20031021Brilz Direct (5.41MB).pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSIONIN THE MATTER OF THE APPLICATIONOF IDAHO POWER COMPANY FOR AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC SERVICETO ELECTRIC CUSTOMERS IN THE STATEOF IDAHO. CASE NO. IPC-O3-
IDAHO POWER COMPANY
DIRECT TESTIMONY
l'1AGGIE BRILZ
please state your name, address and presentoccupation Please state you name and business address.My name is Maggie Brilz.My business addressis 1221 West Idaho Street, Boise, Idaho.By whom are you employed and in whatcapaci ty?I am employed by Idaho Power Company asDirector of Pricing.Please describe your educational background.In May of 1980 I received Bachelor of ArtsDegrees in Economics and Psychology from Smith College inNorthampton Massachusetts In 1998 I completed theUniversity of Idaho's Public Utilities Executive Course in
~1oscow , 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 wi
Idaho Pow~r ompany
I started employment with Idaho Power Company
in November of 1984 as a Financial Analyst in the Planning
Depa r tmen t In 1986 I was promoted to the position of Rate
Analyst in the Rate Department..My duties as a Rate Analyst
included the development of alternative pricing structureg
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I daho Power Company
the analysis of the impact on customers of rate designchanges, the preparation of cost- of-ocrvice studies, and theadministration of the Company I s tariffs..In July of 1993 Iwas promoted to Rate Design Supervisor.In that capacity also became responsible for the overall rate designactivities of the Rate Department. In October of 1996 I waspromoted to my current position of Director of pricing inthe Pricing and Regulatory Services Department.What is the scope of your testimony in thisproceeding?My testimony will address the Company s classcost-at-service study and the Company I s rate designproposals for the tariff and special contract customers.Class Cost-of-Service Study
please describe the methodology used
prepare the class cost-of-service study submi tted in this
proceeding
The class cost-at-service study submi tted in
this proceeding uses the Weighted 12 Coincident Peaks
allocation method.This study 1..1SeS the same mAr.nonology as
previously filed by the Company in Case No. U-IOO6-185, Case
No. U-IOO6-265A, and Case No. IPC-E-94-5 and used by the
Commission in the allocation of the revenue requirement
among customer classes in those cases.
What procedures were UGcd in the preparation
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I daho Power Company
of the fully distributed or embedded class cost-ai-servicestudy?There are two general steps used in preparinga fully distributed or embedded class cost-of-service study.The first step is to determine the total costs of providingelectric service, adjusted for normal weather and waterconditions.The next step is to establish a methodology forthe separation of those costs among customer classes.Q..What total costs of providing electricservice have been allocated to the various customer classesin the class cost-af-service study?The total costs of providing electric serviceto the Idaho jurisdiction included on Mr. Obenchain Exhibit No.. 30 have been allocated to the various classes.
Q..What methodology was used for the separation
of costs among customer classes?
The methodology tor separating costs among
classes consists of a three-step process generally referred
to as classification, functionalization, and allocation..
all three steps r recognit.ion
; ~
gi\TP-D t.o t_he way in which
the costs are incurred by relating these costs to the way in
which the utili ty is operated to provide electrical service.
Please explain the meaning of classification.
Classi ication refers to the identification
of cost as being ci ther cuctomer-related, demand-related, or
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Idaho Power Company
energy- rela ted.These three cost components are used reflect the fact that an electric utili ty is not simply inthe business of selling electric energy even though it maysometimes appear to the ellS tamer tha t only energy, asmeasured in kilowatt-hours is purchased.In fact thecustomer is also buying the abili ty to have serviceavailable at any point in time. Secondly the customer buying capaci ty or the abili ty to receive as much power is required at a point in time. Most power supply facilities(generation and transmission) generally are considered fall into this capaci ty category. And finally the customeris buying energy or the abi 1 i ty to do useful work over anextended period of time. These three concepts ofavailability, 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
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 facilitiest the costs associated with
BRILZ DI
I daho Power Company
meter reading and billing, and the costs associated withmaintaining the Qvailabili ty of service regardless ofwhether service is actually taken Demand-related costs areinvestments in generation, transmission, and distributionplant and the associated operation and maintenance expensesnecessary to accommodate the maximum demand imposed on theCompany I S sys tern Energy-related costs are generally thevariable costs associated wi th the operation of thegenera t ing plants, such as fuel, al though due to the hydroproduction capability of the Company a portion of the hydroand thermal generating plant investment is usuallyclassified as energy-related.please discuss the approach used to classifycustomer-, demand-, and energy-related costs
The Company has used the Electric Utility
Cost Allocation Manual published by the National Association
of Regulatory Utili ty Commissioners as its primary guide
the classification of customer- demand- and energy-related
costs.
Q..Please explain the mean; ng
functionalization.
In addi tion to classification, costs must be
functionalized; that is, identified with utility operating
functions ~ Operating functions recognize the different roles
played by the various faciliticD in the electric utility
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Idaho Power Company
system. In the Company 1 s accounts these various roles arealready recognized to some degree, particularly in therecording of plant costs as production-, transmission-, ordistribution-related. However this functional breakdown not in sufficient detail for cost-ai-service purposes.Individual plant items are examined and, where possible, theassociated investment costs are assigned to one or moreoperating functions so that the costs may be allocated amongclasses of customers.Please explain the process of allocation.A..The process of allocation is merely one ofapportioning the total jurisdictional cost among classes byintroducing allocation factors into the process. Anallocation factor is nothing more than an array of numbers
which specifies the class value or share of a total
jurisdictional quanti ty
Once individual costs have been allocated
the various classes of service, it is possible to total
these costs as allocated and thus arrive at a breakdown
utility rate base An~ i n~ome 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
return earned on rate base compared to the requested rate
return.
Q -Have you prepared or supervised the
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Idaho Power Company
preparation of the fully distributed or embedded class cost-of-service study submitted in this proceeding?Yes. Using the cost information provided me by Mr.. Obenchain, I prepared the fully distributed orembedded class cost-af-service study.This study wasprepared using the Weighted 12 Coincident Peaks allocationme thod It is identified as follows:Exhibi t pescriptionExhibi t No.3 7 Functionalization andClassification of CostsExhibitNo.Exhibit No..Exhibit No.Summary of Functionalized CostsAllocation to ClassesDevelopment of Weighted Demand andEnergy Allocators
Exhibi t No. Revenue Requirement Summary
Please describe Exhibi t No.3 7
Exhibit No. 3'/ contains 115 pages and
consists of 10 Cost Functionalization and Classification
Tables.. The functionalization and classification of each
component. of rar.p baRe , operat~ing reven11e and expense is
treated in detail in these tables..The tables are shown in
the following sequence:
Table No..Descrlptlon
Electric Plant in Service
Accumulated provision for Depreciation
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Idaho Power Company
Additions and Deletions to Rate BaseOperating RevenuesOperation and Maintenance ExpensesDepreciation and Amortization ExpenseTaxes Other Than Income TaxesIncome TaxesDevelopment of Labor Related AllocatorFunctionalization AllocatorsWhat is the significance of the column headedIt Allocator"This column identifies, by symbol the basisfor each allocation. For examplet for Accounts 310 through316, Steam productionr shown at line 20 on page 1, thecons tan t II PI -IJ is used to allocate the total inves tilleD t
steam production plant to the appropriate functions The
resul tant 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 deprec ation
for steam production plant is allocated by the
functionalization of costs at ine ? 0-
Q .Please describe the classification of plant
utilized in the class cost-at-service study..
In the class cost-af-service study all steam
and hydro production plant has been classified on a demand
and energy basis using the methodology found preferable by
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Idaho Power Company
this Commission in prior general rate proceedings. Theenergy portion of the cteam and hydro production investmenthas been determined by use of the Idaho jurisdictional loadfactor of 55 26 percent.The computation of the Idahojurisdictional load factor is included in my workpapers.application of the load factor ratio to the steam and hydroproduction plant investment, the energy-related portion easily determined. The balance of the steam and hydroproduction plant investment is then classified as demand-related.All other production plant and transmission planthas been classified as demand-related..Q..Would you describe how distribution plant hasbeen 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 ! s system peak during the three-year period 2000
through 2003 - The fixed portion of the Company s RYRtem peak
was set equal to the near-minimuffif 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..
Would you plcaoc describe the
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Idaho Power Company
functionalization of general plant?General plant was functionalized based ontotal production, transmission! and distribution plant.. As resul t, a portion of general plant was assigned to eachproduction! transmission, and distribution function based oneach function s proportion to the total.How was the accumulated provision fordepreciation functionalized?The accumulated provision for depreciationwas functionalized using the resulting functionalization ofcosts for the appropriate plant i tern.For example, theaccumulated depreciation for steam production plant shown line 115 on page 16 is functionalized based on thefunctionalization of steam production plant in service at
line 20.
Please describe Table 3 of Exhibi t No. 37
Table j indicates the functionalization
all other addi tions to and deductions from rate base.
Deductions from rate base include customer advances for
construction Ana a~~u~11ated 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.Additions to rate base
concict of materials and supplies, which have been
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I daho Power Company
functionalized based on the appropriate plant function, fuelinventory, which has been functionalized based on energyproduction and prepaid i terns which have beenfunctionalized based on labor expenses or the appropriateplant function depending on the type of prepayment.Deferred conservation expenses have been functionalizedbased on the Idaho jurisdictional load factor resul ting in26 percent of the deferred expenses being functionalizedto energy production and the remainder being functionalizedto demand produc t ion.Please describe the functionalization other revenue shown on Table 4 of Exhibit No. 37Other revenue is functionalized based oneither 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
the specific service i tern.
Briefly describe the method by which
operation and maintenance expenses were functionalized.
