HomeMy WebLinkAbout20110602Larkin Di, Exhibits.pdfRECEIVED
20 Ii JUH - I PM 2: 42
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ITS CUSTOMERS IN THE STATE OF
IDAHO.
CASE NO. IPC-E-II-08
I DAHO POWER COMPANY
DIRECT TESTIMONY
OF
MATTHEW T. LARKIN
1 Q.Please state your name and business address.
2 A.My name is Matthew T. Larkin. My business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company ("Idaho
6 Power" or "Company") as a Regulatory Analyst in the
7 Regulatory Affairs Department.
8 Q.Please describe your educational background.
9 A.I received a Bachelor of Business
10 Administration degree in Finance from the University of
11 Oregon in 2007. In 2008, I earned a Master of Business
12 Administration degree from the University of Oregon. I
13 have also attended electric utility ratemaking courses
14 including The Basics: Practical Regulatory Training for the
15 Electric Industry, a course offered through New Mexico
16 State Uni versi ty' s Center for Public Utili ties, and
17 Introduction to Rate Design and Cost of Service Concepts
18 and Techniques, presented by Electric Utilities
19 Consultants, Inc.
20 Q.Please describe your work experience.
21 A.I began employment with Idaho Power as a
22 Regulatory Analyst in January 2009. As a Regulatory
23 Analyst, I provide support for the Company's various
24 regulatory activities, including regulatory reporting,
25 financial analysis, and the development of various cost-
LARKIN, DI 1
Idaho Power Company
1 related studies. During my time with the Company, I have
2 assisted in the preparation of the Company's Oregon Results
3 of Operations Report, retail revenue forecasts for
4 regulatory filings, and a number of cost-of-service
5 studies.
6 Q.What is the scope of your testimony in this
7 proceeding?
8 A.My testimony will address the derivation of
9 the Company's 2011 retail revenue forecast, as well as the
10 Company's class cost-of-service study and the Company's
11 proposed allocation of the Idaho jurisdictional revenue
12 requirement to customer classes. My testimony will
13 conclude with the computation of the Load Change Adjustment
14 Rate ("LCAR") based upon values contained in this filing
15 and the methodology approved by the Commission in Case No.
16 GNR-E-10-03, Order No. 32206.
17 I. 2011 TEST YEAR RETAIL REVENU DERIVATION
18 Q. Please provide a brief description of the
19 methodology used to determine test year retail revenues.
20 A.Generally speaking, the Company's retail
21 revenue forecast is derived by applying current base rates
22 to forecasted test year billing components. These billing
23 components are derived by applying historical relationships
24 to the Company's customer and kilowatt-hour (" kWh") sales
25 forecast.
LARKIN, DI 2
Idaho Power Company
1 Q.Were the 2011 test year retail sales revenues
2 developed using the same methodology applied in the
3 Company's last general rate case, Case No. IPC-E-08-10
4 ("2008 Rate Case")?
5 A.Yes. Wi th the exception of a minor change in
6 the manner in which the demand-related billing determinants
7 were developed which I will describe later in my testimony,
8 the methodology applied in this case is the same as that
9 applied in the 2008 Rate Case.
10 Q.Please describe the customer and kWh sales
11 forecast that serves as the basis for the 2011 test year
12 retail revenue forecast.
13 A.The 2011 test year customer and kWh sales
14 forecast is based upon the Sales and Load Forecast prepared
15 for the 2011 Integrated Resource Plan ("IRP"), to be filed
16 with the Commission in June 2011. Because the IRP Sales
17 and Load Forecast is developed on a system-wide basis, an
18 addi tional step must be taken to determine the class-
19 specific customer and energy values by jurisdiction. The
20 methodology used to develop the Idaho class-specific test
21 year customer and energy values is outlined in the document
22 Development of Sales Forecast for Revenue Calculation, as
23 Exhibit No. 27 to my testimony. The described forecasting
24 methodology results in class customer counts and total kWh
25 sales estimates for each month of the test period. Once
LARKIN, DI 3
Idaho Power Company
1 the monthly sales estimates have been developed for each
2 customer class, they must be further segmented to align
3 with each class's rate structure.
4 Q.How were the 2011 test year kWh sales further
5 segmented into the class-specific energy-related billing
6 components?
7 A.The first step in deriving energy-related
8 billing components for the test year is to develop factors
9 based on the most current complete calendar year of
10 available historical data, which in this case is 2010.
11 These historical factors represent the percentage of total
12 kWh billed in each tier level of a class's rate structure.
13 To illustrate, Residential Service customers taking service
14 under Schedule 1 are billed according to a three-tiered
15 structure with seasonal rate differentiation. Using the
16 historical month of June 2010 as an example, actual tiered
17 usage was recorded at the following levels for Schedule 1
18 customers in the Idaho jurisdiction:
19
20
21
22
23
24
25
LARKIN, DI 4
Idaho Power Company
Usage Tier
June 2010
Schedule 1Billing
Components
1
2
Summer, 0-800 kWh 85,193,345
Summer, 801-2000 kWh 25,236,634
Summer, Over 2000 kWh 3,325,594
Non-Summer, 0-800 kWh 145,927,779
Non-Summer, 801-2000 kWh 43,227,859
Non-Summer, Over 2000 kWh 5,696,413
Total Schedule 1 kWh Usage 308,607,624
3 Based on the data above, historical factors for
4 Schedule 1 customers for the month of June were calculated
5 as follows:
Usage Tier
June 2010
Schedule 1
Weighting
Factors
6
Summer, 0-800 kWh 28%
Summer, 801-2000 kWh 8%
Summer, Over 2000 kWh 1%
Non-Summer, 0-800 kWh 47%
Non-Summer, 801-2000 kWh 14%
Non-Summer, Over 2000 kWh 2%
Total Schedule 1 100%
7 This process is used to develop historical factors
8 for all rate classes with tiered structures.Once a
LARKIN, DI 5
Idaho Power Company
1 complete set of monthly factors has been developed for each
2 applicable rate class, they are applied to monthly forecast
3 kWh totals to derive the energy-related billing component
4 forecast that aligns wi th each class's current rate
5 structure. Continuing with the illustration of Schedule 1
6 customers, the following table demonstrates the final step
7 in determining test year energy-related billing components:
8
June 2011
Schedule 1
Billing Component
Forecast (kWh)Usage Tier
Historical
June Weighting
Factor
Summer, 0-800 kWh 28%88,603,613
8%26,246,850
1%3,458,716
47%151,769,231
14%44,958,259
2%5,924,439
100%320,961,109
Summer, 801-2000 kWh
Summer, Over 2000 kWh
Non-Summer, 0-800 kWh
Non-Summer, 801-2000 kWh
Non-Summer, Over 2000 kWh
Total
9
10 Q.How are demand-related billing components
11 derived based on the kWh sales forecast?
12 A.The demand-related billing components consist
13 of billing demand and basic load capacity ("BLC") by month
14 for each rate class. Both billing demand and BLC totals
15 are forecasted by applying four-year average load factors
16 to each month in the kWh sales forecast. Historical data
LARKIN, DI 6
Idaho Power Company
1 from the most current available four calendar years is used
2 to derive an average load factor by month for each rate
3 class. These average factors are then applied to monthly
4 kWh sales figures to determine total forecasted billing
5 demand and BLC by class for each month of the test period.
6 Once monthly totals have been developed they are divided
7 into the appropriate tiered rate structure (if applicable)
8 utilizing historical factors in the same manner as kWh
9 charges.
10 Q.How are customer-related billing components
11 deri ved based on the customer count forecast?
12 A.The primary customer-related billing component
13 in the retail revenue forecast is the service charge.
14 Because the customer forecast reflects the expected number
15 of customers under active Utility Service Agreements
16 ("USAs") at the end of each forecast month, forecast values
1 7 must be converted to reflect the expected number of service
18 charges received throughout the corresponding month. To
19 cònvert the USA forecast to an expected service charge
20 count, historical factors are developed reflecting the
21 relationship between the number of USAs at the end of each
22 historical month and the number of service charges received
23 during the corresponding month. These factors are then
24 applied to the monthly customer forecast to develop a
25
LARKIN, DI 7
Idaho Power Company
1 forecast of expected service charges by rate class for each
2 month of the test year.
3 Q.How are test year retail revenues calculated
4 once the billing component forecast has been derived?
5 A.Once the billing components have been
6 forecasted by rate class, the most currently approved base
7 rates are applied to the test year values to derive monthly
8 revenue estimates for each rate class.
9 Q.Have you prepared any exhibits that detail the
10 calculations that were made to determine the Company's 2011
11 test year retail revenues?
12 A.Yes. Exhibit No. 28 provides a summary of
13 forecasted 2011 test year retail revenues, and Exhibit No.
14 29 details the calculations that were made to determine
15 these revenues. Input data used in the forecast
16 calculations can be found in my workpapers. As can be seen
17 on page 2 of Exhibit No. 28, the Company's 2011 Idaho
18 jurisdictional retail sales revenues are forecast to be
19 $812.2 million. As described in the direct testimony of
20 Mr. Scott Wright, revenues associated with first block
21 energy sales to Hoku Materials, Inc. ("Hoku") are treated
22 as surplus sales in this filing; therefore, they are not
23 included in this portion of the 2011 revenue forecast.
24
25
LARKIN, DI 8
Idaho Power Company
1 II. CLAS COST-OF-SERVICE STUDY OVERVIEW
2 Q. Please describe in general terms the process
3 used to prepare the class cost-of-service study.
4 A.There are two general steps used in preparing
5 a class cost-of-service study. The first step is to
6 determine the total costs of providing electric service,
7 adj usted for normal weather and water conditions. These
8 costs have been provided to me by Ms. Kelley Noe on Exhibit
9 No. 26. The next step is to establish a methodology for
10 the separation of those costs among customer classes.
11 Q.What methodology is used to separate costs
12 among customer classes?
13 A.Similar to the methodology described by Ms.
14 Noe to separate costs among jurisdictions, the methodology
15 for separating costs among classes consists of a three-step
16 process generally referred to as classification,
17 functionalization, and allocation. In all three steps,
18 recognition is given to the way in which the costs are
19 incurred by relating these costs to the way in which the
20 utility is operated to provide electrical service.
21 Q.Please explain the meaning of classification.
22 A.Classification refers to the identification of
23 a cost as being either customer-related, demand-related, or
24 energy-related. These three cost components are used to
25 reflect the fact that an electric utility makes service
LARKIN, DI 9
Idaho Power Company
1 available to customers on a continuous basis, provides as
2 much service, or capacity, as the customer desires at any
3 point in time, and supplies energy, which provides the
4 customer the ability to do useful work over an extended
5 period of time. These three concepts of availability,
6 capacity, and energy are related to the three components of
7 cost designated as customer, demand, and energy,
8 respectively. In order to classify a particular cost by
9 component, primary attention is given to whether the cost
10 varies as a result of changes in the number of customers,
11 changes in demand imposed by the customers, or changes in
12 energy used by the customers.
