20260923Direct Allen.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE PETITION )
OF IDAHO POWER COMPANY TO ) CASE NO. IPC-E-26-07
EVALUATE CLASS COST-OF- )
SERVICE METHODOLOGY, CONSIDER )
ALTERNATIVE CLASS COST-OF- )
SERVICE STUDIES, AND )
DETERMINE COST OF SERVICE )
CONSIDERATIONS FOR NEW LARGE- )
LOAD CUSTOMERS )
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
CONNOR L. ALLEN

1 I . Introduction
2 Q. Please state your name and business address .
3 A. My name is Connor L. Allen. My business
4 address is 1221 West Idaho Street, Boise, Idaho 83702 .
5 Q. By whom are you employed and in what capacity?
6 A. I am employed by Idaho Power Company ("Idaho
7 Power" or "Company") as a Regulatory Analyst in the
8 Regulatory Affairs Department .
9 Q. Please describe your educational and pre-Idaho
10 Power employment background.
11 A. In May 2020, I received a Bachelor of Science
12 degree in Economics from the University of Idaho. In May
13 2022, I earned a Master of Science degree in Applied
14 Economics from the University of Idaho. In September 2022,
15 I joined Camoin Associates as a Research and Data Analyst
16 and served in that capacity until joining Idaho Power in
17 May 2025 . After joining Idaho Power, I completed the
18 electric utility ratemaking course "Practical Regulatory
19 Training for the Electric Industry, " offered through New
20 Mexico State University' s Center for Public Utilities .
21 Q. Please describe your work experience with
22 Idaho Power.
23 A. I joined the Company' s Regulatory Affairs
24 Department as a Regulatory Analyst in May 2025 . My primary
25 responsibilities include supporting the Company' s class
ALLEN, DI 2
Idaho Power Company

1 cost-of-service activities, developing pricing for special
2 contract customers, performing other large-load pricing
3 analyses, and supporting the Company' s annual Fixed Cost
4 Adjustment ("FCA") calculation and filing.
5 Q. What is the purpose of your testimony?
6 A. The purpose of my testimony is to present the
7 technical analyses supporting the Company' s recommendations
8 regarding class cost-of-service methodology and the
9 allocation of identified growth-related portions of
10 generation and transmission costs . Company witness Mr.
11 Grant T. Anderson presents the Company' s recommendations
12 and the associated regulatory and policy considerations .
13 My testimony addresses two principal subjects .
14 First, I explain Idaho Power' s Peak and Average Embedded
15 Method ("PAEM") , compare the results of the PAEM Model with
16 the class cost-of-service study reflected in the Company' s
17 2025 general rate case ("2025 CCOS") , and discuss the
18 alternative studies evaluated in this proceeding, including
19 the Hourly-Informed Method.
20 Second, I explain the Company' s Growth
21 Responsibility Method ("GRM") , including the identification
22 of growth-related investments, development of functional
23 growth shares and customer-class growth factors, and
24 allocation of the applicable embedded and growth-related
25 portions of generation and transmission costs . I also
ALLEN, DI 3
Idaho Power Company

1 present a hypothetical New Large Load ("NLL") analysis
2 illustrating how GRM operates when a hypothetical NLL and
3 incremental generation-related costs are added to the class
4 cost-of-service study.
5 Q. Are you sponsoring any exhibits in this
6 proceeding?
7 A. Yes . I am sponsoring the exhibits listed
8 below:
9
Exhibit Description
Exhibit No. 1 CCOS PAEM and GRM Model Process Guide
Exhibit No. 2 PAEM Model
Exhibit No. 3 PAEM Model Allocation Factor Derivation
Workpapers
Exhibit No. 4 2025 CCOS Growth Model
Exhibit No . 5 2025 CCOS Growth Model Allocation Factor
Derivation Workpapers
Exhibit No . 6 GRM Model
Exhibit No . 7 GRM Model Allocation Factor Derivation
Workpapers
Exhibit No . 8 NLL GRM Model
Exhibit No. 9 NLL GRM Model Allocation Factor Derivation
Workpapers
10
ALLEN, DI 4
Idaho Power Company

1 Q. What are the principal technical conclusions
2 developed in your testimony?
3 A. My analyses support two principal conclusions .
4 First, PAEM provides a reasonable embedded class
5 cost-of-service methodology. PAEM classifies eligible
6 production plant between demand-related and energy-related
7 components using peak and average system demand, while
8 maintaining the existing treatment of battery storage,
9 purchased power, demand response, and transmission, as well
10 as the applicable production and transmission allocation
11 methodologies . The Model is transparent, reproducible,
12 fully allocates the applicable costs, and reconciles to the
13 applicable revenue requirement.
14 Second, GRM provides a defined and repeatable method
15 for incorporating measured customer-class demand and energy
16 growth into the allocation of identified growth-related
17 portions of generation and transmission costs . GRM combines
18 embedded cost responsibility with measured customer-class
19 growth and preserves embedded allocation treatment for all
20 remaining costs .
21 The historical analyses demonstrate how PAEM and GRM
22 affect class cost responsibility using investments,
23 customer-class growth, and other information evaluated. The
24 hypothetical NLL analysis further illustrates how GRM
25 operates when a hypothetical NLL and incremental
ALLEN, DI 5
Idaho Power Company