The functionalization of np~ration and
maintenance expenses is detailed on Table 5 of Exhibi t No.
In general! the basis for the functionalization may be
readily interpreted from the Exhibi particularly since in
most cases the functionalization is the same as that for the
associated plant.
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Idaho Power Company
How is supervision and engineering expensetreated throughout the allocation of operation andmaln tenance expenses?A..For each applicable expense account in eachfunctional group, the labor component is separatelyfunctionalized in accordance with the detail provided onTable 9 of Exhibit No.. 37 Referring to pages 91 through 105of Table it can be seen that the total of allocated laborin each functional group becomes the basis for thefunctionalization of supervision and engineering expense..For example, for Account 535 at line 678, the labor relatedsupervision and engineering expense is functionalized basedon lines 679-683 which represent the cumulative labor functionalized for Accounts 536 through 540 shown on page
of Exhibi t No.3 7 .. In a similar fashion, the allocation
supervision and engineering associated wi th 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 p'lrpose of flJric:t.ionalizing employee pensions
and other labor-related taxes and expenses.. Table 9 details
the development of all labor-related functionalization
factors used in tb,is study..
Please describe the functionalization of
depreciation cxpcnoc, taxes other than income, and income
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Idaho Power Company
taxes shown on Tables 6, 7, and 8, respectively.Depreciation expense is functionalized basedon the function of the associated plant.Taxes other thanincome are also functionalized based on the function of thesource 0 f the tax.Deferred income taxes are functionalizedbased on total plant investment.The functionalization offederal and state income taxes is based on thefunctionalization of total rate base and expenses and discussed in more detail in my testimony regarding theallocation of costs to classes of customers.Q..Please describe Exhibi t No. 38Exhibit No. 38 summarizes in row format thefunctionalized costs for each component of rate base andexpenses shown across the columns on Exhibi t No. 37
Please describe Exhibit No. 39
Exhibi t No. 39 details the allocation of the
surnmari zed costs shown on Exhibi t No.3 8 to each class of
customer including the special contract customers.The
Exhibi t also includes a summary of resul ts showing the
actual rate of return earne~ for each customer class and
special contract customer.The Exhibit includes the
following tables:
Table No.Description
Plant in Service
Accumulated Reserve for Dapreciation
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Idaho Power Company
Amortization ReserveCustomer Advances for ConstructionAccumulated Deferred Income TaxesAcquisition AdjustmentWorking Capi talDeferred ProgramsSubsidiary Rate BaseSubstation CIACOther RevenueOperation & Maintenance ExpensesDepreciation ExpenseAmortization of Limited Term PlantTaxes Other Than Incomeprovision for Deferred Income Taxes
Investment Tax Credit Adjustment
State Income Tax
Federal Income Tax
Allocation Factor Summary
Briefly describe the manner in which you
allocated the s1.1mmari zed c:ost.~n()wn on Exh.ibi t No.3 8
each class of service as shown on Tables 1 through 17 of
Exh i bit No.3 9
In an effort to weight the monthly
contributions to the total system peak in a fashion which
reflects the marginal coote of the Company J s geasonal load
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Idaho Power Company
requirements, I have allocated demand-related costsaccording to a Weighted 12 Coincident Peaks allocationme thod Q..Is the Weighted 12 Coincident Peaksmethodology used in the current class cost-ai-service studythe same methodology used in previous studies filed with theCommission?The philosophical approach is the same inthat the methodology is intended to strike a balance betweenbackward-looking costs already incurred and forward-lookingcas ts to be incurred in the fu ture However 1 the nature ofthe Company s marginal costs has changed since the early19908.As a result, the methodology used to compute theweighted demand-related allocation factors has been revised
slightly.
How has the nature of the Company s marginal
costs changed since the early 199Gs?
Accord ng to the Company s 2002 Integrated
Resource Plan (IRP) , the Company has identified capacity
deficits in the months of iJl1np F iTlJly ...AlJgllst
..
November.. and
Decembe only.During all other months, no capacity
defici ts currently exist.The deficits in the five months
cited above are driving the need for additional peaking
resources.Consequently the Company faces capacity, or
generation related, marginal costs in only five months
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I daho Power Company
the year.During the remaining seven months, the Companyhas no current need for addi tional resources ~ Hence there isno generation-related marginal cost for these seven months.In the early 1990s the Company s analysis showed ageneration-related marginal cost for all months of the yearexcept September and October.Does the Company s analysis for transmission-related marginal costs show the same result as forgeneration capaci ty?No f it shows slightly different results..Again, according to the Company s 2002 IRP the Companycurrently anticipates transmission deficits during only themonths of June, July, and August.As a resul t , the Companyfaces transmission-related marginal costs during only these
same three months.
Q..What are the weighted allocation factors used
in the cost-at-service study
The allocation factor DiG is used to allocate
generation capaci ty-related costs.The allocation factor
D13 is used to allocate transmission-related costs.The
allocation factor EIG is used to allocate energy-related
casts..The detail for the development af the weighted
allocation factors can be found on Exhibit No. 40
How has the Company used the marginal costs
to determine the Weighted Coincident Peaks allocation
BRILZ DI
Idaho Power Company
factors?First! the actual coincident peaks for eachcustomer class were used to derive actual DID and D13ratlOS.Second, the actual coincident peaks weighted by thefive monthly marginal costs for generation and the threemonthly marginal costs for transmission were used to deriveweighted D1O and D13 ratios.Finally, the average of theactual and weighted D1O and D13 ratios were computed for usein allocating costs among customer classes.Was the methodology used to compute thedemand-related weighted allocation factors used to computethe weighted energy-related allocation factors?A..No.Because the Company operates its sys ternby continually balancing energy genera tion and purchases,
faces monthly marginal energy costs.Therefore the
methodology used to determine the weighted energy allocation
tactors is the same as that used in the Company's previous
filings.The monthly marginal energy costs were used
weight the normalized monthly energy usage for each customer
class and special contract customer.I then totaled the
results for each customer class and divided the customer
class totals by the jurisdictional total weighted value
establish the E1O ratio each class.
Were any other changes incorporated into the
derivation of the weighted demand and energy allocation
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Idaho Power Company
factors?Tn order to i c1pnt. i fy r.()~t.S hy ~11mmerYes.and non-summer seasons to facilitate the Company s ratedesign proposals I calculated weighted factors for both thesummer season, defined as the months of June, July, andAugust, and the non-summer season, defined as all othermonths.Accordingly the summer and non-summer weighteddemand allocation factors used for the allocation of thedemand-related po rtion of production plant and for theallocation of transmission plant are designated as D1OS,DIONS, D13S, and D13NS, respectively.The summer and non-summer weighted energy allocation factors are designated E1OS and E1ONS, respectively..Q..Have the marginal costs been used to develop
the Company s revenue requiremen t ?
A..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 capaci ty components
distribution plant, both primary and secondary, was by use
of the coincident group peak demands for each customer class
identified as demand allocation factors D20 D30, D50 and
D60 - The allocation of th~ customer components
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I daho Power Company
distribution plant, both primary and secondary was by useof the average number of customers identified as customerallocation factors C20J C30, C50 and C60Q..What was the method by which you allocatedcosts associated with customer accounting and customerassistance expenses?The principal customer-related expenses whichrequire allocation are meter reading expenses customerrecords and collections, uncollectible accounts, andcustomer assistance expense. The meter reading and customeraccount expenses were allocated based upon a review ofactual practices of Idaho Power Company in reading metersand preparing monthly bills. The allocation of uncollectibleamounts again was based upon a review of actual Idaho Power
Company da ta 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 1 7?
A -Yes.Table 20 of Exhibi t 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
shown on Tables 18 and 19?
The state and federal income taxes for the
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Idaho Power Company
Idaho jurisdiction provided to me by Mr. Obenchain wereallocated to each customer class and special contractcustomer on the basis of income before income taxes.Theworksheet showing this allocation is included in myworkpapers.Tables 18 and 19 show the functionalization these allocated taxes to each customer class.What method was used to functionalize thestate and federal income taxes as shown on Table 18 andTable 19 of Exhibit No. 39?State and federal income taxes werefunctionalized based on the functionalization of total ratebase and expenses for each class.For example, the totalsummer power supply production rate base amount of$59,945 913 allocated to the residential class on Tables
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
$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
Please describe Exhibi t No. 41.
Exhibit No - 41 is the revenue requirement
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I daho Power Company
summary based on the results of the class cost-at-servicestudy.The section headed "Revenue Requirement for RateDesignH details the sales revenue required from eachcustomer class and special contract customer. The salesrevenue required includes return on rate base, totaloperating expenses, and incremental taxes computed using thenet-to-gross mul tiplier of 1.642 provided to me by Mr..Obenchain.I have provided the results from this section Mr.. Ga 1 e Mr. Gale 1 s testimony addresses the allocation revenue requirement among the customer classes.Were any adjustments made to the Companydata for any of the customer classes for purposes of theclass cost-of-service study?Yes.Currently seven customers receive
service under Schedule 19 Transmission Service level
After a review of these customers ' facilitiest 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 unlike
Primary Service level customers are currently paying a
facilities charge for a portion of the investment
substation facili ties required to provide service.In order
to treat these customers consistently wi th other customers
in the same situation I the Company intends to trangf r these
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Idaho Power Company
four customers to Primary Service level and discontinue themonthly facilities charge on the substation investm nt adjustment, as detailed by Mr. Obenchain in his testimony,has been made to the amount of annual facilities chargerevenue to reflect this change.Does the Company s class cost-ai-servicestudy treat each service level on Schedule 9 and Schedule as a separate customer class?No, it does not..The three service levels Secondary, Primary, and Transmission, available on bothSchedule 9 and Schedule 19 are intended to provideflexibility in serving customers depending on the customerfacility requirements.For example, customers who own theirown 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 faci Ii ties, or who pay a
facilities charge to the Company for use of the dedicated
secondary facilities, are served at Primary Service level
After the adjustment 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 served at Primary Service level
BRILZ, DI
Idaho Power Company
Therefore, for Schedule 19, the Transmission and Secondarycustomers are combined with the Primary Service levelcustomers to form a single customer class for costallocation purposes.For Schedule 9, the three TransmissionService level and the 112 Primary Service level customersare combined to form a single customer class for costallocation purposes while the Secondary customers remainseparate.. This grouping of the various service levelsprevents a very small group of customers from being treatedas a single customer class.The Company s class cost-at-service studyseparately identifies contributions in aid of construction(CIAC) for distribution substations.Is this treatment substation CIAC a departure from past practices?