13 Q.What are some examples of customer-, demand-
14 and energy-related costs?
15 A.Examples of customer-related costs are the
16 plant investments and expenses that are associated with
17 meters and service drops, meter reading, billing and
18 collection, and customer information and services, as well
19 as a portion of the investment in the distribution system.
20 These investments and expenses are made and incurred based
21 on the number of customers, regardless of the amount of
22 energy used, and are, therefore, generally considered to be
23 fixed costs. Demand-related costs are investments in
24 generation, transmission, and a portion of the distribution
25 plant and the associated operation and maintenance expenses
LARKIN, DI 10
Idaho Power Company
1 necessary to accommodate the maximum demand imposed on the
2 Company's system. Energy-related costs are generally the
3 variable costs associated with the operation of the
4 generating plants, such as fuel. However, due to the hydro
5 production capability of the Company, a portion of the
6 hydro and thermal generating plant investment has
7 historically been classified as energy-related.
8 Q.What did you use as your primary guide in
9 classifying costs as either customer-, demand-, or energy-
10 related?
11 A.I used the Electric Utili ty Cost Alloca tion
12 Manual, published January 1992, by the National Association
13 of Regulatory Utility Commissioners as my primary guide to
14 the classification of customer-, demand-, and energy-
15 related costs.
16 Q.Please explain the meaning of
17 functionalization.
18 A.In addition to classification, costs must be
19 functionalized; that is, identified wi th utility operating
20 functions. Operating functions recognize the different
21 roles played by the various facilities in the electric
22 utility system. In the Company's accounts, these various
23 roles are already recognized to some degree, particularly
24 in the recording of plant costs as production-,
25 transmission-, or distribution-related. However, this
LARKIN, DI 11
Idaho Power Company
1 functional breakdown is not sufficiently detailed for cost-
2 of-service purposes . Individual plant items are examined
3 and, where possible, the associated investment costs are
4 assigned to one or more operating functions, such as
5 substations, primary lines, secondary lines, and meters.
6 This level of functionalization allows costs to be more
7 equi tably allocated among classes of customers.
8 Q.Please explain the process of allocation.
9 A.The process of allocation is merely one of
10 apportioning the total jurisdictional cost among classes by
11 introducing allocation factors into the process. An
12 allocation factor is nothing more than an array of numbers
13 which specifies the class value or share of a total
14 jurisdictional quantity.
15 Once individual costs have been allocated to the
16 various classes of service, it is possible to total these
17 costs as allocated and arrive at a breakdown of utility
18 rate base and expenses by class. The results are stated in
19 a summary form to measure adequacy of revenues for each
20 class. The measure of adequacy is typically the rate of
21 return earned on rate base compared to the requested rate
22 of return.
23 Q.Have you provided separate documentation
24 describing in detail the methodology used to prepare the
25 Company's class cost-of-service study?
LARKIN, DI 12
Idaho Power Company
1 A.Yes. Exhibit No. 30, the Class Cost-of-
2 Service Process Guide, describes in detail the methodology
3 used in the preparation of the Company's class cost-of-
4 service study.
5 III. COST-OF-SERVICE STUDY METHODOLOGY
6 Q.Have you prepared the Company's cost-of-
7 service study in a manner that is consistent with the
8 Commission's preferred methodology established in the 2008
9 Rate Case?
10 A.Yes. In the 2008 Rate Case proceeding, the
11 Company's cost-of-service methodology received a
12 considerable amount of review and evaluation by the parties
13 to the case and the Commission. In Order No. 30722, the
14 Commission identified the Company's "3CP/12CP" cost-of-
15 service study as its preferred method for assigning the
16 Company's Idaho jurisdictional revenue requirement to the
1 7 individual customer classes. The Commission reiterated its
18 support for the 3CP/12CP cost-of-service methodology when
19 it issued Order No. 30754 denying the Department of
20 Energy's Petition for Reconsideration regarding the
21 Commission's preferred cost-of-service methodology.
22 Q.Please provide a brief overview of the aspects
23 of the 3CP/12CP cost-of-service study that differentiate it
24 from the cost-of-service methodology applied by the Company
25
LARKIN, DI 13
Idaho Power Company
1 in general rate case proceedings prior to the 2008 Rate
2 Case.
3 A.The 3CP/12CP study differs from the Company's
4 previously approved cost-of-service studies in a number of
5 ways. First, the 3CP/12CP study allocates production plant
6 costs based on the nature of the load being served. Under
7 this approach, production plant costs associated with
8 serving summer peak load are allocated separately from
9 costs associated with serving base and intermediate load.
10 That is, the costs associated with building and operating
11 combustion turbines, which are used primarily to serve
12 summer peak loads, have been allocated to customers
13 differently than the costs associated with the Company's
14 other generation resources. In the Company's previously
15 approved cost-of-service studies, all of the Company's
16 generation plant was allocated to customer classes
17 according to a weighted 12 coincident peak demand basis.
18 Second, under the 3CP /12CP study, expenses
19 associated with power purchased according to the Public
20 Utility Regulatory Policy Act of 1978 ("PURPA") and other
21 purchased power expenses are classified as demand- and
22 energy-related in the same manner as steam and hydro
23 generation plant. In the Company's previously approved
24 cost-of-service studies, PURPA and purchased power expenses
25
LARKIN, DI 14
Idaho Power Company
1 were classified and allocated to customer classes on the
2 basis of energy only.
3 Lastly, the energy-related cost allocators, "E10S"
4 and "E10NS," are derived using an averaging approach. In
5 prior studies, the energy allocators E10S and E10NS were
6 derived using a two-step process under which summer and
7 non-summer ratios based on the monthly normalized energy
8 usage for each customer class were weighted by the monthly
9 marginal cost. The 3CP /12CP study incorporated a third
10 step by which the un-weighted summer and non-summer ratios
11 are averaged with the summer and non-summer ratios weighted
12 by the monthly marginal cost to derive the summer and non-
13 summer energy-related allocation factors E10S and E10NS,
14 respectively.
15 Q.Please provide a brief overview of the aspects
16 of the current cost-of-service study that differentiate it
17 from the cost-of-service methodology applied by the Company
18 in the 2008 Rate Case.
19 A.The overall class cost-of-service methodology
20 applied in this case is consistent with the 3CP/12CP
21 methodology approved in the 2008 Rate Case. However, a
22 number of allocation factors were adjusted to align with
23 changes in the Company's revenue requirement, and to align
24 with changes to the jurisdictional separation study
25 provided by Ms. Noe. For example, as discussed in the
LARKIN, DI 15
Idaho Power Company
1 testimony of Mr. Timothy E. Tatum, the 2011 Idaho
2 jurisdictional revenue requirement includes in Account 555,
3 Purchased Power, a base level amount of direct incentive
4 payments associated with the Company's demand response
5 ("DR") programs. These expenses were functionalized,
6 classified, and ultimately allocated to customer classes in
7 the same manner as the Company's investment in its
8 combustion turbines, which are used primarily to meet
9 summer peak loads. Because DR programs are also designed
10 to assist the Company in meeting summer peak loads, it is
11 appropriate to treat costs associated with these programs
12 in the same manner as corresponding supply-side resources
13 in the cost-of-service study.
14 Another modification to the 2011 cost-of-service
15 study is the allocation of Account 370, Meter Investment.
16 Due to the Company's current deployment of Advanced
17 Metering Infrastructure ("AMI" ) within its service area, a
18 change was needed to more accurately spread the allocation
19 of associated costs among customer classes. As displayed
20 in Exhibit No. 26 provided by Ms. Noe, the Idaho
21 jurisdictional portion of Account 370 is divided into three
22 subaccounts: AMI, Pre-AMI, and All Other Meters. To
23 properly allocate these costs to customer classes, an
24 allocation factor was developed recognizing the
25 applicability of each subaccount to the various rate
LARKIN, DI 16
Idaho Power Company
1 classes. The AMI and Pre-AMI subaccounts contain
2 investment in metering only for those classes subj ect to
3 AMI deployment. The Pre-AMI subaccount was allocated to
4 AMI-applicable rate classes according to the Company's
5 standard methodology utilizing the historical cost of
6 metering investment, and the AMI subaccount was allocated
7 to AMI-applicable rate classes based on the proportion of
8 expected AMI meter investment following full deployment at
9 the end of 2011. The All Other Meters subaccount was first
10 reduced by the amount of meter investment associated with
11 the Company's Cogeneration and Small Power Production and
12 sales for resale customers. This investment was allocated
13 to customer classes based on the "E10" allocator, which is
14 consistent with the Company's practice in previously
15 approved cost-of-service studies. The remaining investment
16 in the All Other Meters subaccount was allocated to non-AMI
17 rate classes based on each class's historical cost of
18 metering investment. The result of this methodology is an
19 allocation factor that represents each class's weighted
20 proportion of the applicable meter investment subaccounts.
21 It should be noted that this is an interim methodology that
22 will no longer be necessary once AMI is fully deployed and
23 historical metering cost information is available.
24 Finally, a modification was made to the development
25 of the functionalized classified revenue requirement for
LARKIN, DI 17
Idaho Power Company
1 each rate class, provided as Exhibit No. 36, for use in the
2 Company's rate design process and the calculation of the
3 components of the Fixed Cost Adjustment ("FCA"). In prior
4 cost-of-service studies, Other Operating Revenues were
5 functionalized and classified in the development of the
6 unit cost categories according to rate base. This use of
7 rate base as an allocation basis created an inconsistency
8 with the rest of the revenue requirement allocation
9 process. To remove this inconsistency, the current cost-
10 of-service study functionalizes and classifies these
11 revenues utilizing the same factors applied in the rest of
12 the revenue requirement allocation process. This results
13 in a more accurate and consistent allocation of Other
14 Operating Revenues.
15 Q.Please describe the classification of steam
16 and hydro production plant utilized in the cost-of-service
17 study.
18 A.In the class cost-of-service study all steam
19 and hydro production plant has been classified on a demand
20 and energy basis using the methodology preferred by the
21 Commission in prior general rate proceedings. The energy
22 portion of the steam and hydro production investment has
23 been determined by use of the Idaho jurisdictional load
24 factor of 53.88 percent. The computation of the Idaho
25 jurisdictional load factor is included in my workpapers.
LARKIN, DI 18
Idaho Power Company
1 By application of the load factor ratio to the steam and
2 hydro production plant investment, the energy-related
3 portion is easily determined. The balance of the steam and
4 hydro production plant investment is then classified as
5 demand-related. All other production and transmission
6 plant has been classified as demand-related.
7 Q.Did the Company use the most recent year's
8 load research data to derive the coincident demand values
9 used in the cost-of-service study prepared in this
10 proceeding?
11 A.Yes. In Order No. 30722, the Commission
12 accepted the Industrial Customers' and Staff's proposal to
13 derive the coincident demand allocators using the most
14 recent year's (in that case 2007) data rather than the
15 fi ve-year median approach developed in the cost-of-service
16 workshops established as part of Case No. IPC-E-04-23.