1 generation-related costs are added to the class cost-of-
2 service study.
3 II . Common Data, Modeling Assumptions , and Reconciliation
4 Q. Did the Company use a common analytical
5 foundation for the model comparisons presented in your
6 testimony?
7 A. Yes . Except for the hypothetical NLL analysis
8 and other differences specifically identified in my
9 testimony, the model comparisons begin with the 2025 CCOS
10 and generally maintain the same test year, customer
11 classes, billing determinants, load information, revenue
12 requirement, functionalization, and model structure . Each
13 comparison changes only those classification or allocation
14 treatments necessary to implement the methodology being
15 evaluated.
16 Using this common foundation allows the effect of
17 each methodological change to be evaluated separately and
18 reduces the extent to which differences in model results
19 may be attributable to unrelated changes in study inputs .
20 Q. Is the hypothetical NLL analysis based on the
21 same underlying study information?
22 A. The hypothetical NLL analysis begins with the
23 same general analytical framework but modifies the
24 underlying study information to add a hypothetical NLL,
25 associated demand and energy usage, incremental generation
ALLEN, DI 6
Idaho Power Company

1 resources, and related revenue requirement. It is therefore
2 an illustrative application of GRM rather than a controlled
3 comparison in which the other 2025 CCOS inputs remain
4 unchanged.
5 Q. How are the analyses documented and verified?
6 A. The models and supporting workpapers identify
7 the relevant inputs, calculations, allocation factors, and
8 resulting class allocations . This documentation allows
9 costs to be traced from the applicable revenue requirement
10 through their final allocation to customer classes .
11 The models also include controls to confirm that the
12 applicable costs are fully allocated, are not allocated
13 more than once, and reconcile to the applicable total
14 revenue requirement. The supporting workpapers document the
15 derivation of the allocation factors used in the models .
16 III . Idaho Power' s Peak & Average Embedded Method (PAEM)
17 Q. Please describe Idaho Power' s proposed PAEM.
18 A. PAEM is a targeted refinement to the class
19 cost-of-service methodology reflected in the Company' s 2025
20 general rate case. Its principal change is the use of the
21 Peak & Average method to classify eligible production plant
22 between demand-related and energy-related components .
23 PAEM maintains the existing treatment of battery
24 storage, purchased power, demand response, and
25 transmission, as well as the applicable production and
ALLEN, DI 7
Idaho Power Company

1 transmission allocation methodologies . Exhibit No. 1
2 describes the detailed implementation of the PAEM.
3 Q. How does PAEM classify production plant?
4 A. PAEM classifies eligible production plant
5 between demand-related and energy-related components using
6 the Peak & Average method described in the NARUC Electric
7 Utility Cost Allocation Manual ("Peak & Average") . For
8 purposes of PAEM, eligible production plant includes
9 production plant other than battery storage resources .
10 Battery storage is classified separately as 100 percent
11 demand-related.
12 Q. Why does Peak & Average classify eligible
13 production plant between demand-related and energy-related
14 components?
15 A. PAEM recognizes that both peak demand and
16 energy usage are important determinants of production plant
17 cost responsibility. Consistent with the peak and average
18 demand principles discussed in the NARUC Electric Utility
19 Cost Allocation Manual, the methodology incorporates
20 measures of both peak demand and average demand when
21 classifying eligible production plant between demand-
22 related and energy-related components . Because production
23 facilities support both the capability required to meet
24 system demand and the ongoing provision of energy
25 throughout the year, their costs cannot be directly
ALLEN, DI 8
Idaho Power Company

1 assigned between those functions through cost tracing
2 alone . Accordingly, PAEM applies a Peak & Average
3 classification approach to reflect both demand and energy
4 considerations in the classification of eligible production
5 plant .
6 Peak & Average uses peak system demand and average
7 system demand as observable measures of these cost-
8 causative characteristics . Peak demand reflects the maximum
9 generating capability the system must provide to meet
10 customer demand requirements, while average demand reflects
11 the sustained utilization of production resources needed to
12 serve customer energy requirements throughout the year.
13 Q. How are the demand-related and energy-related
14 percentages calculated?
15 A. The demand-related percentage equals peak
16 system demand divided by the sum of peak and average system
17 demand. The energy-related percentage equals average system
18 demand divided by the same total . The percentages are
19 complementary and total 100 percent.
20 Peak and average demand are used to establish
21 relative classification weights, not to represent separate
22 physical capacity requirements . Their sum does not
23 represent the amount of generating capacity the Company
24 must construct . As peak demand increases relative to
25 average demand, the demand-related percentage increases . As
ALLEN, DI 9
Idaho Power Company