A..In the past, the Company s class cost-Yes.
of-service studies have included only the net amount
distribution substation investment.consequently, no direct
recognition of CIAC payments has historically been made on a
customer class basis..As a resul t, 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
class cost-ai-service study to address the CIAC issue?
First , rath9r than using net distribution
BRILZ, Dr
Idaho Power Company
substation investment (Accounts 360, 361 , and 362) as theamount to be functionalized , classified , and allocated toclasses as has been the practice in previous studies, thecurrent study uses the "net plus CIAC" distributionsubstation investment.Second, I directly assigned to eachcustomer class the distribution substation CIAC amountspecifically contributed by each class.Thus the class-specific CIAC contributions were used as direct offsets the allocated distribution plant investment for eachcustomer class in the derivation of net rate base.Thismethodology directly attributes the benefit associated withCIAC payments to the specific classes that made thecontributions.Mr. Obenchain referred to an adjustment 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
adjustment?
Micron currently pays a monthly O&M charge
based on the total cost of the substation facili ties
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 wi th the substation
facili ties into Micron's standard charges.The adjustment
to Micron s sales revenue was made in order to establish an
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Idaho Power Company
appropriate base revenue amount.Rate Deslqntihat are the objectives the Company striving to achieve through its rate design proposals?The Company is striving to achieve two mainobjectives.First, the Company is striving to establishprices which primarily reflect the costs of the servicesprovided.. Cost-based prices provide customers with clearsignals about the costs of receiving service, reducesubsidies within customer classes, and result in a moreequitable recovery of the costs of providing service.Second, the Company is striving to give customers pricesignals that reflect the variation in the costs of providingservice during different times of the year and day.Mr.
Gale addresses in his testimony the Company s policy
regarding its pricing objectives.
How does the Company propose to implement
these obj ecti ves?
The Company proposes to implement these
objectives by pricing the individual rate components closer
to cost, by implementing seasonal pricing for Schedules
9 and 19, and by implementing time-at-use pricing for all
customers taking service under Schedule 19.
How does the Company plan to price the rate
components closer to cost?
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I daho Power Company
Historically, the energy charge on meteredservice schedules has been set at levels that recover notonly the costs associated with providing energy but also aportion of the fixed costs associated wi th delivering energyand providing customer-related services.The Company plansto emphasize increases to both the demand and customercharges so that these components are more reflective cost.This plan will result in less non-energy relatedcas ts being recovered through the energy charge.Q..Why is the Company proposing seasonal ra tesfor Schedules 7, and 19?A..The Company faces its highest power supplycosts during the months of June, July and August..TheCompany also faces its highest peak usage during these same
three months.In fact, it is the peak usage during these
three months along wi th 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
mAnagpmpnr. programs 11t_lmm lZJ.ng t e energy e lclency rl er
funds. Seasonal rates, which are higher in the months
June, July, and Augus t than during the other nine remaining
months, are intended to signal customers that consumption
during the summer months is more costly.It is hoped that
this signal will encourage reduced consumption during thg
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I daho Power Company
peak mon ths Why is the Company not proposing seasonalrates for Schedule 24, irrigation service?Irrigation service is by defini tion seasonal.The pricing structure for Schedule 24 already takes intoaccount the seasonal nature of irrigation service.Why is the Company proposing time-of-userates for Schedule 19 service?Besides being more costly during the su~mermonths energy is more costly during certain hours of theday.The implementation of time-at-use rates for Schedule19 customers, who currently have the metering in place toaccommodate the hourly pricing, will provide the economicsignal that energy is more costly during both the peak hours
0 f the day and the peak months 0 f the year.Again, like
strictly seasonal rates l it is hoped that time-ai-use rates
wi 11 encourage reduced consumption both during the summer
months as well as during the daily peak hours.
What are the specific pricing objectives for
~hp Company 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
initiate seasonal energy pricing on all metered service
schedules and both seasonal energy and s9asonal demand
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Idaho Power Company
pricing on all metered service schedules that are alsodemand metered.And finally the ompany plans to implementmandatory time-ai-use pricing for all customers takingservice under Schedule 19 The Company does not plan change the current seasonal pricing structure for irrigationserviceJ nor does it plan to implement seasonal pricing forunmetered schedules or for the special contract customers.How are the seasons defined for the Company J spricing proposals?The summer season is defined as June through Augus t 31 The non-summer season is defined asSeptember 1 through May 31..Are you proposing any changes to the cri teriafor determining service schedule eligibili ty?
A..I am not proposing any changes to the usage
cri teria for determining eligibi Ii ty for service under
Schedules 9, and 19.However 1 am proposing a change to
the process used to review customers' eligibili ty.
Would you please explain the change being
proposed?
Yes.Currently each customer taking service
under Schedule 9, or 19 is assigned an anniversary date
that coincides with the date on which service under the
schedul e firs t began.Each year dur ing the bi 11 ing per i ad
in which the customer s anniversary date falls ~ the
BRILZ DI
Idaho Power Company
customer S usage during the past twelve months is reviewedto determine continued eligibility-Customers whose usageduring the annual review period has changed such that theyare no longer eligible for the existing schedule are movedto the appropriate schedule beginning with the next billingperiod Although this process works well under mostsituations, there are cases in which there is a lag betweenchanges in usage and the actual annual review.. For example,under the current method where the annual review occurs onthe customer s anniversary date, a customer taking serviceunder Schedule 7 whose account is reviewed on July 1 maydecide to install an additional piece of equipment thatcauses the monthly usage to increase over 3, 000 kWh perro.onth.Thi s increase in usage would make the CUB tamer
eligible for service under Schedule 9 after just three
months"However, because the customer 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.
its place, I propose to review each customer's account
monthly.Based on this monthly review of the customer
most recent twelve months of usage, transfers to the
appropriate service schedule will be timelier The
BRILZ, Dr
Idaho Power Company
language on Schedules 7, and 19 has been modified toreflect this change in process.Are you proposing any other changes that arecornmon to several service schedules?I am propos ing tha t the Cus tamer ChargeYes.included on Schedules 1, 7, 9, 19, 24, and 25 be renamed Service Charge.Why is this change being proposed?The current Customer Charge is intended recover costs that do not vary with the amount of energy orcapaci ty used.These costs include such i terns as a portionof the investment in distribution facili ties the investmentin meters and service drops, meter reading, bi lling, andother customer service related expenses..The term Service
Charge is more descriptive of these costs and, I believe,
will be more easily explained to customers.
Q..Wha t change is being proposed to the power
factor requirement for Schedules 9, 19, and 24?
Currently, Schedules 9, 19, and 24 provide a
mean8 hy whi ch ~hp mA8S11red kW may be adjusted if the
customer! 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's power factor
less than 90 percent This revision will more directly
target cost recovery from those customers whose poor power
, Dr
Idaho Power Company
factors result in the need for additional facilitiesinvectment by the Company. In order to provide ample timefor customers to work with Company representatives identify and implement solutions to improve power factor, Iam proposing the 90 percent power factor requirement notbecome effective until November 1, 2004.Are you proposing any changes to thecontracting provisions for large customers requiring 1, 000kilowatts (kW) or more of capaci ty?Yes. I am proposing that any customer excepta customer receiving service under a special contract, whorequires 1,000 kW or more of capacity at a single point delivery enter into a service agreement with the Companyspecifying the amount of capaci ty required..By 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
Service Agreement, specifying this provision.I have also
added B- TJn.i form Ser'\Ti Cp Agrp-ement- in tariff format to R111e
Are you proposing any changes not directly
related to the Company s rate design?
Yes.Based on previous Commission Orders,
the unit avoided energy cost for cogeneration and gmall
BRILZ DI
Idaho Power Company
power production available under Schedule 89 is to beadjusted during th course of every Idaho Power gen ral ratproceeding.Using the methodology previously ordered by theCommission, I have adjusted the unit avoided energy costutilizing updated variable operation and maintenance costsand variable fuel costs for the Valmy plant.Have you prepared or supervi sed thepreparation of certain exhibi ts relating to your rate designtestlffiony?Yes.I am sponsoring the following exhibi tsrelating to rate design:Exhibi tExhibit No. Exhibit No.
Exhibi t No.
Exhibit No..
Exhibit No.
Exhibit No..
Exhibit No.
Exhibit No..
A..