17 Consistent with the Commission's preferred approach, the
18 Company used 2010 load research data to derive the
19 coincident demand values used in the cost-of-service study
20 prepared in this proceeding.
21 Q.In the 2008 Rate Case, the Company made
22 adjustments to the coincident peak demand values in an
23 attempt to better reflect the impact that the Irrigation
24 Peak Rewards program has on the Company's peak demands.
25
LARKIN, DI 19
Idaho Power Company
1 Has the Company made any adj ustments to the coincident peak
2 demands to account for the impact of DR programs?
3 A.Yes. However, in this case, the Company has
4 modified the treatment of DR programs in the derivation of
5 coincident peak demands, and broadened the applicability of
6 the methodology to recognize the impact that all of its DR
7 programs have on the system peak demand.
8 Q.Please provide a brief description of each of
9 the DR programs that will be operated by the Company during
10 2011.
11 A.In 2011, the Company will operate three
12 separate DR programs: Irrigation Peak Rewards, A/C Cool
13 Credit, and FlexPeak Management. Irrigation Peak Rewards
14 is a DR program available to agricultural irrigation
15 customers. A/C Cool Credit is a DR program available to
16 residential customers in select areas within the Company's
17 service area where the necessary communication technology
18 is available. FlexPeak Management is a DR program
19 available to larger commercial and industrial customers.
20 These programs have allowed the Company to successfully and
21 cost-effectively reduce load during the summer afternoon
22 hours when demand for electricity is highest.
23 Q.Why is it necessary to adj ust coincident peak
24 demands to account for reductions from DR programs?
25
LARKIN, DI 20
Idaho Power Company
1 A.As my testimony states, a portion of the
2 revenue requirement within the class cost-of-service study
3 is allocated according to each class's proportional
4 contribution to the monthly system peaks. When DR programs
5 reduce demand at the time of the system peak, they have the
6 potential to reduce the participating class's coincident
7 peak demand, subsequently reducing its allocation of any
8 coincident peak demand-related costs. As a result, classes
9 without DR programs in effect during the system's peak hour
10 could receive a higher cost allocation when DR programs
11 successfully reduce peak hour demand.
12 Q.Could this result in inequitable cost
13 allocation?
14 A.Yes. DR programs are intended to generate
15 cost savings during system peak hours by reducing demand,
16 thus avoiding or reducing the need to acquire more costly
17 supply-side resources. In this sense, they are operated in
18 the same manner as traditional supply-side resources. Wi th
19 respect to the class cost-of-service study, the Company's
20 resource selection should not unduly affect the allocation
21 factors used to spread costs among customer classes. If
22 the effects of DR programs are not accounted for, cost
23 allocation can potentially be skewed when demand reductions
24 are achieved during peak hours. If no adjustments are
25 made, coincident peak demand allocators can potentially
LARKIN, DI 21
Idaho Power Company
1 shift cost allocation solely based on the Company's choice
2 to utilize a demand-side resource over traditional supply-
3 side peak resources.
4 Further, the Company's DR programs provide a
5 financial incentive to participants in exchange for
6 temporary load reduction. Any allocation benefi ts received
7 from DR program reductions that are not accounted for in
8 the initial incentive design provide the potential for an
9 unintended benefit to participating rate classes at the
10 expense of non-participating rate classes. These
11 allocation benefits are also received by all customers of a
12 participating rate class, although not all customers wi thin
13 each rate class participate in DR programs, resulting in
14 the potential for non-participating customers to receive a
15 benefit without providing any load reduction in return.
16 Finally, the costs of the Company's DR programs are
17 spread among all rate classes. The successful operation of
18 these programs results in system cost savings by avoiding
19 more expensive supply-side resources. Without adj ustment,
20 demand reductions during the time of the system peak can
21 potentially lower cost allocation to participating classes
22 while increasing cost allocation to other classes. This
23 creates the potential for rate classes to contribute to the
24 funding of DR programs, and then receive a higher cost
25 allocation when the programs are successful.
LARKIN, DI 22
Idaho Power Company
1 Q.Please describe the methodology used to adj ust
2 the coincident peak demand values to better reflect the
3 impact that the DR programs have on the Company's peak
4 demands.
5 A.The method for estimating system coincident
6 demands utilizes system coincident demand factors, which
7 represent the ratio of the system coincident demand to the
8 average demand. To derive the monthly system coincident
9 demands, monthly 2010 factors derived from historical load
10 research data are applied to the associated population's
11 monthly average demands for the test year.
12 To remove the potential for inequitable cost
13 allocation due to the effect of the DR programs, the
14 Company's proposed method derives system coincident demand
15 factors as if no DR programs had been in effect during the
16 historical data period. In doing so, DR programs receive
17 equal treatment to the Company's supply-side resources,
18 removing the potential for resource selection to unduly
19 affect the cost allocation process.
20 To accomplish this, historical load data was
21 adjusted to reflect system loads that would have occurred
22 had no DR programs been in effect. This was accomplished
23 by adding back estimated demand reductions achieved through
24 the respective DR programs to historical hourly system
25 loads. The resulting load shape reflects system loads that
LARKIN, DI 23
I9aho Power Company
1 the Company's supply-side resources would have been
2 required to meet without the availability of demand-side
3 resources. The adj usted data was then used to determine
4 the hour that the system peak would have occurred absent DR
5 programs, and system coincident demand factors were
6 calculated according to the adjusted peak hour and
7 historical usage data. Finally, these factors were applied
8 to forecast average demand to derive coincident peak
9 demands by rate class for each month of the test period. A
10 detailed description of the coincident peak demand
11 deri vation process is provided in the document Peak
12 Responsibili ty Methods for the 2011 General Ra te Case,
13 provided in my workpapers.
14 Q.How did the Company arrive at its proposed
15 methodology?
16 A.The effect of DR programs on the derivation of
17 coincident peak demands was discussed with subj ect matter
18 experts throughout the Company in Load Research, Regulatory
19 Affairs, Energy Efficiency, and Power Supply Planning. The
20 issue was also discussed with the well-respected industry
21 consultant Global Energy Partners, LLC, who published a
22 research document titled, Demand Response: It's A Resource,
23 So Treat It Like One. This document suggests treating DR
24 programs in the same manner as supply-side resources in the
25 derivation of coincident peak demands. The Company's
LARKIN, DI 24
Idaho Power Company
1 proposed methodology aligns with this suggested treatment,
2 and represents the consensus following extensive internal
3 discussion.
4 iv. COST-OF-SERVICE STUDY DESCRIPTION
5 Q. Have you prepared a table that summarizes the
6 basis by which each of the major functionalized cost
7 categories has been classified and subsequently allocated
8 to customer classes under the cost-of-service study?
9 A.Yes. The following table summarizes the basis
10 by which each of the major functionalized cost categories
11 is classified and subsequently allocated to customer
12 classes under the cost-of-service study:
13
Generation Plant
Hydro and Steam
Production 53.88% Energy & 46.12% Demand
Other Production
( Peaking Units)Demand
Transmission Plant Demand
Distribution Plant Demand and Customer
Other Expenses
Fuel Energy
Purchased Power 53.88% Energy & 46.12% Demand
Demand Response
Incenti ve Payments Demand
LARKIN, DI 25
Idaho Power Company
Generation Demnd
Hydro and Steam
Production
12CP without Marginal Generation
Cost Weighting
Other Production
(Peaking Units)
3CP without Marginal Generation
Cost Weighting
Demand Response
Incenti ve Payments
3CP without Marginal Generation
Cost Weighting
Genera tion Energy 12 Months Energy with Marginal
Energy Cost Weighting (averaged
w! un-weighted values)
Transmission 12CP with Marginal
Transmission Cost Weighting
Distribution 1NCP ! No. of Customers ! Direct
Assignment
1
2 Q.Please identify the exhibits that comprise the
3 cost-of-service study.
4 A.The cost-of-service study is comprised of the
5 following exhibits:
6 1.Exhibit No. 31, Functionalization and
7 Classification of Costs;
8 2.Exhibit No. 32, Summary of
9 Functionalized Costs;
10 3.Exhibi t No. 33, Allocation to Classes;
11 4.Exhibit No. 34, Summary of Class
12 Allocations;
LARKIN, DI 26
Idaho Power Company
1 5.Exhibi t No. 35, Revenue Requirement
2 Summary;
3 6.Exhibit No. 36, Class Cost-of-Service
4 Unit Costs;
5 7 .Exhibi t No. 37, Development of Weighted
6 Demand and Energy Allocators;
7 Q.Please describe Exhibit No. 31.
8 A.Exhibit No. 31 contains 145 pages and consists
9 of eleven Cost Functionalization and Classification Tables.
10 The functionalization and classification of each component
11 of rate base, operating revenue, and expense are treated in
12 detail in these tables. The tables are shown in the
13 following sequence:
14 . Table 1 - Electric Plant in Service;
15
16
17
18
19
20
21
. Table 2 - Accumulated Provision for
Depreciation;
. Table 3 - Additions and Deletions to Rate
Base;
. Table 4 - Operating Revenues;
22
23
24
25
26
27
28
. Table 5 - Operation and Maintenance
Expenses;
. Table 6 - Depreciation and Amortization
Expense;
. Table 7 - Taxes Other Than Income Taxes;
29 . Table 8 - Regulatory Debits/Credits;
30 . Table 9 - Income Taxes;
LARKIN, DI 27
Idaho Power Company
1
2
3
4
. Table 10 - Development of Labor-Related
Allocator; and
. Table 11 - Functionalization Allocators.
5 Q.What is the significance of the column header
6 "Allocator" on Exhibit No. 31?
7 A.This column identifies, by symbol, the basis
8 for each allocation. For example, for Accounts 310 through
9 316, Steam Production, shown at line 20 on page 1, the
10 constant "PI-S" is used to allocate the total investment in
11 steam production plant to the production function and to
12 the demand and energy cost classifications. The resultant
13 functionalization of costs may itself serve as a basis for
14 subsequent allocations. This use is illustrated at line
15 122 on page 21' where the accumulated depreciation for steam
16 production plant is allocated according to the same
17 allocator "PI-S" used at line 20.
18 Q .Please describe Exhibit No. 32.
19 A.Exhibit No. 32 summarizes in row format the
20 functionalized costs for each component of rate base and
21 expenses shown across the columns on Exhibit No. 31.