1 average demand increases relative to peak demand, the
2 energy-related percentage increases . The calculation
3 therefore reflects the relationship between the maximum
4 generating capability the system must provide and the
5 sustained use of that capability throughout the year.
6 Applying the calculation to the system inputs shown
7 in Exhibit No. 3 classifies approximately 65 percent of
8 eligible production plant as demand-related and
9 approximately 35 percent as energy-related. The calculation
10 can be reproduced using the system inputs shown in Exhibit
11 No . 3 .
12 Q. Why does the PAEM separately identify energy-
13 related production plant costs and variable-energy costs?
14 A. The two categories represent different types
15 of costs . Energy-related production plant costs represent
16 capital investment classified to the energy function under
17 Peak & Average, while variable-energy costs are incurred as
18 energy is produced or purchased.
19 The same seasonal energy allocation factors apply to
20 both categories . Separately identifying the categories
21 therefore preserves the nature of the underlying costs but
22 does not independently affect the resulting class
23 allocations .
24 Q. How are battery storage resources treated
25 under PAEM?
ALLEN, DI 10
Idaho Power Company

1 A. Battery storage resources are classified as
2 100 percent demand-related because their modeled purpose is
3 to provide system capacity during peak-demand periods . They
4 are allocated using a 12-month coincident peak "12 CP"
5 allocation factor rather than the four-month coincident
6 peak "4 CP" allocation factor applied to peaking resources .
7 Q. Why are battery storage resources allocated
8 using the base and intermediate demand methodology rather
9 than the summer peak-demand methodology?
10 A. Battery storage resources provide modeled
11 capacity during peak-demand periods throughout the year.
12 The base and intermediate demand methodology recognizes
13 this year-round capability by allocating battery storage
14 costs based on customer-class contributions to monthly
15 coincident demand across all 12 months, rather than only
16 during the summer peak period.
17 Q. How does PAEM classify purchased power?
18 A. Purchased power is classified as 100 percent
19 energy-related, except for demand response purchased power.
20 Purchased power generally represents the expense of
21 acquiring power to serve customer energy requirements
22 rather than a long-lived investment in Company-owned
23 generating facilities . Its cost characteristics therefore
24 differ from the production plant classified through Peak &
25 Average.
ALLEN, DI 11
Idaho Power Company

1 Demand response purchased power is classified as 100
2 percent peak demand-related because those expenses are
3 incurred to reduce or manage demand during the Company' s
4 summer peak period when additional system capacity is
5 needed.
6 Q. How is transmission classified under PAEM?
7 A. Transmission is classified as 100 percent
8 demand-related because transmission investment is
9 principally associated with the system capability required
10 to reliably serve customer demand under normal and
11 contingency conditions .
12 Q. Why is transmission classified as demand-
13 related rather than between demand-related and energy-
14 related components?
15 A. Idaho Power annually evaluates one-year, five-
16 year, and ten-year cases under a range of load, generation,
17 and contingency conditions to comply with applicable North
18 American Electric Reliability Corporation Reliability
19 Standards . When a study identifies a performance
20 deficiency, the Company develops a Corrective Action Plan
21 that may result in a transmission project.
22 The limiting condition that creates the need for a
23 transmission project may differ by project because the
24 planning process evaluates multiple periods and a variety
25 of load, generation, and contingency conditions . The
ALLEN, DI 12
Idaho Power Company

I relevant technical attribute is the system capability
2 required to reliably serve demand under the identified
3 limiting condition, rather than a single common system peak
4 or annual energy throughput. These planning characteristics
5 support the demand-related classification of transmission
6 under PAEM rather than applying Peak & Average.
7 Q. Why does PAEM use the 2025 CCOS allocation
8 methodologies for demand-related production costs?
9 A. The allocation methodologies recognize that
10 different types of production resources provide capability
11 to meet different resource requirements . Demand-related
12 costs associated with base and intermediate resources are
13 allocated using each class' s contribution to monthly net
14 coincident peak demands across all 12 months because those
15 resources provide capability throughout the year. Demand-
16 related costs associated with peaking resources are
17 allocated using each class' s contribution to net coincident
18 peak demands during the summer peak months because those
19 resources serve seasonal peak requirements .
20 This resource-specific treatment aligns the
21 allocation of production capability costs with the demands
22 the applicable resources are intended to serve.
23 Q. Why does PAEM use the 2025 CCOS allocation
24 methodology for energy-related production costs?
ALLEN, DI 13
Idaho Power Company

1 A. The methodology allocates energy-related
2 production costs using seasonal factors that average each
3 customer class' s normalized share of energy usage with its
4 normalized energy share weighted by monthly marginal energy
5 costs . This treatment reflects each class' s energy usage
6 and the relative monthly cost of serving that usage .
7 Q. Why does PAEM use the 2025 CCOS allocation
8 methodology for transmission costs?
9 A. Transmission costs are allocated using a
10 factor that averages each customer class' s share of actual
11 coincident system demand with its normalized coincident-
12 demand share weighted by monthly marginal transmission
13 costs . This treatment reflects class contribution to
14 coincident system demand and the relative monthly cost of
15 transmission capability.
16 Q. Did you compare the results of the PAEM Model
17 with the 2025 CCOS?
18 A. Yes . Figure 1 compares the percentage revenue
19 changes for each customer class resulting from the revenue
20 allocations produced by the 2025 CCOS and the PAEM Models .
21
ALLEN, DI 14
Idaho Power Company