DescriptionClass Cost-of-Service Uni t CostsSummary of Revenue Impact and Calculation
of Proposed Rates
Billing Comparisons and Rate Design
Impacts of proposed Kates
Derivation of Schedule 19 Charges
Derivation of Schedule 24 Charges
Derivation of Schedule 45 Standby Charges
Proposed Tariff in Legislative Format
IPUC No. 27, Tariff No. 101
Please describe Exhibi t No. 42
Exhibit No.. 42 shows the uni t cost for each
function for metered service schedules as determined through
BRILZ
Idaho Power Company
11'
the fully distributed or embedded class cost-of-servicestudy.The billing units shown in the column labeled (E)reflect the billing demands, normalized billing energy basic load capaci ty / and number of billings.The unit costsshown on Exhibit No. 42 form the basis of the componentcharges for each service schedule.Please describe Exhibi t No. 43Page 1 of Exhibit No. 43 is titled Summary ofRevenue Impac Each service schedule and special contractcustomer is listed with its number of customers, energysales, and current revenue level.Column 5 shows therevenue adjustment to each customer class.Column 6 showsthe revenue to be recovered by the rate design proposalsbased 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 ~xhibit 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,
19, 24 , and 25
Please describe Exhibi t No. 45 and Exhibi t
No. 46.
BRILZ Dr
Idaho Power Company
Exhibi t No. 45 details the derivation of thecharges for SCl1edlJ.le 19 Ex.hib.it 1\10. 46 deta.i 1s t.derivation of the charges for Schedule 24Please describe Exhibi t No.4 7 .Exhibit No. 47 details the derivation of theupdated charges for Standby Service under Schedule 45please describe Exhibit No. 48 and ExhibitNo. 49 Exhibi t No.4 8 ine 1 udes the Company J s ru 1 e s /regulations / and service schedules indicating in legislativeformat the changes made to those rules / regulations andschedules.Exhibi t No. 49 is the proposed Idaho Publicutilities Commission No. 27 , Tariff No. 101.Thi s exhib i tcontains all the changes to the Tariff proposed by the
Company in thi s proceeding.
How have you organized your discussion of the
company s rate design proposals?
I have di vided 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 t s non-demand metered schedules.The second
section addresses the Company I s proposals tor demand-metered
schedules.The third section includes the discussion for
the proposed rate structures for the Company I s non-metered
schedules - The fourth sect ion addresses the Company '
BRILZ / Dr
Idaho Power Company
proposals for the special contract customers.The fifthsection includes the rate design proposals for the Company f srider" schedules for standby and alternate d stributionserVlce.The final section addresses the Companyproposals for its miscellaneous special contracts.NON - DEMAND METERED SCHEDULESWha t are the Company I s non -demand meteredservice schedules?Residential Service and Small GeneralService, Schedules 1 and 7 respectively, are metered forkilowatt-hour (kWh) use only..What is the present rate structure forResidential Service under Schedule Presently, residential customers pay a
Customer Charge of $2 51 and a base Energy Charge of 4. 9303~
per kWh..
What is the revenue requirement to be
recovered from Residential Service customers taking service
under Schedule
Based on Mr ~ Gale s Exhibi t No - 61 l' tJle
annual revenue to be recovered from Schedule 1 customers is
$255,076,727 .
Please describe the rate design proposal for
Schedule 1..
A..The rate dcsign propooal for Schedule 1 is
BRILZ Dr
Idaho Power Company
included on page 2 of Exhibi t No. 43 The Service Charge increased from $2 51 to $10~OO per month.The $10Service Charge represents approximately 40 percent of thecost-of-service result of $24 61 shown at line 300 on page of Exhibi t No. 42 Both a summer and a non - summer EnergyCharge are established wi th the sum~er charge 25 percentgrea ter than the non - summer charge.The Energy Chargeduring the summer is 6.13759 per kWh.The Energy Chargeduring the non-summer is 4 . 9101Q per kWh.Q..What impact does this rate design have onResidential Service customers?The typical monthly billing comparison forResidential Service customers appears on page 1 of Exhibi No. 44
Do you believe the increase in the Service
Charge f om $2.51 to $10.00 per month is detrimental to low
income cus tamers?
No, I do not.
Are you proposing any other changes
Schedule
A..Yes.I am making wha I cons i der
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
the Company J s specifications for residential service-
BRILZ, Dr
I daho Power Company
What is the present rate structure for SmallGeneral Service under Schedule Customers taking service under Schedule 7 paya Customer Charge of $2 51 and a base Energy Charge 96499 per kWh.Demand is not metered for Schedule CUB tamers.What is the revenue requirement to berecoveredfromSmall General Service customers takingservice under Schedule Based on Mr.Gale s Exhibi t No.61,the totalannualto be collected from Schedule cus tamersrevenue$20,328,148 Please describe the rate design proposal forSchedule 7
The rate design proposal for Schedule 7 is
inc 1 uded on page 3 0 f Exhibi t No.4 3 .The Service Charge is
increased from $2 Sl to $10.00 per month.'l'he $10.. 00
Service Charge represents approximately 40 percent of the
cost-of-service result of $26.01 shown at line 360 on page
of Exhibit No ~ 42 Both a summer and a non-summer Energy
Charge are established.The Energy Charge dur ing the summer
is 7.28689 per kWh..The Energy Charge during the non - summer
is 5 . 8283~ per kWh.As is the case for residential service,
the Schedule 7 Energy Charge during the summer is 25 percent
greater than the Energy Charge during the nOll-summer
BRILZ , Dr
Idaho Power Company
What the impact this rate designSma 11 Gener a cus tamers 7ServlcePageExhibit No.shows the billingcomparison between the existing rates and rate structure andthe proposed rates and rate structure for typical billinglevels Are you proposing other changes to ScheduleA..As I wi 11 explain in more detai 1 as Idescribe the proposed changes to Schedule 24, IrrigationServicef I am proposing to add language to Schedule 7 thatclarifies that it is not applicable to agricul turalirrigation service after October 31, 2004.DEMAND- METERED SCHEDULES
What are the Company s demand-metered
schedules?
The Company I s demand-metered schedules are
Large General Service Large Power Service 1 and Irrigation
Service Schedules 19 and 24, respectively.
addi ~i on r ~rhedll1 2 S, Irrigation Service Time-af-Use pilot
Program, while not open to new participants, is still
available to those who were taking service as of October
2002
How are Schedule 9 and Schedule
in terrela ted?
BRILZ Dr 3 8
Idaha Power Company
Both Schedule 9 and Schedule 19 provideservice at Secondary Primary and Transmission Servicelevels.As customers ' loads change, they can transferbetween Schedule 9 and Schedule 19 while continuing to takeservice at the same service level.Both Schedule 9 andSchedule 19 have a Demand Charge and a Basic Charge.TheDemand Charge is assessed on peak demand each month whilethe Basic Charge is as sessed on the average of the twohighest peak demands for the current 12-month period.Q..What is the current relationship betweenprices on Schedule 9 and Schedule 19?Currently, the Basic Charge, the DemandCharge, and, with a slight deviation, the Customer Chargeare the same wi thin 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
and Schedule 19; tor 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
Transm; ~~1 on ~er\Tice le\Tel for Schedule 9 are approximately
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
reflective of cost and to facilitate customer transitions
BRILZ, Dr
Idaho Power Company
1'7
from Schedule 9 to Schedule 19 and vice versa.Does the Company s rate design proposal forSchedule 9 and Schedule 19 customers maintain this pricingrelationship between schedules?The rate design proposal for Schedule 9 andSchedule 19 maintains the relationship between the BasicCharge and the Demand Charge on each of the schedules.However because time-ai-use pricing is being proposed forSchedule 19 and not for Schedule 9, a direct relationshipbetween the energy components is not maintained.What is the present rate structure forSchedule Service under Schedule 9 is taken atSecondary 1 Primary 1 or Transmission Service level One
hundred twelve customers take service at Primary Service,
three customers take service at Transmission Service, and
16 919 customers take service at Secondary service.All
customers taking service under Schedule 9 pay an Energy
Charge, a Demand Charge a Bas i c Charge, and a Cus tamer
Charge. Cl1~~omprs taking Primary or Transmission service may
also pay a Facilities Charge.
Please describe the rate design proposal for
Schedule 9
The Company is proposing both seasonal Energy
Chargee and seasonal Demand Charges for Schedule
BRILZ, DI
Idaho Power Company
addition, the Company is proposing increases to both theService Charge and the Basic Charge-Does the rate design proposal have the sameoverall impact in terms of the percentage increase inrevenue requirement for customers taking service underSecondary, Primary, and Transmission Service levels?No. The results of the cost-of-service studyindicated an overall increase in revenue of 8 percent forSecondary Service level customers and 24 percent for Primaryand Transmission Service level customers (refer to line 233on page 1 of Exhibi t No. 41)In order to recognize thiscost difference between service levels, the rate designproposal for Primary and Transmission Service level targetsan 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-at-service result
$37 74 shown at line 480 on page 3 of Exhibit No. 42 The
~ervice Charge for Primary and Transmission Service is $500.
This amount is the same charge established for Schedule
Primary Service and Schedule 19 Transmission Service and
reflects the cost associated with the automated metering
customers at these voltage levels.
What is the Basic Charge for Schedule
BRILZ, Dr
Idaho Power Company
The Basic Charge for Secondary Service $ .65 per J'\:W of basic load capaci ty per month.Th e $.. 6 5charge reflects approximately 50 percent of the cost service for distribution facili ties as shown at line 480 onpage 3 of Exhibi t No. 42 For Primary Service, the BasicCharge is $1.. 12 per kW of basic load capaci ty The BasicCharge for Transmission Service is $.. 57 The Basic Chargefor Primary Service and the Basic Charge for TransmissionService are the same as those for Schedule 19 Thederivation of the $1..12 and $.57 charges is detailed laterin my discussion of the Schedule 19 rate design..Q..What is the Demand Charge for Schedule A..The Demand Charge for Secondary Service forthe 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 tor Primary
Service is $3
..