22 Q.Please describe Exhibit No. 33.
23 A.Exhibi t No. 33 details the allocation of the
24 summarized costs shown on Exhibit No. 32 to each customer
25 class, including the special contract customers. The
26 exhibit also includes a summary of results showing the
LARKIN, DI 28
Idaho Power Company
1 actual rate of return earned for each customer class and
2 special contract customer. The exhibit includes the
3 following tables:
4 . Table 1 - Plant in Service;
5
6
7
8
. Table 2 - Accumulated Reserve for
Depreciation;
. Table 3 - Amortization Reserve;
9 . Table 4 - Substation CIAC;
10
11
12
13
14
15
16
. Table 5 - Customer Advances for
Construction;
. Table 6 - Accumulated Deferred Income
Taxes;
17
.Table 7 -Acquisition Adj ustment;
.Table 8 -Working Capital;
.Table 9 -Deferred Programs;
.Table 10 -Subsidiary Rate Base;
.Table 11 -Plant Held for Future Use;
.Table 12 -Other Revenues;
.Table 13 -Operation &Maintenance
Expenses;
18
19
20
21
22
23
24
25 . Table 14 - Depreciation Expense;
26
27
28
29
. Table 15 - Amortization of Limited Term
Plant;
. Table 16 - Taxes Other Than Income;
30 . Table 17 - Regulatory Debi ts/Credi ts;
LARKIN, DI 29
Idaho Power Company
1
2
3
4
5
6
7
· Table 18 - Provisions for Deferred Income
Taxes;
8
.Table 19 -Investment Tax Credit
Adj ustment;
.Table 20 -Construction Work In Progress;
.Table 21 -State Income Taxes;
.Table 22 -Federal Income Taxes;and
.Table 23 - Allocation Factor Summary.
9
10
11 Q.Does the Class Cost-of-Service Process Guide,
12 Exhibit No. 30, detail the manner in which you allocated
13 the summarized costs shown on Exhibit No. 32 to each class
14 of service as shown on Tables 1 through 22 of Exhibit No.
15 33?
16 A.Yes. Exhibit No. 30, the Class Cost-of-
17 Service Process Guide, details the allocation methodology
18 that was applied to produce the results shown on Tables 1
19 through 22 of Exhibit No. 33.
20 Q.Does Exhibit No. 33 include a listing of the
21 allocation factors used to allocate to classes the various
22 costs shown on Tables 1 through 22?
23 A.Yes. Table 23 of Exhibit No. 33 includes a
24 listing of each allocation factor.
25 Q.Have the marginal costs used in the current
26 study been updated since the Company's previous study in
27 Case No. IPC-E-08-10?
LARKIN, DI 30
Idaho Power Company
1 A.Yes. Updated marginal energy costs were
2 calculated for the five-year period 2011 through 2015.
3 Q.Have you included information regarding the
4 derivation of the Company's updated marginal costs with
5 your testimony?
6 A.Yes. I have included a copy of the Company's
7 2011 Marginal Cost Analysis in my workpapers.
8 Q.Have the marginal costs been used to develop
9 the Company's revenue requirement?
10 A.No. The marginal costs have been used solely
11 for purposes of developing allocation factors and not for
12 purposes of developing the Company's revenue requirement.
13 Q.Have you prepared an exhibit that details the
14 derivation of the demand and energy allocation factors used
15 in the cost-of-service study?
16 A.Yes. Exhibit No. 37 details the derivation of
17 the allocation factors D10S, D10NS, D10P, D13, E10S, and
18 E10NS used in the cost-of-service study.
19 V. COST-OF-SERVICE STUDY RESULTS
20 Q.Please describe Exhibit No. 35.
21 A.Exhibi t No. 35 is the revenue requirement
22 summary based on the results of the cost-of-service study.
23 The section headed "Revenue Requirement for Rate Design"
24 details the sales revenue required from each customer class
25 and special contract customer. The sales revenue required
LARKIN, DI 31
Idaho Power Company
1 includes return on rate base, total operating expenses, and
2 incremental taxes computed using the net-to-gross
3 mul tiplier of 1.642 provided to me by Ms. Noe.
4 Q.Please summarize the results of the class
5 cost-of-service study which are detailed on Exhibit No. 35.
6 A.The results shown on Exhibit No. 35 indicate
7 that the Small General Service (Schedule 7), Large General
8 Service (Schedule 9), Large Power Service (Schedule 19),
9 Irrigation Service (Schedule 24), Traffic Control Lighting
10 Service (Schedule 42), and special contract (Micron,
11 Simplot, DOE/INL, and Hoku) customers should have an
12 increase in rates which is greater than the overall average
13 increase requested by the Company. In addition, the
14 results indicate that Dusk to Dawn Lighting (Schedule 15)
15 and Municipal Street Lighting (Schedule 41) should have a
16 decrease in rates from the current level.
17 Q.Did you provide the results of the cost-of-
18 service study to Mr. Michael J. Youngblood, Manager of Rate
19 Design, for use in the Company's rate design proposals?
20 A.Yes. I provided the class cost-of-service
21 unit costs, detailed on Exhibit No. 36, to Mr. Youngblood
22 for use by his group in determining the component charges
23 for each service schedule.
24 Q.Please describe Exhibit No. 36.
25
LARKIN, DI 32
Idaho Power Company
1 A.Exhibit No. 36 shows the unit cost for each
2 function for metered service schedules as determined
3 through the class cost-of-service study. The billing units
4 shown in the column labeled "(E)" reflect the billing
5 demands, normalized billing energy, basic load capacity,
6 and number of billings.
7 VI . REVENU REQUIRENT ALLOCATION
8 Q.What is the Company's general philosophy on
9 determining rates?
10 A.The Company's primary approach to ratemaking
11 in the last several general rate cases has been to
12 establish rates that reflect costs as accurately as
13 possible. Accordingly, the Company's ratemaking proposals
14 usually advocate movement towards cost-of~service results,
15 which assign costs to those customer classes that cause the
16 Company to incur the costs.
17 Q.Are there other obj ecti ves that may be
18 considered in the ratemaking process?
19 A.Yes. The Commission may consider a number of
20 other obj ecti ves, such as rate stability, in the
21 determination of rates.
22 Q.How did you approach the determination of the
23 revenue requirement for each customer class?
24 A.A pure cost-of-service revenue requirement
25 spread would result in substantial increases to Irrigation
LARKIN, DI 33
Idaho Power Company
1 Service, Traffic Control Lighting Service, and the four
2 special contract customers. In order to mitigate the
3 magnitude of the rate increase to each of these customer
4 classes that would be necessary to bring them to current
5 cost-of-service levels, the Company is proposing to cap the
6 percentage increase to those customer classes at one and
7 one-half times the overall average requested increase, or
8 14.85 percent. As proposed, Dusk to Dawn Lighting and
9 Municipal Street Lighting receive neither a decrease nor an
10 increase in rates.
11 Q.Did you discuss the results of the cost-of-
12 service study internally before deciding to apply the 14.85
13 percent caps to the specified customer classes?
14 A.Yes. I discussed the results of the cost-of-
15 service study and potential ra,te spread scenarios with Mr.
16 Gregory W. Said, who is responsible for the overall
17 preparation of this case. My revenue allocation is the
18 result of those discussions.
19 Q.Was the revenue allocation process affected by
20 the Company's Energy Sales Agreement ("ESA") with Hoku
21 approved by Commission Order No. 30748, and amended by
22 Commission Order No. 30869?
23 A.Yes. The ESA with Hoku prevents the Company
24 from modifying first block demand and energy charges, and
25 requires that second block charges increase or decrease
LARKIN, DI 34
Idaho Power Company
1 uniformly with charges to Large Power Service customers
2 taking service at the transmission voltage level (Schedule
3 19T customers). Because of these contract provisions, the
4 revenue requirement allocation process was adjusted to
5 comply with the ESA approved by Commission Order No. 30748,
6 and amended by Commission Order No. 30869.
7 Q.Do you have an exhibit that details the class
8 revenue requirement determination?
9 A.Yes. Exhibit No. 38 is a nine page exhibit
10 that steps through the revenue requirement allocation
11 process from the cost-of-service results to the ultimate
12 proposal for each customer class. Page 1 of Exhibit No. 38
13 presents the proformed normalized test year sales and
14 revenues. Page 2 details the results from the cost-of-
15 service study and illustrates the revenue changes that
16 would be made to each customer class to obtain the cost-of-
17 service results. Page 3 shows the revenue shortfall that
18 resulted by applying the 14.85 percent cap to Irrigation
19 Service, Traffic Control Lighting, Micron, Simplot,
20 DOE/INL, and no decrease to Dusk to Dawn Lighting or
21 Municipal Street Lighting.
22 Due to the previously described provisions of the
23 Hoku ESA, pages 3 through 5 exclude Hoku from the initial
24 phase of the cap-and-spread revenue requirement allocation
25 process. Because Hoku second block charges must change
LARKIN, DI 35
Idaho Power Company
1 uniformly with Schedule 19T ~ates, the percentage change to
2 Large Power Service must be determined before the revenue
3 requirement allocation to Hoku can be calculated. Page 4
4 shows the revenue shortfall that resulted by applying the
5 14.85 percent cap to Large General Service, which was
6 necessary following the spreading of the revenue shortfall
7 calculated on page 3. Page 5 shows the final proposed
8 increase to customer classes excluding Hoku after applying
9 the 14.85 percent cap and assigning no increase or decrease
10 to Dusk to Dawn Lighting or Municipal Street Lighting.
1l 'Page 6 shows the revenue shortfall that resulted
12 from including Hoku's first and second block revenues under
13 the previously described rate adj ustment limitations. In
14 accordance with the terms of the ESA, first block charges
15 received no change, and the percentage increase to second
16 block charges was set equal to that received by Large Power
17 Service at 13.02 percent. Page 7 displays the results of
18 spreading the revenue shortfall to customer classes that
19 resulted from the inclusion of Hoku's revenue requirement.
20 Page 8 displays the results of applying the 14.85 percent
21 cap to Small General Service, which was necessary following
22 the spread of the revenue shortfall that resulted from the
23 inclusion of Hoku's revenue requirement.
24 Page 9 shows the final proposed increase to customer
25 classes which resulted from spreading the revenue shortfall
LARKIN, DI 36
Idaho Power Company
1 created by the 14.85 percent cap, no increase or decrease
2 to Dusk to Dawn Lighting or Municipal Street Lighting, no
3 increase or decrease to Hoku's first block charges, and
4 uniformly increasing Hoku's second block charges with the
5 increase to Large Power Service to the remaining rate
6 classes in order to obtain the total Idaho jurisdictional
7 target revenue requirement. I have provided the results
8 from page 9 to Mr. Youngblood for his use in determining
9 the individual rates for the Company's general tariff and
10 special contract customers.
11 VII. LOAD CHAGE ADJUSTMNT RATE
12 Q.Please describe in general terms the purpose
13 of the LCAR.
14 A.The LCAR is a part of the Power Cost
15 Adjustment mechanism that is intended to eliminate recovery
16 of power supply expenses associated with load growth
17 resul ting from changing weather conditions, a growing
18 customer base, or changing customer use patterns.
19 Q.Please describe the LCAR methodology approved
20 by the Commission in Order No. 32206.
21 A.The methodology approved by the Commission in
22 Order No. 32206 directs the Company to calculate the LCAR
23 based on the energy classified portion of embedded
24 production revenue requirement as established in the cost-
25 of-service study. The final LCAR is calculated by dividing
LARKIN, DI 37
Idaho Power Compåny
1 this portion of revenue requirement by the Idaho
2 jurisdictional firm load for the test year.