1 Figure 1 . Percentage Revenue Changes by Customer Class : 2025
2 CCOS vs . PAEM.
Customer Class 2025 CCOS PAEM
Uniform Tariff Schedules
Residential 14.42% 12.60%
Small General 10.78% 11.35%
Large General(9S) (0.40%) 0.70%
Large General(P/T) (1.20%) 0.44%
Large Power 0.58% 3.36%
Irrigation 10.36% 10.72%
Total Uniform Tariff Schedules 8.43% 8.20%
Special Contracts
Micron (0.72%) 2.50%
Simplot- Donn (6.91%) (1.58%)
DOE/INL 3.84% 7.23%
Simplot- Caldwell (16.09%) (11.27%)
Lamb Weston (13.75%) (9.02%)
Total Special Contracts (8.26%) (4.51%)
Total 7.48% 7.48%
Figure 1 presents the percentage revenue changes for the major customer classes
resulting from the revenue allocations produced under the 2025 CCOS and the
PAEM Models. Results are shown separately for uniform tariff schedules and
special contract customers, with subtotal rows provided for each group. The 'Total"
row reflects the system-average revenue increase reflected in the 2025 General Rate
3 Case Settlement Stipulation.
4 Q. Why is the 2025 CCOS the principal benchmark
5 for this comparison?
6 A. The 2025 COOS is the most recent class cost-
7 of-service framework reflected in the Company' s approved
8 rates . It therefore provides the most relevant benchmark
9 for identifying the methodological changes reflected in
10 PAEM and how those changes affect class cost
11 responsibility.
ALLEN, DI 15
Idaho Power Company

1 Q. What accounts for the differences between the
2 2025 CCOS and the PAEM Model shown in Figure 1?
3 A. The differences are principally attributable
4 to reclassifying a portion of eligible production plant
5 from demand-related to energy-related under Peak & Average .
6 The reclassified costs move from the applicable demand
7 allocation factors to the seasonal energy allocation
8 factors .
9 Accordingly, each class' s result depends on the
10 relationship between its demand and energy allocation
11 shares . A class with a relatively greater share under the
12 energy allocation factors will generally receive a larger
13 share of the reclassified costs, while a class with a
14 relatively lower energy share will generally receive a
15 smaller share.
16 Separately identifying energy-related production
17 plant costs and variable-energy costs does not
18 independently affect the class allocations because both
19 categories use the same seasonal energy allocation factors .
20 Exhibits Nos . 2 and 3 provide the detailed calculations and
21 resulting class allocations .
22
ALLEN, DI 16
Idaho Power Company

1 Q. Did the Company evaluate other embedded
2 classification and allocation approaches in developing
3 PAEM?
4 A. Yes . In its initial Petition, the Company
5 presented the Energy & Fixed Allocation Classification
6 ("EFAC") , EFAC Production and Transmission ("EFAC P&T") ,
7 Average & Excess Demand with four coincident peaks ("AED-
8 4CP") , and Hourly-Informed studies to support the
9 evaluation of alternative embedded classification and
10 allocation approaches .
11 The Company used those studies, together with the
12 2025 CCOS, to evaluate the individual methodological
13 choices reflected in PAEM. The alternatives informed the
14 Company' s evaluation of how production plant and purchased
15 power should be classified, whether transmission should be
16 classified between demand-related and energy-related
17 components, and whether different production or
18 transmission demand-allocation methodologies should be
19 adopted.
20 The Company did not treat the alternative studies as
21 coequal recommendations or select PAEM based solely on the
22 overall class results produced by any one study. Rather,
23 each study informed a particular classification or
24 allocation question.
ALLEN, DI 17
Idaho Power Company

1 I discuss those comparisons and how they informed
2 the Company' s evaluation below.
3 Q. How did the EFAC alternative inform the
4 Company' s evaluation?
5 A. EFAC tested an alternative classification of
6 production-related costs using the Idaho jurisdictional
7 load factor as the energy-related percentage and the
8 remainder as demand-related. This enabled a comparison with
9 Peak & Average, which gives peak system demand and average
10 system demand separate roles in establishing the
11 classification percentages .
12 Neither EFAC nor Peak & Average directly traces
13 jointly used production plant to separate demand-related
14 and energy-related functions . Both therefore require
15 methodological judgment. EFAC uses the average-to-peak
16 relationship directly through the system load factor, while
17 Peak & Average gives peak demand and average demand
18 separate roles in establishing the classification
19 percentages .
20 After evaluating the alternatives, the Company
21 determined that Peak & Average provides a more reasonable
22 classification basis because eligible production plant
23 supports both the generating capability required to meet
24 peak demand and customers' energy requirements throughout
25 the year. Peak & Average reflects both functions by
ALLEN, DI 18
Idaho Power Company

I incorporating peak demand and average demand as separate
2 inputs when determining the demand-related and energy-
3 related shares .
4 EFAC also tested applying its classification to
5 purchased power. The Company determined purchased power
6 should generally remain energy-related because it
7 represents the expense of acquiring power to serve customer
8 energy requirements rather than investment in Company-owned
9 production plant .
10 Q. How did the EFAC P&T alternative inform the
11 Company' s evaluation?
12 A. EFAC P&T tested classifying transmission
13 between demand-related and energy-related components rather
14 than maintaining a fully demand-related classification.
15 This comparison allowed the Company to evaluate whether
16 energy throughput provided a more appropriate
17 classification basis for transmission.
18 The transmission-planning considerations discussed
19 earlier indicate that transmission investment is
20 principally associated with the system capability required
21 to reliably serve demand under limiting normal and
22 contingency conditions . Those considerations did not
23 support replacing the demand-related classification of
24 transmission with a classification based partly on energy
25 requirements .
ALLEN, DI 19
Idaho Power Company