25 per kW.The Demand Charge for Transmission
Service is $3 80 per kW during the summer season and $3
per kW during the nOn-S1...1mmer season For he nOD.- S11mmer
season, the Demand Charges for Secondary Primary 1 and
Transmission Service are the same as those for Schedule 19
The derivation of both the summer and non-summer Demand
Charges is described in more detail in my discussion of the
Schedule 19 pricing design.
BRILZ 1 DI
Idaho Power Company
Q..What is the Energy Charge for Schedule A..The Energy Charg for Secondary Service 94429 per kWh during the summer and 2 56169 per kWh duringthe non - summer.For Primary Service, the Energy Charge 56599 per kWh during the summer and 18239 during thenon - summer The Energy Charge for Transmission Service 50879 per kWh during the su~mer and 2 13379 per kWh duringthe non - summer.How were the Energy Charges derived?The differential between the summer and non~summer energy costs resulting from the class cost-af-servicestudy for Schedule 9 is approximately 18 percent (refer toExhibi t No. 42 1 page line 480) The Energy Charges forPrimary 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 rrransmission Service
~ '
l'he ~nergy charges for
Secondary Service were set to recover the residual revenue
requirement for the class while attempting to maintain a
SlImmer and non-summer differential close to 18 percent..
Q..Are you proposing any other changes to
Schedule
A..As I wi 11 explain in more detai 1 as I
describe the proposed changes to Schedule 24 Irrigation
Service , I am proposing to add language to Schedule 9 that
BRILZ DI
Idaho Power Company
clarifies that it is not applicable to agriculturalirrigation service after October 31 2004Wha t is the revenue requiremen t to berecovered from Schedule Based on Mr.. Gale I S Exhibi t No.. 61, the totalannual revenue to be collected from customers taking serviceunder Schedule 9 is $123 864, 097 What is the impact of this rate design onLarge General Service customers?AS can be seen from page 3 of Exhibi t No. 44,approximately 30 percent of the customers taking Schedule Secondary Service receive an increase in their annual billsless than the 15 percent overall increase for the SecondaryService customers as a whole.Another 28 percent of the
Secondary Service customers receive an increase of
percent to less than 20 percent.For Primary and
Transmission service level customers, approximately
percent of the customers receive an increase less than the
20 percent overall increase targeted for this group.Page
of Exhibi t No. 44 shows the impact of the rate design
proposal on customers taking service under Schedule
mary or Transmission Service.For all service levels,
customers wi th higher load factors receive less of an
increase than GUS tamers wi th lower load factors.
What is the present rate structure for
BRILZ Dr
Idaho Power Company
Schedule 19?A..Service under Schedule 19, just like rviceunder Schedule 9, is provided under Secondary, Primary Transmission Service levels. All customers taking serviceunder Schedule 19 pay an Energy Charge, a Demand Charge Basic Charge, and a Customer Charge. Customers takingPrimary or Transmission Service may also pay a FacilitiesCharge. In addi tion1 Schedule 19 includes a 1,000 kW minimumbilling demand and basic load capacity.What is the rate design proposal for Schedule197The Company is proposing seasonal time-at-userates be implemented on a mandatory basis for all customerstaking service under Schedule 19 Under the Company
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-S1.1mmer dema.nd cnArgp.~ as well as an on-peak demand
charge during the summer. Although the Company is proposing
an increase to both the Service Charge and the Basic Charge,
no seasonality is being proposed for these charges.
Q..What is the Service Charge for Schedule 19?
A..For all service levels, the Service Charge
BRILZ, DI
Idaho Power Company
$500 per month. This amount represents approximately percent of the cost-ai-service result of $712 - 36 shown atline 720 on page 5 of Exhibi t No. 42What is the Basic Charge for Schedule 19?The Basic Charge for Secondary Service 65 per kW per month, the same as that for Schedule Secondary Service.For Primary Service, the Basic Charge $1.12 per kW per month.This amount is approximately equalto the cost-at-service result of $1 11 shown on line 720 onpage 5 of Exhibit No. 42 For Transmission Service theBasic Charge is set to $.57 per kW per month to maintain theexisting relationship between the Primary and TransmissionService levels.Please describe the Company s proposal for
time-ai-use energy charges.
During the three summer months 1 the Company
is proposing three time-of-use blocks..The On-peak block
defined as m. to 9 p .ffi.. Monday through Friday.The Mid-
Peak block is defined as 9 a.m. to 1 p.m. and 9 p..m. to
m~ Monday through Friday and 7 a.m. to 11 p.m. Saturday!
Sunday and holidays.The Off-Peak block is defined as
p .
ffi. to 7 a ID. every day.. During the non-summer months, the
Company is proposing just two time-at-use blocks.The Mid-
Peak block during the non-summer is defined as 7 a .ill. to
m. Monday through Sa turday The Off-Peak block is d fined
BRILZ, DI
Idaho Power Company
as 11 P .ill. to 7 a .ID.. Monday through Saturday and all hourson Sunday and holidays All times are in Mountain Time-What are the specific proposed energy prices?The Energy Charges by service level and timeperiod for each season are:TimePeriod -----------Service Level----- ---------Secondary Primary TransmissionSummerOn-Peak 3 . 4354~2 . 7991~. 7368~2 .41989Mid-Peak 03759 2 .47499Of f - Peak 77459 26069 2103c;Non-SummerMid-Peak 2 .66619 1723Q 2 ..12399Off-4928~0311~1 - 9859G
Please describe the Company s proposal for
Demand Charge s
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 IS-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 $0 45 is assessed for each
kW of On-Peak Billing Demand, which is the average kW
BRILZ, DI 4 7
Idaho Power Company
supplied during the 15-minute period of maximum demandduring the billing period for the on-peak hours.Forcustomers whose peak demand during the billing period occursduring the on-peak period, the Billing Demand and the On-Peak Billing Demand will be the same.However, forcustomers whose peak demand occurs during the mid~peak oroff-peak period, the Billing Demand will be greater than theOn-Peak Billing Demand.During the non-summer months, onlyBilling Demand will apply. There is no On-Peak BillingDemand during the non-summer months.The Demand Charges forthe non - summer mon ths are $ 3 . 35 per kW f or SecondaryService, $3 25 per kW for Primary Service, and $3 ..15 per kWfor Transmission Service.Would you please provide an example of how
the summer Billing Demand and On-Peak Billing Demand will
affect customers?
Assume a primary service level customerYes
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
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 kW for On-Peak Billing Demand) .
How r if this same customer has a peak demand for the
BRILZ, DI
Idaho Power Company
billing period of 1,500 kW that occurs during the mid-peakor off-pPAk pprio(1 wi t.n t.l1p l1i g"hP~t- ppak rip-mAne) c111ri ng t.r1Pon~peak period equal to 1,200 kWt the On-Peak Billing Demandwill be less than the Billing Demand.In this situation,the customer will, on averaget pay only $3 86 per kW of peakdemand ($3 50 per 1,500 kW of Billing Demand plus 45 per200 kW of On-Peak Billing Demand) Are you aware of any utilities that chargefor both peak demand during the month and on-peak demandduring the month in a manner similar to the Billing Demandand On-Peak Billing Demand you are proposing for the summerseason?Yes.I am aware of at least three utili tiesthat 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-8; 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 Sprinqs Utilities charqes for both monthly on-
peak and monthly off-peak demand under its Schedule E8T and
E~S .Both Southe n California Edison and Pacific Gas and
Electric charge for on-peak demand during the summer season
only.
Wnat approach was tak.e:n -LD determining the
BRILZ, DI
I daho Power Company
pricing proposal for Schedule 19?A two-step approach WAR ~akpn-pi rst.seasonal charges that did not differentiate by time-of-usewere developed..After the seasonal charges were developed,the next step was to create the time-af-use charges for thedemand and energy components within each season..ExhibitNo. 45 details the derivation of the seasonal, non time-of-use differentiated charges as well as the derivation of theseasonal time-of -use charges.How were the seasonal charges developed?The Energy Charges for each season wereestablished to approximate the 17 percent cost differentialbetween summer and non-summer energy costs resul ting fromthe class cost-at-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 Pr imary
Service was developed by first establishing the non-summer
Demand Charge at $3 25 per kW which is approximately
percent greater than the Schedule 19 Primary Service cost-
of-service result at $2 95 shown at line 7'20 on page :' ot
Exhibi t No. 42 and approximately equal to the Schedule
Primary Service cost-ai-service result of $3 29 per kW shown
at lin 540 on page 4 of Exhibit No - 42 ThP Sllmmpr DpmAnc1
BRILZ Dr
Idaho Power Company
Charge for Primary Service was then established at $3 94 perkW to reflect a O percent differential betw en the summerand non - summer Demand Charges.The Demand Charges for bothnon-summer and summer for Secondary and Transmission Servicewere then set to maintain the current relationship for thesecharges between the three service levels. The non-summerDemand Charge was set to $3 35 per kW for Secondary Serviceand to $3 .15 per kW for Transmission Service.The summerDemand Charge was set to $4.00 per kW for Secondary Serviceand to $3 80 per kW for Transmission Service.Why was a 20 percent differential establishedbetween the summer and non-summer Demand Charges?20 percent differential approximates theseasonal 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-at-service
study is approximately 80 percent (refer to line 720 on page
5 0 f Exh bit No.4 2)
How were the time-of-use Energy Charges
devG loped 7
BRILZ, Dr
Idaho Power Company
The first step in developing the time-ai-useEnergy Charges was to determine the charge for the Mid-Peaktime period for each season.As a starting point, the Mid-Peak charge was set equal to the seasonal Energy Chargeestablished through the process I just described. Forexample, as a starting point, the summer Mid-Peak EnergyCharge for Primary Service was set to 2 46869 the value ofthe seasonal, non time-af-use differentiated summer EnergyCharge (refer to page 1 of Exhibit No. 45)For the summercharges, the second step involved determining the amount increase or decrease from the Mid- Peak charge needed toestablish the On-Peak and Off-Peak charges so that thetarget price differentials for the three time blocks weremet.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 f ina
step involved minor adjustments to each charge to establish
prices that recovered the revenue requirement amount.