3 Q.Have you determined the appropriate level for
4 the LCAR based upon the Company's proposed cost-of-service
5 study and the methodology approved by the Commission in
6 Order No. 3220 6?
7 A.Yes. By applying the methodology established
8 by Commission Order No. 32206 in Case No. GNR-E-10-03, the
9 LCAR should be decreased from the requested level of $19.67
10 in Case No. IPC-E-11-06 to $19.28 per megawatt-hour.
11 Q.Have you prepared an exhibit that details the
12 derivation of the revised LCAR?
13 A.Yes. Exhibi t No. 39, details the derivation
14 of the $19.28 LCAR amount.
15 Q.Does this conclude your testimony?
16 A.Yes, it does.
17
18
19
20
2l
22
23
24
25
LARKIN, DI 38
Idaho Power Company
RECEIVED
BEFORE THE 20" JUN -, PM 2: 46
IDld-in r;, d d'
IDAHO PUBLIC UTiliTIES COMMISSIC5l~J1Es-'cdi;/j;'d¡¡j;S¡ON
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO. 27
1SIDA..POC8
An IDACORP copany
To:
Febru 18,2011
Tim Tatu
Bar Smith
Date:
From:
Subject:Development of Sales Forecast for Revenue Calculation
Energy and Customer Forecast Development
The process used to develop futu year energy and customer counts by rate schedule and
jursdiction has two distict steps. il the first step, sales and customer forecasts ar developed on a
system-wide basis for each major customer segment or class; i.e., residential, commercial,
industral, irrgation and special contracts. il the second step, the sales and customer forecasts
developed in the first step ar allocated to each individual servce schedule or rate schedule. The
allocation basis used for each customer class forecast is the most curent histoncal year's weather
normalized electrcity sales (also refered to as weather-adjusted sales); in this case 2010 was used.
The histoncal 2010 weather-adjusted sales, available by rate schedule and jursdiction, are used only
to allocate the system class-level forecasts to rate schedule and jursdiction. The regression
equations used to weather-notmalize histoncal electrcity sales are not used in the long-ter
forecasts of electrcity sales.
Sales Forecasting Process
System Sales Forecast Development by Qass
A long-ter sales forecast is prepared, tyically once each year, for each customer class: residential,
commercial, industral, and irgation, as well as for each special contrct customer. The sales
forecast process is descnbed in detail in Appendix A - Sales and Load Forecast for the Integrated
Resource Plan (IR), to be filed June 2011.
The sales forecast models are dnven by the most recent available economic forecast. The economic
forecast is based on a forecast of national and regional economic activity developed by Moody's
Analytics, a national econometric consulting firm. Moody's Analytics July 2010 macroeconomic
forecast was used to develop the August 20 i 0 forecast for the 2011 IR. The national, state,
metropolitan statistical area (MSA), and county econometrc projections ar talored to
Idaho Power's service area using an economic database developed by an outside consultant.
National economic drivers from Moody's Analytics were also used in development of the most
recent sales forecast.
Economic growt assumptions infuence several of the individual class of serce growt rates.
Because growt in the number of households within individual counties in Idao Power's service
area differ from statewide household growt, servce area households are denved from
Exhibit No. 27
Case No. IPC-E-11-08
M. Larkin, IPC
Page 1 of5
county-specific household foreasts. The numbe of households, incomes, employment projections,
economic output, real retail electrcity pnces, and customer consumption patter are used to form
load projections.
The sales and load forecast is constrcte by developing a separte forecast for each individual sales
category. ildependent sales forecasts are prepared for each of the major customer classes:
residential, commercial, irgation, and industraL. ildividual energy forecasts are developed for
Micron Technology, Simplot Ferlizer, the Idaho National Laboratory (IN), and Hoku Materals,
ilc. (Hoku). The assumptions for each of the individua categones are descnbed in greater detail in
their respective sections in Appendix A -Sales and Load Forecast for the Integrated Resource Plan.
System residential sales are a fuction of a numbe of factors affecting electrcity sales to
that sector. Residential sales are a fuction of heating degree days (HDD) in witerime, cooling
degree days (CDD) in sumerme, the numbe of serce area households as derved from
Moody's Analytics forecasts of county housing stock, the real price of electrcity, and the real price
of natual gas. System commercial sales are also a fuction of HDD, CDD, the real pnce of
electrcity, and the number of serce area households, as well as serce area employment as
derived from Moody's Analytics forecasts. In the industral sector forecast, regression models were
developed for 17 industr groups to detere the relationship beteen histoncal electrcity sales
and histoncal employment or population, and other relevant explanatory vanables. The estimated
coeffcients from the industr group regression models were then applied to the appropnate
employment or population dnvers, reultig in the escalation of electrcity sales to the vanous
industr groups over time. The system irgation sales forast consider several factors affecting
electrcity sales to the irrgation class, including temperatue, precpitation, sprng rainfall, Moody's
Gross Product: Farr,for Idaho, and the real prce of electrcity.
Energy Forecast Development by Juridicton and Rat Schedule
To accurately estimate the revenue derved from energy and apply the appropnate charges to that
energy, it is necessar to develop a more-detailed energy forecast that provides a forecast of energy
sales by jursdiction and rate schedule. The models for allocating the system class-level sales
forecasts (residential, commercial, industral, and irgation classes) to jursdiction and rate schedule
were developed as follows:
Residential Energy Forecas
The residential class includes electrcity sales to customer takg serce under Schedule 1
(Schedules 3, 4, and 5, inclusive) and Schedule 15. Because the residential sales forecast was
developed on a system-wide basis by biling month, it was necessar to allocate the system-wide
residential sales forecast to each jursdiction and the appropnate rate schedules (Schedules 1 and
15). il this process, 2010 normalize energy was used to develop allocation factors for each
jursdiction and rate. The allocation factors were then applied to the system-wide biling month
residential sales forecast (excluding Schedule 15) to deterne the forecast of billng month
residential sales by rate schedule and jursdiction. This method results in Idaho jursdiction
residential sales (Schedule 1) that grow at essentially the same rate as Oregon jursdiction
residential sales. The Schedule 15 forecast energy figues in both the IPUC and OPUC jursdictions
were set to match the 2010 normalized energy figues (i.e., no sales growt). No sales growt was
assumed based on an histoncal trend of flat /no growth from 2000 though 2010.
Exhibit No. 27
Case No. IPC-E-11-08
M. Larkin, IPC
Page 2 of5
Commercial Energy Forecast
The commercial class includes electrcity sales to customer takng serce under Schedules 7, 9
(Pnmar, Seconda, and Tranmission Servce), 16,40,41, and 42. Because the commercial sales
forecast was developed on a system-wide basis by biling month, it was necessar to allocate the
system-wide commercial sales forecast to each jursdiction and the appropnate rate schedules
(Schedules 7, 9 Secondary and Pnar Serce). il this process, 2010 normalized energy was used
to develop allocation factors for each jursdiction and rate. The allocation factors were then applied
to the system-wide biling month commercial sales forecast (excluding Schedules 16, 40, 41, and
42) to deterne the forecast of biling month commercial sales by rate schedule and jursdiction.
The Schedules 9 Transmission Servce, 16,40,41, and 42 forecast energy figues in both the IPUC
and OPUC jursdictions were set to match the 2010 normalized energy figues (i.e., no sales
growth). No sales growt was assumed based on an histoncal trend of flat /no growt from 2000
through 2010.
Industral Energy Forecas
The industral class includes electrcity sales to customer tang serce under Schedule 19
(Pnmar, Seconda, and Tranmission Servce). Because the industral sales forecast was
developed on a system-wide basis by biling month, it was necessar to allocate the system-wide
industral sales forecast to each jursdiction and the approprate rate schedules (Schedules 19
Pnmar and Tranmission Serce). il this process, 2010 normalized energy was used to develop
allocation factors for each jursdiction and rate. The allocation factors were then applied to the
system-wide billng month industral sales forecast (excluding Schedule 19 Seconda Servce) to
deterne the forecast of biling month industral sales by rate schedule and jursdiction. Because
only one customer takes serce under Schedule i 9 Seconda Serce, forecat figues were set to
match the 2010 normalized energy figues (i.e., no sales growt). No sales growt was assumed
based on an histoncal trend of flat /no growt from 2000 though 2010.
Irrgatin Energy Forecas
The irgation class includes electrcity sales to customers tang serce under Schedule 24
Seconda Servce. Because the irgation sales forecast was developed on a system-wide basis by
biling month, it was necessar to allocate the system-wide irrgation sales forecast to each
jursdiction. il ths process, 2010 normalized energy was used to develop allocation factors for each
jursdiction. The allocation factors were then applied to the system-wide biling month irgation
sales forecast to deterne the forecast of biling month irrgation sales by jursdiction.
Energy Forecasts - Special Contracts
The special contrct energy forecasts for Simplot Ferlizer, Micron Technology, the IN, and Hoku
are each set directly to the values in the long-ter sales forecast in the appropnate jursdiction. For
this rate case, however, an adjustment was made regarding the treatment of the Hoku special
contract customer. The IRP forecast reflects a ramp-up schedule for Hoku that does not reach full
contract levels until early 2011, and maximum capacity in all months of the year until 2013. For
ratemakng puroses, 2011 usage has been anualized to reflect loads that would have occured
had Hoku been operating at its full contract level for all twelve months of the year. This
adjustment was made to allow the Company to develop rates based on a normalized anualized
test year rather than a one-time load patter that does not reflect tyical or expected customer
behavior on a long-term basis. More detail on the development of the long-ter sales forecast for
Exhibit No. 27
Case No. IPC-E-11-08
M. Larkin, IPC
Page 3 of5
each special contract customer can be found in Appendix A -Sales and Load Forecast for the
Integrated Resource Plan.
Expected Oregon Large Load Custmer
il Appendix A - Sales and Load Forecast for the Integrated Resource Plan, a new large load
customer is expected to begin taking servce in the Company's Oregon jurisdiction in late 2011.
Ths customer, however, is not included in the load forecast prepared for this rate case fiing. As
of the rate case fiing date, a final signed Electrc Serce Agreement (ESA) had not been
established between Idaho Power and this new large load. Whle the IR forecast must
incorporate expected large loads into the resource planng process, it is not appropnate to
include such loads in the ratemakng process until a contractul agreement for providing electrcal
serce has been finalized.
Customer Forecast Development
System Customer Forecast Development by Qass
Once each year a system customer count forecast is prared for each customer class: residential,
commercial, industral, and irgation. il the residential customer forecast, the number of residential
customers is a fuction of the number of new serce area households as denved from Moody's
Ana1ytics forecast of county housing stock and demographic data. Additionally, the number of
commercial customer being added each year is a fuction of the numbe of new residential
customer being added. The industral and irgation customer foreasts ar based on linear trends of
operating area customer counts that are allocated to months and then sumed to monthly class
totals. The customer forecast process is better descbed in Appendix A-Sales and Load Forecast for
the Integrated Resource Plan.