1 Q. How did the AED-4CP alternative inform the
2 Company' s evaluation?
3 A. AED-4CP tested a unified annual allocator for
4 all demand-related production costs against the resource-
5 specific allocation used in the 2025 COOS . AED-4CP applies
6 one combined average-and-excess-demand measure, while the
7 maintained methodology separately allocates base and
8 intermediate resources using monthly net coincident peak
9 demands across all 12 months and peaking resources using
10 net coincident peak demands during the summer peak months .
11 Based on this comparison, the Company maintained the
12 resource-specific allocation because it better recognizes
13 the different system requirements the applicable production
14 resources are intended to serve .
15 Q. Why did the Company develop an Hourly-Informed
16 class cost-of-service analysis?
17 A. Development and presentation of an Hourly-
18 Informed allocation of production and transmission revenue
19 requirements was contemplated by the settlement reached in
20 the Company' s 2025 general rate case .
21 Q. How does the Hourly-Informed Method differ
22 from PAEM?
23 A. The Hourly-Informed Method does not separately
24 classify production costs between demand-related and
25 energy-related components . Instead, it distributes annual
ALLEN, DI 20
Idaho Power Company

1 production costs across the 8, 760 hours of the year using
2 modeled hourly resource-output profiles and, where
3 applicable, hourly prices . It then allocates those costs to
4 customer classes based on hourly energy usage. Transmission
5 costs are allocated based on annual customer-class energy
6 usage using a uniform cost per megawatt-hour.
7 Q. What are the primary considerations and
8 limitations associated with the Hourly-Informed Method?
9 A. The Hourly-Informed Method allocates both
10 production and transmission costs through customer energy
11 usage . Although hourly energy usage provides information
12 regarding when customers consume electricity, it does not
13 separately measure customer responsibility for the
14 generation and transmission capability the Company must
15 construct and maintain to reliably serve load.
16 Implementation of the methodology also requires
17 substantial hourly data, modeling assumptions, and
18 alignment among customer load shapes, resource dispatch,
19 resource costs, and annual embedded costs .
20 Q. What is your conclusion regarding the Hourly-
21 Informed Method?
22 A. The Hourly-Informed Method may provide useful
23 supplemental information regarding customer load shapes,
24 the timing of energy usage, modeled resource-dispatch
ALLEN, DI 21
Idaho Power Company

1 patterns, and the allocation outcomes produced by an hourly
2 energy-based approach.
3 However, because the method ultimately allocates
4 production and transmission costs through customer energy
5 usage rather than separately measuring class responsibility
6 for generation and transmission capability, the Company
7 does not believe it should serve as the primary embedded
8 CCOS methodology.
9 IV. Growth Responsibility Method (GRM)
10 Q. What is the purpose of the GRM?
11 A. GRM provides a defined method for
12 incorporating measured customer class growth into the
13 allocation of identified growth-related portions of
14 generation and transmission costs .
15 A traditional embedded class cost-of-service study
16 allocates investments as part of the integrated production
17 or transmission function without separately measuring
18 whether customer growth contributed to the need or scale of
19 those investments . GRM identifies a growth-related portion
20 of applicable costs for additional allocation treatment
21 based on both embedded cost responsibility and measured
22 customer-class growth.
23 GRM does not change the Company' s total revenue
24 requirement, and all costs not receiving growth-weighted
ALLEN, DI 22
Idaho Power Company

1 treatment continue to be allocated through the applicable
2 embedded class cost-of-service methodology.
3 Q. How does GRM relate to PAEM?
4 A. GRM builds on PAEM rather than replacing it .
5 PAEM establishes the classification and embedded allocation
6 of the Company' s costs . GRM then applies growth-weighted
7 treatment to identified growth-related portions of
8 applicable generation and transmission costs .
9 The embedded portions of those costs are allocated
10 using the applicable PAEM allocation factors . The growth-
11 related portion is allocated using growth-weighted
12 allocation factors that incorporate both embedded cost
13 responsibility and measured customer-class growth. The two
14 portions are then combined to determine total class cost
15 responsibility.
16 Q. What are the principal steps in applying GRM?
17 A. GRM:
18 (1) identifies applicable growth-related generation and
19 transmission investments;
20 (2) develops functional growth shares;
21 (3) separates the applicable functional revenue
22 requirements into embedded and growth-related portions;
23 (4) develops customer-class growth factors using changes in
24 the applicable allocation measures;
ALLEN, DI 23
Idaho Power Company