What were the target Drice differentials
between the various time blocks that the Company was
tr i ving to achi eve?
For the summer months the target price
differential between the on-peak and off-peak time periods
is 25 percent.According to the Company s Pow r Supply
BRILZ, Dr
Idaho Power Company
Planning Department, this differential represents theapproximate difference in cost between an average marketprice for energy during the summer months of June, July, andAugust and a flat market price for the calendar year.Theprice differentials between the on-peak and mid-peak pricesand the mid-peak and off-peak prices resulted from aniterative process in which the Company attempted to maintainthe mid-peak price as close to the flat seasonal charge possible, give a price signal to encourage shifting of loadfrom the on-peak period to either the mid-peak or off-peakperiod, and recover the revenue requirement.For the non-summer months, the price differential between the mid-peakand off-peak prices resulted from an iterative process inwhich the Company attempted to maintain the same
relationship as the summer mid-peak and off-peak prices
whi le recovering the revenue requiremen
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-at-use differentiated charges (refer to Exhibi No.. 45
discussed earlier) The summer Demand Charge for Primary
Service was derived by applying the same 13 percent
differential as was established for the summer On-Peak and
Mid-Peak Energy Charges to the summer non time-of-use
BRILZ Dr
Idaho Power Company
differentiated Demand Charge of $3 94. The resul t of thiscalculation is $3 50.The summer Demand Charges forSecondary and Transmission Service were then set to maintainthe current relationship between the service levels.Thedifference between $3 94 and $3 50, or $45 (rounded), isthe summer On-Peak Demand Charge.The On - Peak Demand Chargeis set at $.45 for each service level in order to help makethe adoption of this new charge simple for all customers.Does your rate design proposal include anyrevisions to the provision for a Facilities Charge underSchedule19?No.no t subj ect to a Customers taking Secondary Service willFacilities Charge.. Customers takingPrimary Service will continue to be required to ei they own
all facili ties, including transformers beyond the point of
delivery or pay the Company a monthly Facilities Charge
1 . '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 s orne
situations, customers taking Transmission Service may pay a
monthly Facili ties Charge of 1.7 percent times the Company
investment in certain facilities.
What is the total annual revenue requirement
to be collected from Large Power Service customers?
BRILZ , DI
I daho Power Company
Based on Mr. Gale s Exhibi t No,. 61 , the totalannual rGvenue requirement to be collected from Schedule is $ 62,703,671.What is the impact of the rate design onLarge Power Service customers?As can be seen f rom page 5 of Exhibi t No.4 4 ,approximately 25 percent of the customers taking serviceunder Schedule 19 receive an increase in their annual billsless than the 14 percent overall increase for the Schedule19 customers as a whole.Another 33 percent receive anincrease of 14 percent to less than 16 percent.For theSchedule 19 customer group as a whole, customers with higherload factors receive less of an increase than customers withlower load factors.
Are you proposing any other changes
Schedule 19?
A,.Yes.Currently customers are required
sign a Uniform Large Power Service Agreement with the
Company in order to receive service under Schedule 19
the cur.;:;t.nmpr ref"uses to sign the Agreement C1 service
continues to be provided under Schedule al though
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 wi th loads greater
BRILZ Dr
Idaho Power Company
than 1,000 kW who meet the criteria for service underSchedule 19 but who choose not to enter into an Agreement-The reasoning stated by some of the customers for notentering into an Agreement is the reluctance to make a 12-month co~li tment for service particularly by some of thecompanies that operate nationally.In order to ensure tha customers are placed on the appropriate service schedulebased on their usage characteristics, I am proposing eliminate the requirement that a Uniform Large Power ServiceAgreement be signed in order to receive service underSchedule 19 Wi thout the requirement to enter into anAgreement, customers will be transferred onto and off Schedule 19 automatically based on their usage.addition, customers whose operations are going out
business will no longer be required to provide a twelve-
month notice to the Company prior to having Schedule
service discontinued.Ra ther, as these cus tamers usage
declines, they will be transferred to the appropriate
general service schedule as indicated by the monthly review
proces s I have added language to Schedule 19 indicating
that all Uniform Large Power Service Agreements will be
cancelled effective June 1, 2004.
Q..what contracting requirements, if any, will
customers taking service under Schedule 19 have?
A..Customers taking service under Schedule
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Idaho Power Company
will be required to enter into a Service Agreement with theCompany specifying the level of capacity required to servetheir facili ties.I described this Service Agreementearlier in my testimony.Are you proposing any changes to theeligibili ty cri teria for receiving service under Schedule19?Schedule 19 will remain available No.customers who have three or more billing periods during atwelve-month period in which the metered demand equals orexceeds 1, 000 kW.However, Customers whose loads areanticipated to immediately exceed 1,000 kW may request totake ini tial service under Schedule 19..What is the current rate structure for
Schedule 247
Service under Schedule 24 is classified as
being ei ther 11 in-season II or II out-af-season" rhe in-season
for each customer begins wi th the customer I s meter reading
for the May billing period and ends wi th the customer i
mpr.P.T 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 the out-ai-season, customers pay an Energy Charge
only..For the in-season , customers are subj eet to a $10.
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Idaho Power Company
Cus tamer Charge The Customer Charge during the out-of-season is $2 50.Both Secondary Service and TransmissionService levels are available under Schedule 24, although nocustomers are currently taking Transmission Service Please describe the rate design proposal forSchedule 24 I am proposing to keep the overall ratestructure for the irrigation season as it is currently.Consistent with the Company s overall objectives, I proposeto move the individual rate components closer to cost byemphasizing increases in the demand and customer componentsand the inclusion of less non-energy related costs in theenergy 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
ro~~-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
overall revenue by component currently provided by the
exi sting base ra tes These percentages are shown in column
4 on Exhibi t No. 46.The difference, or gap, between the
BRILZ DI
Idaho Power Company
target and the actual percentage was then determined foreach component.Cus tomer demand, and energy charges werethen established at a level that adjusted revenue by percent of the gap.Exhibi t No. 46 illustrates the approachtaken for each rate component.How were the rates for Transmission Servicedetermined?Once the component rates for SecondaryService were determined, the charges for TransmissionService were established to maintain the same relationshipbetween service levels as currently exists.What is the Service Charge for Schedule 24?The Service Charge for Secondary Serviceduring the in-season is $25 per month.The S erv ice Charge
for Transmission Service during the in-season is $500 per
mon th 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-ai-season is $2 50 per month.
Q -What is the Demand Charge for Schedule 24?
The Demand Charge for Secondary Service
increased from $3 58 to $5.40 per kW per month.The Demand
Charge for Transmission Service is -increased from $3 37 to
08 per kW per month.The Demand Charge is billed to
Schedule 21 customers during the in-season only.
BRILZ DI
I daho Power Company
What is the Energy Charge for Schedule 24?The Energy Charge for Secondary Service increased from 2 84169 per kWh to 3 26349 per kWh during thein-season and from 3 61729 per kWh to 4.57319 per kWh duringthe out-af-season.The Energy Charge for TransmissionService is increased from 2 70219 per kWh to 3 .10359 per kWhduring the in-season and from 3 43969 per kWh to 4.34909 perkWh for the out-af-season.What is the impact of the rate design onSchedule 24 irrigation service customers?Page 6 0 f Exhibi t No.4 4 shows the bi 11 ingimpact of the proposed rate design.As can be seen frompage 6 of Exhibit No. 44, approximately 23 percent of thecustomers 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.
~Dother 31 percent of the cus tamers receive an increase
just 3 percent or less above the overall class increase
25 percent The remaining cus tamers receive an increase in
their annual bills of 3? pprrpn~ ~o 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
emphaais on capacity, the higher a customer t g
load factor
BRILZ DI
I daho Power Company
the more beneficial the rate structure tends to be in termsof the overall impact to the annual billing.As can be seen-from page 6 of Exhibi t No. 44, customers wi th the highestpercentage increase in annual bills have the lowest loadfactors What changes are being proposed for Schedule25 Irrigation Service Time-of-Use pilot Program?Schedule 25 currently provides continuedservice until October 1, 2007 for those participants whowere enrolled in the pilot program on October 1, 2002 TheCompany is not proposing any changes to this ongoing serviceavailability at this time.However the Company proposing to revise the Schedule 25 Service and DemandCharges 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 ChArgp~, 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-at-season Service Charge
$ 2 . 50 per mon th, the Demand Charge is $ 5 . 40 per kW per
month, and the out-ai-season Energy Charge is
~ -
5731~ per
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Idaho Power Company
kWh.The $3 00 per month in-season Meter Charge remains thesame.For the in- season the On- Peak Energy Charge 71109 per kWh, the Mid-Peak Energy Charge is 3 26349 perkWh, and the 0 f f - Peak Energy Charge is 1. 631 7 ~ per kWh.Would you please describe the methodologyused to determine the in-season Energy Charges for Schedule25?As is currently the case, the Mid-Peak EnergyCharge is set equal to the in - season Energy Charge underSchedule 24, or 3 26349 per kWh.The differential betweenthe On-Peak Energy Charge and the Off-Peak Energy Charge the same as that currently in place for Schedule 25 Thatis, the On-Peak Energy Charge is 75 percent greater than theMid-Peak Energy Charge while the Off-Peak Energy Charge
50 percent less than the Mid-Peak Energy Charge.