Customer Forecast Development by Jurisdictin and Rate Schedule
To accurately forecast the revenue denved from vanable customer charges, it is necessar to
develop a more-detailed customer forecast that provides customer counts by jursdiction and rate
schedule. The allocation of system class-level forecasts to jursdiction and rate schedules are bnefly
descnbed below for each individual class of customer.
Residential Customer Forecas
The residential class includes customer takg serce under Schedules 1, 3, 4, and 5. Since the
customer counts in all schedules except Schedule 1 are negligible in companson to Schedule 1, the
forecasts of all schedules except Schedule i were set to the most-recent month's actual customer
count, December 2010. Jursdictional split factors were calculated using the 12 months ending
December 2010 Schedule 1 actul customer counts by jursdiction. The resulting factors were
applied to the adjusted-system residential class customer forecast (adjusted downward by the
forecasted counts of the residential schedules descnbed above) to determe jursdictional counts
for Schedule 1.
Commercial Customer Forecast
The commercial class includes customer takg serce under Schedules 7, 9 (Pnar, Seconda,
and Transmission Serce), 40, 41, and 42. Since the customer counts in all schedules except
Exhibit No. 27
Case No. IPC-E-11-08
M, Larkin, IPC
Page 4 of5
Schedules 7 and 9 Secondar are small in comparson, the forecasts of all schedules except
Schedule 7 and 9 Seconda were set to the most-recent month's actua customer count (December
2010). Jursdictional split factors were calculated using the 12 month ending December 2010
Schedule 7 and 9 Seconda actul customer counts by jursdiction. The resulting factors wer then
applied to the adjusted-system commercial class customer forecast (adjusted downward by the
forecasted counts of the other commercial schedules descnbed above) to detere jursdictional
counts for Schedule 7 and 9 Seconda. Additionally, the IPUC jursdiction Schedule 7 and 9
Secondar customer count forecasts were reallocated based on a histoncal trend analysis of the
relationship beteen Schedule 7 and 9 Secondar customer counts within the IPUC jursdiction to
more accurately reflect futu customer counts.
Industl Customer Forecast
The industral class includes customer tag serce under Schedule 19 (Pnma, Seconda, and
Transmission Serce). Since the customer counts in schedules 19 Seconda and 19 Transmission
Servce are small in comparson to Schedule 19 Pnmar, the forecasts of those schedules were set to
the most-recent month's actual customer count (December 2010). Jursdictional split factors were
estimated using the 12 months endig December 2010 Schedule 19 Pnar actu customer counts
by jursdiction. The resulting factors were then applied to the remaing system industral class
customer forecast (adjusted downward by the forecasted counts of the Schedule 19 Secondar and
19 Tranmission Serce schedules descrbed above) to determne jursdictional counts for Schedule
19 Pnmar.
Irrgaton Customer Forecas
The irgation class includes customers takg serce under Schedule 24 Seconda Serce.
Jursdictional split factors were estimated using the 12-months ending December 2010 Schedule 24
Secondary actu customer counts by jursdiction. The resulting factors wer then applied to the
system irrgation class customer forecast to detere jursdictional counts for Schedule 24
Secondar.
Summary
Ths sumarzes the development of both the energy sales and customer counts used as inputs to
the calculation of normalized revenue.
If you have questions or require additional information, please let me know.
C: Matt Larkin
Greg Said
Catie Miler
Brad Snow
Scott Sparks
Mike Youngblood
Exhibit No, 27
Case No. IPC-E-11-08
M, Larkin, IPC
Page 5 of5
RECEIVED
BEFORE THE 20" Jmi-i PM 2: 46
lO-/\t"'10
IDAHO PUBLIC UTILITIES COMMISSIÓrJT1E'3
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO. 28
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Case No. IPC-E-11-Q8
M. Larkin, IPC
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Case No. IPC-E-11-08
M, Larkin, (PC
Page 4 of 10
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Exhibit No. 28
Case No. IPC-E-11-08
M. Larkin, IPC
Page 6 of 10
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Exhibit No. 28
Case No. IPC-E-11-08
M, Larkin, IPC
Page 7 of 10
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Exhibit No. 28
Case No. IPC-E-11-08
M. Larkin, IPC
Page 8 of 10
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Exhibit No. 28
Case No. IPC-E-11-08
M. Larkin, IPC
Page 9 of 10
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Exhibit No. 28
Case No. IPC-E-11-08
M, Larkin, IPC
Page 10 of 10
BEFORE THE
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IDAHO POWER COMPANY
LARKIN, 01
TESTIMONY
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RECEIVED
BEFORE THE 20li.JUN -I PH 2: 4'
. i(Jlt¡~'-1C)
IDAHO PUBLIC UTILITIES COMMISSIONTluTH::s
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
LARKIN, 01
TESTIMONY
EXHIBIT NO. 30
CLASS COST-Of-SERVICE PROCESS GUIDE
The following is a technical description of Idaho Power Company's Class Cost of Service study.
The methodology for separating costs among classes consists of a three-step process generally
referred to as classification, functionalization, and allocation. In all three steps, recognition is
given to the way in which the costs are incurred by relating these costs to the way in which the
utilty is operated to provide electrical service.
PROCESS OVERVIEW
Classification
The Electric Utilty Cost Allocation Manual, published in January of 1992 by the National
Association of Regulatory Utilty Commissioners, serves as the basis for the Company's
classification process. Classification refers to the identification of a cost as being either
customer-related, demand-related, or energy-related. These three cost components are used to
reflect the fact that an electric utilty makes service available to customers on a continuous
basis, provides as much service, or capacity, as the customer desires at any point in time, and
supplies energy, which provides the customer the abilty to do useful work over an extended
period of time. These three concepts of availabilty, capacity, and energy are related to the
three components of cost designated as customer, demand, and energy components,
respectively. In order to classify a particular cost by component, primary attention is given to
whether the cost varies as a result of changes in the number of customers, changes in demand
imposed by the customers, or changes in energy used by the customers.
Examples of customer-related costs are the plant investments and expenses that are
associated with meters and service drops, meter reading, biling and collection, and customer
information and services as well as a portion of the investment in the distribution system. These
investments and expenses are made and incurred based on the number of customers,
regardless of the amount of energy used, and are therefore generally considered to be fixed
costs. Demand-related costs are investments in generation, transmission, and a portion of the
distribution plant and the associated operation and maintenance expenses necessary to
accommodate the maximum demand imposed on the Company's system. Energy-related costs
are generally the variable costs associated with the operation of the generating plants, such as
fueL. However, due to the hydro production capabilty of the Company, a portion of the hydro
and thermal generating plant investment has historically been classified as energy-related.
Functionalization
In addition to classification, costs must be functionalized; that is, identified with utilty operating
functions. Operating functions recognize the different roles played by the various facilties in the
electric utility system. In the Company's accounts, these various roles are already recognized
to some degree, particularly in the recording of plant costs as production-, transmission-, or
distribution-related. However, this functional breakdown is not in sufficient detail for cost-of-
service purposes. Individual plant items are examined and, where possible, the associated
investment costs are assigned to one or more operating functions, such as substations, primary
Exhibit No. 30
Case No. IPC-E-11-08
M. Larkin, IPC
Page 1 of8
lines, secondary lines and meters. This level of functionalization allows costs to be more
equitably allocated among classes of customers.
Allocation and Summarization of Results
Once costs have been classified and functionalized, they are allocated to rate classes based on
the appropriate allocation factors. After individual costs have been allocated to the various
classes of service, it is possible to total these costs as allocated and arrive at a breakdown of
utility rate base and expenses by class. The results are stated in a summary form to measure
adequacy of revenues for each class. The measure of adequacy is typically the rate of return
earned on rate base compared to the requested rate of return.
ASSIGN MODULE AND FUNCTIONALIZED COST MODULE
The class cost-of-service model is comprised of two separate Microsoft Excel workbooks. The
first workbook, called the Assign Module, performs the previously described classification and
functionalization processes. This workbook categorizes the Idaho jurisdictional costs identified
by FERC account into operating functions, such as production, transmission, distribution,
metering, customer service, etc. It also categorizes the functional costs into demand-, energy-,
and customer-related classifications. For example, the Assign Module categorizes the
Company's investment in steam plant into the production function and the demand- and energy-
related classifications.
The second workbook, called the Functionalized Cost Module, or "FC Module" for short,
performs the class allocation process. This module allocates the classified and functionalized
costs developed in the Assign Module to the various customer classes. For example, the FC
Module allocates the demand- and energy-related production costs identified in the Assign
Module to each of the Company's customer classes and special contract customers. Each of
the major operations performed by this module is shown as a separate worksheet to make the
allocation process transparent and easy to understand.
CLASSIFICATION
Steam and Hydro Production
In the class cost-of-service study all steam and hydro production plants have been classified on
a demand and energy basis using the methodology preferred by the Idaho Public Utilties
Commission in prior general rate proceedings. The energy portion of the steam and hydro
production investment has been determined by use of the Idaho jurisdictional load factor. By
application of the load factor ratio to the steam and hydro production plant investment, the
energy-related portion is easily determined. The balance of the steam and hydro production
plant investment is then classified as demand-related. All other production and transmission
plants have been classified as demand-related.
Exhibit No. 30
Case No. IPC-E-11-08
M. Larkin, IPC
Page 2 of8
PURPA and Purchased Power Expenses
PURPA and purchased power expenses booked to FERC Account 555 are classified as
demand-and energy-related in the same manner as steam and hydro generation plant. Under
the previous approach of classifying these expenses as energy only, customers who use a
larger proportion of energy with respect to their demand (higher load factors) receive a greater
allocation of these expenses than would have occurred if a power plant had been constructed to
serve the same loads. For example, if the Company had chosen to build and operate a power
plant to serve the same customer loads served by purchased power, the plant would have been
classified as both demand and energy. With that said, it is reasonable to classify these
expenses as demand- and energy-related in the same manner as the Company's steam and
hydro generation plant. Under this methodology, PURPA and purchased power expenses are
classified according to the same ratio of demand to energy used in the classification of hydro
and steam generation plant.
Distribution Plant
Distribution substation plant Accounts 360, 361, and 362 are classified as demand-related.
Distribution plant Accounts 364, 365, 366, 367, and 368 are classified as either demand-related
or customer-related using the same fixed and variable ratio computation method utilized in the
Company's prior general rate case proceedings. The fixed to variable ratio is updated
according to a system capacity utilzation measurement based on a three-year average load
duration curve.
FUNCTIONALIZATION
General Plant
General plant is functionalized based on total production, transmission, and distribution plant.
As a result, a portion of general plant is assigned to each production, transmission, and
distribution function based on each function's proportion to the total.
Accumulated Provision for Depreciation
The accumulated provision for depreciation is functionalized using the resulting functionalization
of costs for the appropriate plant item. For example, the accumulated depreciation for steam
production plant shown is functionalized based on the functionalization of steam production
plant in service.
