge
includes some kilowatt-hours.And if you stay under the
cutoff point for the minimum charge, you just pay the
minimum?
That's correct.
COMMISSIONER SMITH:All right, thank you.
Let's start tomorrow morning at 9: 00 a. m.
Mr. Kline.
MR. KLINE:Might I inquire in light of the
fact that it's surprising to me that it's possible that
the Company will have its case submitted tomorrow , who
would then follow the Company s case?
COMMISSIONER SMITH:Well, as I said when
we began , I asked the Industrial Customers to be ready to
go on Wednesday if the Company s case had concluded by
then.
MR. KLINE:And if we concluded on Tuesday,
would they just go ahead and
. . .
MR. RICHARDSON:Madame Chairman.
COMMISSIONER SMITH:Mr. Richardson.
MR. RI CHARDSON :The Industrial Customers
would be prepared tomorrow to put on Dr. Reading and Mr.
Teinert.And Mr. Henderson would have to be here on
Wednesday because he's out of town.
CSB REPORTING
Wilder, Idaho
908 BRILZ (Com)
Idaho Power Company83676
COMMISSIONER SMITH:
might fill up our day.
MR. KLINE:
Okay.I think that
I think you're right.
COMMISSIONER SMITH:
adj ourned for the evening.
All right.We'
We'll see you all at 9:00 a.
(The Hearing recessed at 4:50 p.
CSB REPORTING
Wilder, Idaho 83676
909 COLLOQUY