What is the impact of these changes on the
Time-af-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- C1J.stomer rl RRS as a whole. As can be seen
from page 7 of Exhibit No. 44, approximately 23 percent of
the customers taking service under Schedule 25 receive an
increase in their annual bills of less than 25 percent.
Another 27 Dercent of the customers receive an increase of
....
just 3 percent or lCOD above the overall class increase of
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I daho Power Company
1"7
25 percell t What are the usage characteristics of theSchedule 25 customers receiving increases less than andgreater than 25 percent?As is the case wi th Schedule 24 the ratedesign for Schedule 25 places an increased emphasis oncapaci ty As a resul t, the higher a customer s load factor,the lower the overall percentage increase.Conversely, thelower a customer s load factor the higher the overallpercentage lncrease.Are any other changes to Irrigation Servicebeing proposed?Yes.Currently irrigation customers whorequest service be reconnected or transferred into their
name are not charged an account processing charge or a
reconnection charge if they provide ten working days
advanced notice at the date reconnection or transfer of
service is desired.This ~waiver " of the account processing
charge is unique for irrigation customers as all other
customers recp; "ing met_ered service are assessed an account
processing charge or a reconnection charge when service
transferred or reconnected.. I am proposing that irrigation
customers be treated similarly to all other customers who
request a service reconnection or transfer by assessing
either a cervice reconnection charge or a service
BRILZ DI
I daho Power Company
es tabl i shmen t charge in each sit ua t i on where the ervi c e isper farmed.Will irrigation customers still be requiredto provide ten working days advance notice of the date theydesire to have service reconnected or transferred?No*The Company will process requests forservice reconnect ions and transfers in the same manner asthese reques ts are now proces sed f or all other CUB tamers In almost all si tuations, these requests will normally beproces sed wi thin three working days.Why is the Company proposing to add thesecharges for irrigation service at this time?Since the Company routinely began leavingirrigation 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 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
15,280 irrigation customers..In 1996/ the Company performed
approximately 9,000 service reconnections tor irrigation
customers.In 2003 only 3,400 service reconnections for
irrigation customers were performed.The Company believes
it is equitable to have those customers who require the
BRILZ, DI
Idaho Power Company
reconnection service pay for the service rather than havingthe costs shared by all customers Requiring customers topay a reconnection charge will eliminate a cross-subsidybetween those irrigation customers who require servicereconnections and those who do not.Similarly, chargingthe approximately 250 customers who annually require theCompany to perform a special meter reading in order transfer service into their names is more equi table andtargets cost recovery from those customers who require thespecific service.Q..What are the reconnection charge and serviceestablishment charge for irrigation customers being proposedby the Company?A..Ms. Drake addresses the specific charges and
their derivation in her testimony.
What change is being proposed to the
eligibility criteria tor Schedule 24 and Schedule 25?
The current language under the Applicabili
section on both Schedule 24 and Schedule 25 states that
service 1_8 "appl i ~Ahlp to power and energy supplied to farm
customers and organizations Al though the Company
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 interpretations.The
Company intends to clarify the nature of service for which
BRILZ , DI
Idaho Power Company
Schedule 24 and Schedule 25 are applicable by replacing thexisting language under the Applicability section withlanguage that specifies that service is applicable to powerand energy supplied to agricul tural use customers operatingwater pumping or water delivery systems used to irrigateagricul tural crops or pas turage and by changing the name ofthe schedule from simply Irrigation Service to Agricul turalIrrigation Service.Are there any customers currently receivingservice under Schedule 24 or Schedule 25 that would nolonger be eligible for irrigation service wi th the adoptionof the new applicability language?There are approximately 768 customersYes.currently receiving service under Schedule 24 and Schedule
25 that would no longer be eligible for continued irrigation
service wi th the adoption of the new applicabili ty language
The majority 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-agricul tural
customers to continue receiving irrigation service under
Schedule 24 or Schedule 25 through October 31, 2004.
Effective November 1 OO4 any non-agricultural customers
BRILZ Dr
Idaho Power Company
still receiving service under Schedule 24 or Schedule would be transferred to the applicable general serviceschedule.In addition, on this date, any agriculturalcustomer utilizing a water pumping or water delivery systemand receiving service under ei ther Schedule 7 or Schedule would be transferred to Schedule 24How many agricultural customers currentlyserved under Schedule 7 or Schedule 9 would will be affectedby this change?Approximately 613 customers would betransferred from Schedule 7 or Schedule 9 to Schedule 24.NON-METERED SCHEDULES, , "" Q .What are the Company . s non-metered serviceschedules?
The Company 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 C1)~t_omer IJ ighting on Schedule 15?
Customers taking service under Schedule
are charged on a per lamp basi s Lamps currently served
under Schedule 15 include 100, 200, and 400 watt high
pres sure sodium vapor
prec.cure sodi urn vapor
area lighting, 200 and 400 watt high
flood lighting and 400 and 1 000 watt
BRILZ DI
Idaho Power Company
metal halide flood lighting. Under Schedule 15, customerspay a monthly Facilities Charge of 1.75 percent for all newfacili ties required for service.Q..Wha t is the revenue requi remen t to berecovered from customers taking service under Schedule 15?A..Based on Mr. Gale s Exhibi t No. 61, theannual revenue to be recovered from Schedule 15 customers is$1,458,416 The class cost-of-service study indicatesthat the rates for Schedule 15 service should be reduced byover 100 percent.Would you please explain this result?Yes.Customers who require new facilities tobe installed in order to receive service under Schedule are charged a monthly facilities charge equal to 1.
percent of the Company s investment in those new facilities.
Prior to the implementation of the Company s 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 ser,ri r~ cloeR not identify the total
investment in new facilities installed to provide Dusk
Dawn Customer Lighting Service.In prior cost-ai-service
studies, the total facilities charge revenue collected from
customers was allocated to customer classes based on the
identified facilitics investment for each class This
BRILZ/ DI
Idaho Power Company
methodology resulted in no facilities charge revenue beingdirected to the Schedule 15 customer class-Rather thefacilities charge revenue that should have been directed tothe Schedule 15 customer class was spread to other customerclasses.Because the detailed information on facilitiescharge revenue is now available through the CIS, the currentcost-of-service study directly assigns the appropriateamount of facilities charge revenue to each customer class including the Schedule 15 class..However , the issue oftracking facilities so that new facilities installed provide Dusk to Dawn Customer Lighting Service can becorrectly identified has not been resolved.As a resul t al though the revenue is credi ted to the Schedule 15 customerclass ( the associated costs associated wi th the plant
investment are not Prior to f i 1 ing its next general ra
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
negati Vp i mpl cations for the other customer classes?
Al though it would obviously be bet ter to have
the correct matching of the revenue and expenses, any impact
to other classes is minimal.Based on the total amount of
facilities revenue received from Schedule 15 customers, the
maximum total original investment in new facilities should
BRILZ DI
Idaho Power Company
be approximately $6 million The net amount of thisinvestment included in rate base , after adjustments fordepreciation, would be something less than $6 million.Compared to a total rate base amount for the IdahoJurisdiction of $1.547 billion, the plant investmentpotentially attributable to the Schedule 15 customer classrepresents less than four tenths of one percent of totalrate base.Please describe the rate design proposal forSchedule 15 The rate design proposal for Schedule 15 isine 1 tided on page 7 0 f Exhibi t No.4 3 The monthly chargefor each lamp is simply increased on a uniform percent basisconsistent wi th the overall 99 percent increase for the
class as a whole.
Is the Company proposing any other changes to
Schedule IS?
The Company is proposing two changesYes.
related to the facili ties required to provide Dusk to Dawn
Cl1st.()mpr Tl ightin.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 rather than having the
BRILZ DI
Idaho Power Company
, 21
customer pay a monthly facilities charge on the newQCl 1- tlCS Why is the Company proposing to allow thefixture to be installed on a customer-owned support?The Company is proposing to allow the fixtureto be installed on a customer-owned support that acceptable to the Company in order to allow more flexibilityfor customers.In several instances, a customer-owned poleor other structure could adequately provide the supportneeded to install a lighting fixture.Charging the CUB tomeran additional amount to install a new Company-owned polewhen an exiting customer-owned structure exists unnecessary ~ The Company would have the sale discretion determine if a customer-owned support were acceptable..
addi tion, the Company would have the right to remove its
lighting fixture from the customer-owned support if it were
a t any time determined by the Company tha t the support was
unsafe or had the potential to cause damage to it or to
other cus tamers.Language has been added to Schedule
that specifi s that by req1Je~r.i ng t.ne 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 s property and granting the Company permission
enter the customer ' 0 prcmicec inclu,ding the customer-owned
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I daho Power Company
support, in order to maintain its lighting fixture.What changes are being proposed regarding theinstallation of new facilities to provide Dusk to DawnCustomer Lighting Service?A..Customers who request Dusk to Dawn Lightingservice where Company facilities are not presently availableare required to pay a monthly facili ties charge of percent for all new facili ties installed to provide service.New facilities can include such i terns as poles, anchors andconduc tors.If the facili ties remain in service for theirfull useful lives the Company is made whole on thetransaction"However if the ellS tamer reques t s the Companydiscontinue the lighting service and remove the facilitiesbefore the end of their useful lives, the Company is not
made whole for the transaction.In order to avo i d thi s
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
earl y ypmoval of the lighting fixture and other facilities,
the Company would still incur the labor costs associated
wi th the removal..However the Company would not be left
wi th facili ties for which it would not be able to recover
its investment.