Additions to and Reductions from Rate Base
Deductions from rate base include customer advances for construction and accumulated
deferred income taxes. Customer advances are functionalized based on the distribution plant
investment against which the advances apply. Accumulated deferred taxes are functionalized
based on total plant investment. Additions to rate base consist of fuel inventory, which is
functionalized based on energy production, and materials and supplies, which are functionalized
based on the appropriate plant function. Deferred conservation expenses are functionalized
Exhibit No, 30
Case No. IPC-E-11-08
M. Larkin, IPC
Page 3 of8
based on the Idaho junsdictional load factor resulting in a specific percentage of the deferred
expenses being functionalized to energy production and the remainder being functionalized to
demand production.
Other Operating Revenue
Other operating revenue is functionalized based on either the functionalization of the related
rate base item or, in the situation where a particular revenue item may be identified with a
specific service, the functionalization of the specific service item.
O&M Expense
In general, the basis for the functionalization of O&M expense is the same as that for the
associated plant.
Labor Components
For each applicable expense account in each functional group, the labor component is
separately functionalized. For example, for Accunt 535 the labor-related supervision and
engineering expense is functionalized based on the cumulative labor as functionalized for
Accounts 536 through 540. In a similar fashion, the allocation of supervision and engineenng
associated with hydraulic maintenance expense, Account 541, is based on the composite labor
expense for Accounts 542 through 545. Total functionalized labor expense serves the additional
purpose of functionalizing employee pensions and other labor-related taxes and expenses.
Depreciation Expense, Taxes Other than Income, and Income Taxes
Depreciation expense is functionalized based on the function of the associated plant. Taxes
other than income are also functionalized based on the function of the source of the tax.
Deferred income taxes are functionalized based on plant investment. The functionalization of
federal and state income taxes is based on the functionalization of total rate base and
expenses.
ALLOCATION
Derivation of Peak Demands
For customers taking service through interval meters, system coincident demands are taken
directly from their meter read data. For all other customers coincident demands are estimated
through the use of system coincident demand factors. These factors are defined as the ratio of
the system coincident demand to the population's average demand. To determine the monthly
system coincident peak demands by rate class, each class's monthly system coincident
demand factors from the load research sample are applied to the test year monthly average
demand values for each class. Similarly, a non-coincident (or "group") demand factoris defined
as the ratio of a population's non-coincident peak demand to the population's average demand.
To determine the monthly non-coincident peak demands by rate class, each class's monthly
non-coincident demand factors from the load research sample are applied to the test year
monthly average demand values for each class.
Exhibit No. 30
Case No. IPC-E-11-08
M. Larkin, IPC
Page 4 of8
Customers are biled throughout each month and billng periods, or cycles, typically include
portions of more than one calendar month. Billng period data is converted into calendar month
data using a nonlinear method based on load research data that utilzes actual daily usage
patterns. Total daily consumption is assumed to fluctuate in proportion to the fluctuations in the
daily consumption of the load research sample customers. This methodology captures the
effects of weather on energy consumption and improves the process of determining coincident
peak demand responsibilty.
Marginal Cost Usage
While the 3CP/12CP methodology eliminates the need for marginal cost weighting in the
allocation of production plant costs, this weighting is stil necessary to properly seasonalize
energy- and transmission-related costs. The use of marginal cost weighting strikes a balance
between backward-looking costs already incurred and forward-looking costs to be incurred in
the future, and injects into the allocation process recognition of the influence seasonal load
profiles have on cost causation.
The marginal costs associated with new resource integration are seasonalized based on the
monthly peak-hour generation deficiencies which the Company expects to encounter during the
next five years of the planning period based on the 90th percentile water and 70th percentile
load criteria used for planning purposes. The relative sizes of the five-year average monthly
peak-hour deficiencies identified in the IRP are used to define the share of the annual capacity
cost assigned to each month. The marginal costs associated with planned system expansions
are seasonalized based on the monthly share of projected peak-hour load growth. The total
demand-related transmission marginal costs for each month are then derived by adding the
monthly values for both categories of transmission costs.
Updated marginal energy costs are calculated by quantifying the difference in net power supply
costs resulting from the addition of 50 megawatts of load to all hours of the Company's base
case system simulation run for the five-year planning period. It should be noted that the
marginal costs have been used solely for purposes of developing allocation factors and not for
purposes of developing the Company's revenue requirement.
Production Plant Cost Allocation
The class cost-of-service study allocates the costs of the Company's generation peaking
facilties differently than its base-load resources. Rather than allocating all production plant
based on the same allocation factor, this method allocates production plant costs based on the
nature of the load being served. Under this approach, production plant costs associated with
serving summer peak load are allocated separately from costs associated with serving the base
and intermediate load. That is, the costs associated with building and operating combustion
turbines, which are used primarily to serve summer peak loads, have been allocated to
customers differently than the costs associated with the Company's other generation resources.
This method allocates production plant costs associated with serving base and intermediate
load using an average of 12 monthly coincident demands ("2CP"), without marginal cost
weighting. Using an un-weighted 12CP allocator is appropriate in this case given that fixed
Exhibit No. 30
Case No, IPC-E-11-08
M. Larkin, IPC
Page 5 of8
base and intermediate generation costs do not vary greatly betwen the summer and non-
summer seasons. Furthermore, the study allocates fixed generation costs associated with
serving peak load using an average of the three coincident peak demands ("3CP") occurring in
June, July, and August. This method of allocation isolates the costs associated with peaking
resources and allocates those costs according to the load that is causing the investment.
The cost allocation method used in the study is based on the concept that the costs associated
with each of the Company's generation resources can be categorized according to the type of
loads being served. Utilties typically experience three distinct time-based production costing
periods that are driven by customer loads. The costing periods are normally identified as base,
intermediate, and peak. The base period is equivalent to a low load or off-peak time period
where loads are at the lowest, normally during the nighttime hours. The intermediate time
period represents the shoulder hours which are driven by the mid-peak loads that typically occur
throughout the winter daytime and in the early morning and late evening during the summer
months. The peak category is driven by the peak loads that occur during summer afternoons
and evenings. The base and intermediate loads on the Company's system are typically served
by the same generation resources. In recognition of that fact, those two categories have been
combined for cost allocation purposes. The generation resources that serve the peak loads,
Le., combustion turbines, are normally only utiized for that single purpose. Consistent with that
concept, the costs associated with peak-related resources have been segmented into a second
category for cost allocation purposes. Using this methodology there is no need for marginal
cost weighting because the seasonal nature of the loads is reflected in the allocation factors.
The production plant costs that have been classified as serving base and intermediate load are
captured in Accounts 310-316, Steam Production, and Accounts 330-336, Hydraulic Production.
The costs identified under the Steam Production category represent the Company's investment
in coal-fired generation facilties, and the costs identified under the Hydraulic Production
category represent the Company's investment in its hydroelectric generation facilties.
Utilties typically utilize their generation resources to serve customer loads by operating the
resources with the lowest operating cost first and as demand grows more costly resources are
then dispatched. This is no different for Idaho Power. However, since hydroelectric generation
is such a significant portion of the Company's resource stack, stream flow conditions and
economics can influence the proportionate share of output provided by steam and hydro
resources throughout the year. Since hydroelectric output is highly dependent upon stream
flows, steam production is ramped up or down according to the production capabilty of the
hydro. Therefore, throughout the year, hydro and steam production plants are utilized at varying
proportions to serve base and intermediate loads accrding to the production capabilities of the
hydro plants. However, the combined monthly output of these two resource types does not vary
significantly between the summer and non-summer months as does the output of the
combustion turbines.
Accounts 340-346, Other Production, contain the Company's investment in gas-fueled
production plant. The production plant investment captured in Accounts 340-346 represents the
Company's investment in the combustion turbine generation facilties used to serve peak
Exhibit No. 30
Case No. IPC-E-11-08
M. Larkin, IPC
Page 6 of8
demands. The only investment identified as peaking plant is the investment in combustion
turbine generation resources that were constructed specifically to meet the summer peak loads.
In the Functionalized Cost Module, the names "010BS" and "010BNS" describe the factors
used to allocate the production plant associated with serving the base and intermediate loads.
The name "010P" is used to describe the allocation factor used to allocate the production plant
associated with serving the peak loads. The 010BS and 010BNS represent the non-weighted
average twelve coincident peak demands for the summer and non-summer seasons
respectively. The allocator 010P represents the non-weighted average three coincident peak
demands for the summer months of June, July, and August.
Transmission and Distribution Cost Allocation
The Company's approach to cost allocation for transmission and distribution facilities is an
effective method for equitably assigning costs to customer classes. Under this method,
transmission and distribution costs are properly segmented according to the manner in which
the costs are imposed on the system. As a result, the cost responsibilty of each class can be
effectively identified through a combination of direct cost assignment and cost allocation based
on the appropriate demand- or customer-based factors.
The allocation factor 013 is used to allocate transmission costs to customer classes. The first
step in deriving this factor is to calculate ratios based on the sum of the actual coincident peak
demands for each customer class. Second, weighted coincident peak demand values are
derived by multiplying the actual monthly coincident peak demands by the monthly transmission
marginal costs. Corresponding weighted ratios are then calculated for each customer class.
Finally, the actual ratios are averaged with the weighted ratios to derive the non-seasonalized
transmission allocation factor 013. The Company applies this "averaging approach" as a rate
stabilty measure intended to mitigate any extreme impacts that the marginal costs may have on
cost allocation.
The capacity components of distribution plant, both primary and secondary, are allocated by the
non-coincident group peak demands for. each customer class identified as demand allocation
factors 020, 030, 050, and 060. The customer components of distribution plant, both primary
and secondary, are allocated by the average number of customers identified as customer
allocation factors C20, C30, C50 and C60.
Energy-Related Cost Allocation
The energy-related cost allocators, E10S and E10NS, are derived by averaging the normalized
energy values for each customer class with the normalized energy values weighted by the
marginal energy costs. First, summer and non-summer ratios based on each class's
proportionate share of the total normalized energy usage for the test year are determined. Next,
summer and non-summer ratios based on the monthly normalized energy usage for each
customer class weighted by the monthly marginal cost are calculated. Finally, these two values
are averaged, resulting in the E10S and E10NS allocators used in this study. This averaging
Exhibit No. 30
Case No. IPC-E-11-08
M. Larkin, IPC
Page 7 of8
approach is consistent with the methodology used in the derivation of the demand-related
allocation factor D13.
Customer Accounting and Customer Assistance Expense Allocation
The principal customer accounting expenses which require allocation are meter reading
expenses, customer records and collections, and uncollectible accounts. The meter reading
and customer records and collection expenses are allocated based upon a review of actual
practices of the Company in reading meters and preparing monthly bils. The allocation of
uncollectible amounts is similarly based upon a review of actual Company data. Customer
assistance expenses are allocated based on the average number of customers in each class.