1 (5) develops growth-weighted allocation factors that
2 incorporate embedded cost responsibility and measured
3 customer-class growth; and
4 (6) combines the embedded and growth-related allocations to
5 determine total class responsibility.
6 Exhibit No. 1 describes the detailed implementation
7 of these steps .
8 Q. What historical period did the Company
9 evaluate in its illustrative application of the GRM?
10 A. In this instance, the historical analysis
11 evaluates customer-class demand and energy growth along
12 with production and transmission investment between the
13 Company' s 2023 and 2025 general rate cases .
14 Q. How did the Company determine whether an
15 investment was growth-related?
16 A. The Company reviewed production additions,
17 battery-storage resources, transmission expansions, and
18 associated network upgrades occurring during that period to
19 determine whether customer demand and energy growth
20 contributed to the need or scale of each investment . This
21 standard distinguishes growth-related investment from
22 investment needed primarily to maintain, replace, or
23 otherwise support the existing system.
24
ALLEN, DI 24
Idaho Power Company

1 Q. Does identifying an investment as growth-
2 related mean that it serves only growing customer classes?
3 A. No. The designation does not establish
4 exclusive causation or use . An identified facility may also
5 support reliability, resource integration, operations, and
6 the requirements of both existing and growing customer
7 classes after it enters the integrated system.
8 GRM recognizes this shared-system function by
9 incorporating both embedded cost responsibility and
10 measured customer-class demand and energy growth rather
11 than allocating the applicable costs solely based on
12 growth.
13 Q. How did the Company identify the growth-
14 related investment measure used in the historical analysis?
15 A. The Company reviewed generation, battery-
16 storage, and transmission projects with values greater than
17 $2 million that were closed to plant in 2024 or forecast to
18 be closed to plant in 2025 . Using plant included in the
19 2023 general rate case as the baseline, the Company
20 determined that the identified growth-related projects
21 represented approximately 24 percent of the combined
22 incremental generation and transmission investment included
23 in the project review.
ALLEN, DI 25
Idaho Power Company

1 The historical analysis used that percentage as the
2 first step in estimating growth-related rate base for each
3 applicable production and transmission function.
4 Q. What are functional growth shares, and why
5 does GRM develop them separately by function?
6 A. A functional growth share represents the
7 portion of an applicable function' s revenue requirement
8 that receives growth-weighted treatment.
9 Separate functional growth shares are developed
10 because growth-related investment may represent different
11 proportions of the applicable production and transmission
12 functions . Developing separate shares allows the portion of
13 each function receiving growth-weighted treatment to
14 reflect information specific to that function.
15 Q. What functional growth shares result from the
16 historical analysis?
17 A. To isolate the effect of growth-weighting, the
18 Company applied GRM' s growth-weighting process to the 2025
19 CCOS without changing its underlying functionalization,
20 classification, or embedded allocation framework. I refer
21 to this illustrative comparison as the "2025 CCOS Growth
22 Model . "
23 As shown in Exhibit No. 5, the 2025 CCOS Growth
24 Model produces functional growth shares of approximately
25 6 . 450 percent for production demand, base and intermediate;
ALLEN, DI 26
Idaho Power Company

1 7 . 641 percent for production demand, peak; and 5 . 601
2 percent for transmission demand.
3 Each percentage represents the portion of the
4 applicable function' s revenue requirement receiving growth-
5 weighted treatment. The remaining portion continues to
6 receive embedded treatment under the 2025 CCOS .
7 Q. How are functional growth shares applied to
8 the revenue requirement?
9 A. Each functional growth share is applied to the
10 revenue-requirement components assigned to that function,
11 including rate base, operating expenses, other revenues,
12 and related components . This separates the applicable
13 functional revenue requirement into an embedded portion and
14 a growth-related portion without developing a separate
15 project-specific revenue requirement.
16 Costs outside the applicable growth-related
17 production and transmission functions remain subject to the
18 embedded class cost-of-service methodology.
19 Q. How does GRM develop customer-class growth
20 factors?
21 A. GRM measures positive incremental changes in
22 the applicable customer-class allocation factors between
23 the studies being compared and normalizes those changes to
24 determine each class' s proportionate share of measured
25 growth. Classes without a positive incremental change do
ALLEN, DI 27
Idaho Power Company

1 not receive a positive growth share but continue to receive
2 cost responsibility through the embedded component of the
3 applicable growth-weighted allocation factor.
4 Using the applicable allocation factor aligns the
5 growth measure with the demand or energy characteristic
6 relevant to the production or transmission function.
7 Q. How does GRM construct the growth-weighted
8 allocation factors?
9 A. For each applicable function, GRM combines
10 each class' s embedded allocation factor with its
11 corresponding customer-class growth factor to develop a
12 growth-weighted allocation factor.
13 The embedded component reflects class responsibility
14 for facilities operating as part of the integrated system,
15 while the growth component reflects measured customer-class
16 growth associated with the identified growth-related
17 investment. This results in classes with greater relative
18 measured growth receiving a greater share of the growth-
19 related portion than they would receive under the embedded
20 allocation factor alone.
21 GRM does not allocate the entire applicable cost
22 solely to classes with measured growth and does not
23 directly assign a specific project to an individual
24 customer or customer class .
ALLEN, DI 28
Idaho Power Company