What is the present rate structure for
BRILZ Dr
Idaho Power Company
Unmetered General Service under Schedule 407Customers taking service und r Schedule pay a flat Energy Charge based on estimated usage.Demand -and customer-related costs are recovered through the EnergyCharge..The minimum bill for service under Schedule 40 is$1.50 per month.What is the revenue requirement to berecovered from customers taking service under Schedule 40?Based on Mr. Gale's Exhibi t No. 61, theannual revenue to be recovered from Schedule 4 a CUB tamers is$952,976 .Please describe the rate design proposal forSchedule 40..The rate design proposal for Schedule 40 is
included on page 14 of Exhibi No.. 43 The Energy Charge
remains flat and increases from 5 6809 per kWh to 5 . 953Q per
kWh.
Are any other changes being proposed to
Schedule 40?
Yes Sr.npO111e 40 is available to customers
whose loads and hours of operation are fixed such that the
monthly kWh consumption can be accurately determined~
order to ensure that Schedule 40 remains available only
loads that are fixed, I am proposing language that makes
Schedule 40 unavailable for loads that have the potential to
BRILZ, DI
I daho Power Company
have variable usage.With this additional language,customers taking service under Schedule 40 who modify thexisting equipment such that it has the potential forvariation in usage or who install additional equipment thathas the potential for variation in usage will no longer beallowed to take service under Schedule 40 and will betransferred to the appropriate metered service schedule.What is the present rate structure for StreetLighting Service, Schedule 41?Charges for Street Lighting Service are basedon a per lamp or per pole basis.Street Lighting is dividedinto 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 ~he AVAi Rbi lity of wired outlets or energized
plug-ins on the lighting standard, it is possible for
customers to use energy for other purposes, such
illuminating holiday decorations.In order to accommoda
customers who desire to use addi tional energy for non-street
lighting purposes, the Company is proposing to add a metered
BRILZ , DI
Idaho Power Company
service option under Schedule 41.Customers who utilizeplug-ins on Company-o\tJYled facilities or who have wiredoutlets or plug-ins on customer-owned facilities will berequired to have metered service.Is the Company changing its standard to thecut-off or shielded fixture?Yes.The Company is changing its standardlight luminaire from a drop-down lens fixture to a flat lensor cutoff fixture.The Company plans to use its existinginventory of drop-down lenses until it is exhausted or untilMarch whichever comes sooner.Beginning March 1, 2004 the cutoff fixture will be used exclusively I have addedlanguage to Schedule 41 that addresses the acceleratedreplacement of drop-down lens fixtures wi th ell tot f fixtures
for those customers who are interested in converting to the
cutoff fixture more rapidly than would normally occur
through standard maintenance.
I s the Company proposing changing the wa t tage
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 H requirements In order to minimize inventory and
better meet customer requests, the Company is proposing no
new service for the 20Q-watt high pressure sodium fixture
BRILZ, DI
Idaho Power Company
and the addition of the 250-watt high pressure sodiumfixture to the Company-owned options These changes willresul t in the same wattage lamps being available for bothCompany-owned and customer-owned systems.Q..Are you propo sing any 0 ther change s toSchedule 41?Yes"I am proposing what I consider to betwo housekeeping changes.First Schedule 41 currently haslanguage specifying that underground circui ts can beinstalled if the customer pays a monthly Facilities Charge75 percent times the cost difference between overheadand underground installation charges Thi s language is nolonger applicable wi th the Company s current Rule Underthe provisions of Rule H, customers are responsible for
paying the total cost of any addi tional facili ties 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
1Jnc1p.rgrollnd cirelli ts?
No..Customers who previously agreed to pay a
monthly facili ties charge for the installation of
underground facili ties will continue to pay the charge
What is the second housekeeping change being
proposed?
BRILZ Dr
I daho Power Company
Schedule 41 currently has language statingthat the services provided by the Company for customer-ownedsystems include the replacement of defective ballasts.withthe current design of lighting fixtures, the ballasts are nolonger separately replaced.Rather, the entire fixture isreplaced.Therefore, I have removed the reference to thereplacement of defective ballasts from the sectiondescribing the services performed by the Company forcustomer-owned systems.What is the revenue requirement to berecovered from customers taking service under Schedule 41?Based on Mr. Gale's Exhibi t No. 61, theannual revenue requirement for Schedule 41 is $1,899 531Please 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 ser\7i C'.P.. wi 11 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 uni t cost
for the fixture, bulb, and photocell was determined for each
BRILZ, DI
Idaho Power Company
lamp type and wattage using the information available in theCompany 0 property records.Sales tax Company overheads and labor expense were then added to the average uni t cos to derive a loaded facilities-related cost.The mon thlyper-lamp facili ties-related charge was derived byfiliI tiplying the loaded fixture cost by 1.75 percent (themonthly facilities charge rate) For non-metered service,the total monthly charge per lamp equals the monthly per-lamp facilities-related charge plus the applicable amountfor the per-lamp energy consumption.For metered service,the monthly charge per lamp equals the sum of the monthlyper-lamp facilities-related charge plus the metered kWhtimes 4. 661Q 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 Exhibi t No. 43 . I have
included in my workpapers details on the average unit cost
for each fixture, bulb, and photocell and the derivation
the loaded facili ties-related cost.
What is the present rate structure for
Traffic Control Signal IJ ighti ng ~~rvice, Sche&lle 42?
Customers taking service under Schedule
pay a flat Energy Charge for each kWh of estimated energy
use.Usage is estimated based on the number and size
lamps burning simultaneously in each signal and the average
number of hours per day the signal is operated.There is no
BRILZ , Dr
I daho Power Company
1-'
minimum charge under Schedule 42What is the rev nue requirement to recovered from customers taking service under Schedule 42?Based on Mr. Gale's Exhibi t ,No. 61, theannual revenue requirement for Schedule 42 is $320 719 .please describe the rate design proposal forSchedule 42 The rate design proposal for Schedule 42 isincluded on page 19 of Exhibit No. 43 The Energy Charge increased from 3 .1059 per kWh to 3 4959 per kWh.Is the Company proposing any other changes toSchedule 42?Yes"Over the past several years the Companyhas experienced an increase in the number of traffic
lighting systems that utilize LED bulbs, traffic sensors
and camera moDi tor ing 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
mAkpF; i t. difficul t to accurately estimate the kWh
consumption at each intersection.In order to el imina te
this n 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
consumption.
BRILZ DI
Idaho Power Company
Will traffic control signal lighting systemsinotallcd prior to June 1, 2001 be required to beretrofitted to allow metered service?No.Systems installed prior to June 1, 2004may be retrofitted with meters upon the mutual consent ofthe Company and the cus tamer.However the Company is notproposing at this time that existing systems be required convert to metered service SPECIAL CONTRACT CUSTOMERSWhat are the Company s rate design proposalsfor its special contract customers?Other than the proposal which I describedearlier to eliminate the monthly O&M charge paid by Micronand incorporate the costs associated with the substation
facilities into Micron s standard charges, the Company
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's Exbibi t No - 61 ~ne rates for Micron~
J. R. Simplot Company, and DOE/INEEL are shown on pages 20,
2 1, and 2 2 0 f Exh i bit No.4 3 res pee t i vel y
STANDBY AND ALTERNATE DISTRIBUTION SERVICE
Are any customers currently taking service
under Schedule 451 Standby Service?
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Idaho Power Company
1-'
No there are no customers taking Schedule serVlce.Are any revisions to Schedule 45 beingproposed?The Schedule 45 charges are being revised toreflect the updated cost information resulting from thecost-at-service study.However, no other changes are beingmade to Schedule 45Have you prepared an exhibi t showing thederivation of the updated charges for Standby Service?Yes.Exhibit No. 47 details the derivationof the updated charges.The upda ted charges have beenderived using the same methodology approved by theCommission in the Company s last general rate case, Case No.
IPC-94-5
Are any customers currently taking service
under Schedule 46, Alternate Distribution Service
No.
What changes are being made to Schedule 46,
Al ternatA ni.. s t:ri bllt_.ion Service?
A..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 Al ternate Distribution Service.
The $1.30 amount is derived by summing the Distribution
demand revenue requirement for Substationst Primary Lines
BRILZ, DI
Idaho Power Company
and Primary Transformers for Schedule 19 shown on page 5 ofExhibi t No ~ 42 ($1 , 577 ,379; $3, 205 , 775; and $274 , 457respectively) and dividing this sum by the total billed kWof 903,470 This methodology is the same as that approvedby the Commission in the Company s last general rate case,Case No. IPC-94-MISCELLANEOUS CONTRACTSWhat are the miscellaneous contracts underwhich the Company is providing service?The Company has entered into contracts wi two customers to provide customized service otherwiseprovided under standard service schedules.First 1 theCompany is providing standby service to the AmalgamatedSugar 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 Ci ty 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 propos ing any changes to the standby
charges under the Standby Electric Service Agreement with
the Amalgamated Sugar Company?
Yes I am revis ng the charges to reflect
the updated cost information rgsulting from the cost-of-
BRILZ, Dr
Idaho Power Company
service study.The methodology used to update the chargesis the same methodology used to establish the currentlyapproved charges.Page 190 of Exhibit No.. 48 shows therevisions to Schedule 31 to reflect these updated charges.I have included details on the derivation of the updatedcharges in my workpapers.Are you proposing any changes to the ElectricService Agreement wi th the Ci ty of Ketchum?No.The Agreement with the City of Ketchumincludes a provision specifying that if any shielded fixtureprovided under the agreement becomes avai lable through astandard tariff offering, either party may give notice thatthey desire that shielded street lighting service becontinued under the standard tariff offering and the
Agreement will be terminated.Should the Commission approve
the Company s revised Schedule 41, the Company intends to
provide notice to the City of Ketchuffir terminate the
Electric Service Agreement and provide shielded service
the Ci ty of Ketchum under Schedule 41.
0 -Does this conclude your testimony?
Yes, it does.
BRILZ, DI
Idaho Power Company