State and Federal Income Tax Allocation
The state and federal income taxes for the Idaho jurisdiction are allocated to each customer
class and special contract customer according to each class's allocated share of rate base.
Once the state and federal income taxes are allocated to each customer class, they are
functionalized based on the functionalization of total rate base and expenses for each class.
REVENUE REQUIREMENT AND APPLICATION
Once all costs have been properly functionalized, classifed, and allocated, the Company is able
to determine the revenue requirement for each customer class. The sales revenue required
includes return on rate base, total operating expenses, and incremental taxes computed using
the net-to-gross multiplier.
Exhibit No. 30
Case No, IPC-E-11-08
M. Larkin, IPC
Page 8 of8
BEFORE THE
RECEIVE'D
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UTIL
IDAHO PUBLIC UTILITIES COMMISSION ,"J
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
LARKIN, 01
TESTIMONY
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M. Larkin, IPC
Page 19 of 145
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M. Larkin, IPC
Page 20 of 145
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Page 26 of 145
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Exhibit No. 31
Case No. IPC-E-11-08
M. Larkin, IPC
Page 65 of 145
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Exhibit No. 31
Case No. IPC-E-11-08
M. Larkin, IPC
Page 93 of 145
1 2 3 4 5 6 7 8 9
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Case No. IPC-E-11-08
M. Larkin, IPC
Page 95 of 145
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Page 131 of 145
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9
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11
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9
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9
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9
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5
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3
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58
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11
0
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6
7
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46
%
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6
%
(I
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(0
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(P
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2
8
7
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15
,
7
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22
3
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7
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1
4,
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7
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3
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19
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49
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9
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27
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4
4
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1
19
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3
9
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1
9
7
2
0
3
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1
1
9
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3
2
7
P1
1
2
P
5%
0%
8%
4%
0%
1%
1%
0%
5%
22
0
,
1
6
8
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2
7
3
3,9
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3
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3
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31
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7
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48
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27
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1
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5
1
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9
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4
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6
9
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2
0
0
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6
3
0
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5
7
8
P1
1
1
P
5%
0%
8%
4%
0%
1%
1%
0%
5%
24
3
,
3
5
7
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2
7
6
27
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0
6
9
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3
4
5
31
9
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7
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3
27
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1
1
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1
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9
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4
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9
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2
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0
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6
3
0
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5
7
8
P1
0
1
P
6%
1%
8%
4%
0%
1%
1%
0%
5%
24
6
,
3
7
6
,
0
3
3
27
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4
0
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1
3
1
32
3
,
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8
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4
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9
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2
0
3
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1
1
9
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3
2
7
P1
1
0
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6%
1%
8%
4%
0%
1%
1%
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5%
22
8
,
7
9
5
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1
1
7
25
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4
4
9
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5
5
4
30
0
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6
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17
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1
8
8
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6
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5
P-
P
T
D
6%
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8%
4%
0%
1%
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5%
24
6
,
3
7
6
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0
3
3
27
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4
0
5
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1
3
1
32
3
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6
8
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1
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7
P1
1
0
P
-
L
2
0
7%
1%
10
%
5%
1%
1%
1%
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6%
14
,
5
6
2
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1
5
8
1,
6
1
9
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7
9
2
19
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1
3
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6
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6
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4
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6
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2
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1
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3
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12
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4
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3
GE
N
-
P
L
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6%
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8%
4%
0%
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5%
4,
0
3
6
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3
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91
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6
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2
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LA
B
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10
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5%
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6,
7
5
0
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9
9
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5
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15
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7
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M
.
M
1%
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3%
1%
0%
0%
0%
0%
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6,
3
0
1
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7
6
1
68
0
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2
5
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10
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3
3
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17
6
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3
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1,
8
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6
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1%
9%
5%
0%
0%
0%
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2%
13
,
0
5
2
,
7
5
8
1,
4
0
5
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9
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1
24
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4
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1
33
4
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1
2
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6
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9
0
3
O&
M
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2%
0%
4%
2%
0%
0%
0%
0%
1%
L-
5
0
0
1
ID
A
H
O
P
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W
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A
N
Y
2
BE
F
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3
CL
A
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4
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l
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l
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D
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G
D
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C
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M
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3
1
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2
0
1
1
5
FU
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C
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A
L
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6
(A
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.
(
S
)
(T
)
(U
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(V
)
(W
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(X
)
(Y
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7
.
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.
8
AL
L
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T
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SE
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ME
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S
ST
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IN
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T
A
L
L
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T
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N
9
SE
C
C
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DE
M
A
N
D
CU
S
T
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M
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R
LI
G
H
T
S
CU
S
T
P
R
E
M
91
8
D3
6
0
2
N
8%
4%
2%
4%
8%
0%
0%
91
9
DA
R
K
F
I
B
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P
R
O
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C
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N
U
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(
A
C
C
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4
5
4
)
10
5
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2
2
9
,
2
5
3
53
,
0
2
5
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7
1
2
29
,
5
8
1
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7
2
2
55
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3
3
4
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4
3
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1
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3
9
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1
6
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3
9
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7
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92
0
(D
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R
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D
F
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A
C
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L
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)
D-
F
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B
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8%
4%
2%
4%
7%
0%
0%
92
1
ME
R
C
H
A
N
D
I
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10
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2
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4
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6
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5
3
9
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7
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92
2
(D
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D
F
R
O
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A
C
T
U
A
L
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)
M-
R
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V
10
%
5%
3%
5%
0%
0%
92
3
ME
R
C
H
A
N
D
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N
G
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P
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10
5
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2
2
9
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2
5
3
53
,
0
2
5
,
7
1
2
29
,
5
8
1
,
7
2
2
55
,
3
3
4
,
4
3
2
4,
1
6
0
,
0
8
2
2,
5
3
9
,
7
9
2
92
4
(D
E
R
I
V
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D
F
R
O
M
A
C
T
U
A
L
S
)
M-
E
X
P
10
%
5%
3%
5%
0%
0%
92
5
CU
S
T
O
M
E
R
A
D
V
A
N
C
E
S
F
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R
C
O
N
S
T
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T
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N
3,6
1
9
,
1
5
1
2,
0
1
9
,
0
3
4
4,
5
1
1
,
2
6
6
62
,
6
4
4
(3
,
8
2
9
)
92
6
CU
S
T
A
D
V
13
%
7%
16
%
0%
0%
92
7
36
4
-
3
6
5
CO
M
B
I
N
E
D
D
I
S
T
R
I
B
U
T
I
O
N
A
L
L
O
C
A
T
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R
19
,
2
1
5
,
8
7
4
10
,
7
2
0
,
0
5
7
92
8
L
9
0
-
9
1
D-
3
6
4
-
3
6
5
6%
3%
92
9
36
6
-
3
6
7
CO
M
B
I
N
E
D
D
I
S
T
R
I
B
U
T
I
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N
A
L
L
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C
A
T
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R
33
,
8
0
9
,
8
3
8
18
,
8
6
1
,
6
6
6
93
0
L
9
2
-
9
3
D-
3
6
6
-
3
6
7
14
%
8%
93
1
90
2
-
9
0
4
CO
M
B
I
N
E
D
D
I
S
T
R
I
B
U
T
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A
L
L
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C
A
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R
93
2
L
4
8
1
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8
3
D-
9
0
2
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Case No. IPC-E-11-08
M. Larkin, IPC
Page 142 of 145
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RECEIVED
BEFORE THE 20 II JUN - I PM 2: 47
IDAHO
¡'Til ¡riFSIDAHO PUBLIC UTILITIES COMMISSION --
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
LARKIN, 01
TESTIMONY
EXHIBIT NO. 32
1
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IDAHO PUBLIC UTILITIES COMMISŠ1lÖfi;
CASE NO. IPC-E-11-08
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IDAHO POWER COMPANY
LARKIN, 01
TESTIMONY
EXHIBIT NO. 33
1
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Exhibit No. 33
Case No. IPC-E-11-08
M. Larkin, IPC
Page 3 of 48
53
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Exhibit No. 33
Case No. IPC-E-11-08
M. Larkin, IPC
Page 6 of 48
17
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Exhibit No. 33
Case No.IPC-E-11-08
M. Larkin, IPC
Page 9 of 48
23
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Case No. IPC-E-11-08
M. Larkin, IPC
Page 14 of 48
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Exhibit No. 33
Case No. IPC-E-11-08
M. Larkin, IPC
Page 17 of 48
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Exhibit No. 33
Case No. IPC-E-11-08
M. Larkin, IPC
Page 22 of 48
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Exhibit No. 33
Case No.IPC-E-11-08
M, Larkin, IPC
Page 23 of 48
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Exhibit No. 33
Case NO.IPC-E-11-08
M. Larkin, IPC
Page 24 of 48
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Exhibit No. 33
Case No. IPC-E-11-08
M. Larkin, IPC
Page 27 of 48
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Exhibit No. 33
Case No. IPC-E-11-08
M. Larkin, IPC
Page 31 of 48
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Exhibit No. 33
Case No.IPC-E-11-08
M. Larkin, IPC
Page 33 of 48
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Exhibit No. 33
Case No. IPC-E-11-08
M. Larkin, IPC
Page 35 of 48
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Exhibit No. 33
Case No.IPC-E-11-08
M. Larkin, IPC
Page 42 of 48
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Exhibit No. 33
Case No.IPC-E-11-08
M. Larkin, IPC
Page 43 of 48
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Exhibit No. 33
Case No. IPC-E-11-08
M. Larkin, IPC
Page 48 of 48
BEFORE THE
RECE\VED
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IDAHO PUBLIC UTILITIES COMMISsioN:j
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
LARKIN, 01
TESTIMONY
EXHIBIT NO. 34
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Exhibit No. 34
Case No. IPC-E-11-08
M. Larkin, IPC
Page 4 of6
12
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BEFORE THE
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2011 JUN -I PM 2: 41
IDAHO PUBLIC UTILITIES COMMIS~¡8~P
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
LARKIN, 01
TESTIMONY
EXHIBIT NO. 36
1
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Case No. IPC-E-11-08
M. Larkin, IPC
Page 2 of6
18
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Case No. IPC-E-11-08
M. Larkin, IPC
Page 50f6
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Exhibit No. 37
Case No. IPC-E-11-08
M. Larkin, IPC
Page 1 of6
ID
A
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Exhibit No. 37
Case NO.IPC-E-11-08
M. Larkin, IPC
Page 4 of6
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RECEIVED
BEFORE THE 201\ JUN - i PM 2: 41
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IDAHO PUBLIC UTILITIES COMMlsSK)N~ol"M,'\
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
LARKIN, 01
TESTIMONY
EXHIBIT NO. 38
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Exhibit No. 38
Case NO.IPC-E-11-08
M. Larkin, IPC
Page 7 of9
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Case No. IPC-E-11-08
M. Larkin, IPC
Page 8 of9
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Case No. IPC-E-11-08
M. Larkin, IPC
Page 1 of3
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Case No. IPC-E-11-08
M. Larkin, IPC
Page 2 of3
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