1 Q. Does the GRM change the Company' s total
2 revenue requirement?
3 A. No. GRM changes how the applicable production
4 and transmission revenue requirements are allocated among
5 customer classes . It does not increase or decrease the
6 Company' s total revenue requirement .
7 The models include controls confirming that the
8 embedded and growth-related portions reconcile to the
9 applicable functional revenue requirements and that the
10 final class allocations reconcile to the total revenue
11 requirement .
12 Q. Why did the Company prepare the 2025 CCOS
13 Growth Model?
14 A. The Company prepared the 2025 COOS Growth
15 Model to isolate the effect of applying growth weighting
16 within the 2025 COOS framework. The model maintains the
17 2025 CCOS functionalization, classification, and embedded
18 allocation methodologies and changes only the allocation
19 treatment applied to the calculated growth-related portions
20 of the applicable production and transmission revenue
21 requirements .
22 Q. What does the comparison between the 2025 CCOS
23 and the 2025 CCOS Growth Model demonstrate?
ALLEN, DI 29
Idaho Power Company

1 A. Figure 2 compares the revenue adjustments
2 required for each customer class to achieve cost of service
3 under the 2025 CCOS and the 2025 CCOS Growth Model .
4 Only the identified growth-related portions receive
5 growth-weighted treatment. All remaining costs continue to
6 be allocated through the 2025 CCOS framework, and the total
7 Idaho jurisdictional revenue requirement is unchanged.
8 The results are specific to the investments,
9 customer-class growth, measurement period, and allocation
10 factors evaluated. A future application would produce
11 different functional growth shares, customer-class growth
12 factors, and allocation results .
13
ALLEN, DI 30
Idaho Power Company

1 Figure 2 . Percentage Revenue Changes by Customer Class:
2 2025 CCOS vs . 2025 CCOS Growth Model .
Customer Class 2025 CCOS 2025 CCOS Growth
Uniform Tariff Schedules
Residential 14.42% 14.52%
Small General 10.78% 10.75%
Large General(9S) (0.40%) (0.44%)
Large General(P/T) (1.20%) (1.28%)
Large Power 0.58% 0.59%
Irrigation 10.36% 10.12%
Total Uniform Tariff Schedules 8.43% 8.43%
Special Contracts
Micron (0.72%) (0.91%)
Simplot- Donn (6.91%) (7.27%)
DOE/1 N L 3.84% 3.56%
Simplot- Caldwell (16.09%) (16.38%)
Lamb Weston (13.75%) (12.75%)
Total Special Contracts (8.26%) (8.37%)
Total 7.48% 7.48%
Figure 2 presents the percentage revenue changes for the major customer classes
resulting from the revenue allocations produced under the 2025 CCOS and the 2025
CCOS Growth Models. Results are shown separatelyfor uniform tariff schedules and
special contract customers, with subtotal rows provided for each group. The "Total"row
reflects the system-average revenue increase reflected in the 2025 General Rate Case
3 Settlement Stipulation.
4 Q. Did you also apply GRM within PAEM?
5 A. Yes . The GRM Model applies GRM' s growth-
6 weighting process within PAEM. Exhibit No. 6 contains the
7 GRM Model, and Exhibit No . 7 contains the related
8 allocation-factor derivation workpapers .
9 Q. How does GRM apply within PAEM?
10 A. PAEM first establishes the classification and
11 embedded allocation of the Company' s costs . GRM then
12 applies functional growth shares to separate the applicable
ALLEN, DI 31
Idaho Power Company

1 production and transmission revenue requirements into
2 embedded and growth-related portions .
3 The embedded portions are allocated using the
4 applicable PAEM allocation factors . The growth-related
5 portions are allocated using the applicable growth-weighted
6 allocation factors . The two allocations are then combined
7 to determine total class cost responsibility.
8 Q. How does the GRM Model differ from the 2025
9 CCOS Growth Model?
10 A. Both models apply the same growth-weighting
11 process, but they begin with different embedded CCOS
12 methodologies .
13 The 2025 CCOS Growth Model applies growth weighting
14 within the 2025 COOS framework. The GRM Model applies
15 growth weighting after PAEM classifies and allocates the
16 embedded costs . The comparison therefore demonstrates how
17 the same growth-weighting process operates under two
18 embedded CCOS methodologies .
19 Q. Why do the functional growth shares in the GRM
20 Model differ from those in the 2025 CCOS Growth Model?
21 A. The two models apply the same growth-related
22 investment measure within different embedded classification
23 frameworks .
24 The 2025 CCOS does not classify eligible production
25 plant between demand-related and energy-related components .
ALLEN, DI 32
Idaho Power Company

1 Its functional growth shares therefore apply to production
2 demand, base and intermediate; production demand, peak; and
3 transmission demand.
4 PAEM classifies eligible production plant between
5 demand-related and energy-related components before GRM is
6 applied. The GRM Model therefore develops an additional
7 functional growth share for energy-related production plant
8 costs . As shown in Exhibit No. 7, the GRM Model produces
9 functional growth shares of approximately 5 . 507 percent for
10 production demand, base and intermediate; 7 . 556 percent for
11 production demand, peak; 8 . 192 percent for energy-related
12 production plant costs; and 5 . 601 percent for transmission
13 demand.
14 The energy-related production growth share results
15 from PAEM' s classification of eligible production plant and
16 does not represent an additional category of identified
17 growth investment .
18 Q. What do the model comparisons demonstrate?
19 A. Figure 3 compares the percentage revenue
20 changes for each customer class resulting from the revenue
21 allocations produced by the 2025 COOS, PAEM, and GRM
22 Models . Together, Figures 1 through 3 separately show:
23 (1) the effect of applying the PAEM rather than the
24 2025 CCOS;
ALLEN, DI 33
Idaho Power Company

1 (2) the effect of applying growth weighting within the
2 2025 CCOS framework; and
3 (3) the combined effect of applying PAEM and GRM.
4 In the historical comparison, the PAEM changes have
5 a larger effect on class allocations because they apply to
6 a broader portion of eligible production plant, while
7 growth-weighted treatment applies only to calculated
8 growth-related portions of applicable costs . The total
9 Idaho jurisdictional revenue requirement is unchanged.
10
ALLEN, DI 34
Idaho Power Company

1 Figure 3 . Percentage Revenue Changes by Customer Class :
2 2025 CCOS vs . PAEM vs . GRM.
Customer Class 2025 CCOS PAEM GRM
Uniform Tariff Schedules
Residential 14.42% 12.60% 12.66%
Small General 10.78% 11.35% 11.31%
Large General(9S) (0.40%) 0.70% 0.66%
Large General(P/T) (1.20%) 0.44% 0.47%
Large Power 0.58% 3.36% 3.34%
Irrigation 10.36% 10.72% 10.53%
Total Uniform Tariff Schedules 8.43% 8.20% 8.20%
Special Contracts
Micron (0.72%) 2.50% 2.34%
Simplot- Donn (6.91%) (1.58%) (1.83%)
DOE/INL 3.84% 7.23% 6.99%
Simplot-Ca[dwell (16.09%) (11.27%) (11.45%)
Lamb Weston (13.75%) (9.02%) (6.34%)
Total Special Contracts (8.26%) (4.51%) (4.40%)
Total 7.48% 7.48% 7.48%
Figure 3 presents the percentage revenue changes for the major customer classes resulting from the
revenue allocations produced under the 2025 CCOS, the PAEM, and the GRM Models. Results are
shown separatelyfor uniform tariff schedules and special contract customers, with subtotal rows
provided for each group. The"Total"row reflects the system-average revenue increase reflected in the
3 2025 General Rate Case Settlement Stipulation.
4 Q. What information and refinements should be
5 considered in a future application of GRM?
6 A. A future application would update the
7 measurement period, identified growth-related generation
8 and transmission investments, customer-class growth, rate-
9 base changes, revenue requirements, embedded allocation
10 factors, functional growth shares, and customer-class
11 growth factors using information applicable to the
12 proceeding.
13 The historical analyses presented in this case also
14 identify refinements that should be incorporated or
ALLEN, DI 35
Idaho Power Company

1 evaluated in a future application. First, growth-related
2 generation and transmission investments should be evaluated
3 separately when developing the applicable functional growth
4 shares . The historical analysis used a combined growth-
5 related investment percentage as a simplifying assumption,
6 which may not reflect differences in the relative amount of
7 identified growth investment within the generation and
8 transmission functions .
9 Second, associated network upgrades should be
10 included within the transmission function even when they
11 are required to integrate a generation resource.
12 Third, customer migration between rate schedules
13 should be distinguished from actual customer growth. Prior-
14 period class information should be adjusted as appropriate
15 to avoid treating the transfer of existing load between
16 classes as incremental system growth.
17 GRM provides a repeatable analytical structure, but
18 its inputs and resulting allocations will reflect the
19 system, loads, investments, and other information
20 applicable to each proceeding.
21 V. Hypothetical NLL Analysis
22 Q. What is the purpose of the hypothetical NLL
23 analysis?
24 A. The hypothetical NLL analysis illustrates how
25 GRM operates when a hypothetical 300-megawatt transmission-
ALLEN, DI 36
Idaho Power Company

1 level customer class and approximately $219 million of
2 incremental generation-related revenue requirement are
3 added to the class cost-of-service study. I refer to this
4 analysis as the "NLL GRM Model . "
5 The NLL GRM Model is an illustrative application
6 based on specified assumptions . It does not represent an
7 actual customer, service request, load forecast, resource
8 decision, customer-specific rate proposal, or precedent for
9 a future proceeding.
10 Q. How did the Company identify the incremental
11 generation resources included in the NLL GRM Model?
12 A. The Company used portfolio analyses developed
13 as part of its 2025 Integrated Resource Plan. The Company
14 compared the resources reflected in the 2025 IRP portfolio
15 with those reflected in a counterfactual portfolio analysis
16 that added an assumed 300-megawatt customer.
17 The incremental differences between the two modeled
18 portfolios were used to identify the additional generation
19 resources included in the NLL GRM Model .
20 Q. Does the portfolio comparison identify
21 generation resources dedicated exclusively to the
22 hypothetical NLL?
23 A. No . The portfolio comparison evaluates modeled
24 system resource requirements under two scenarios, one
ALLEN, DI 37
Idaho Power Company

1 without the hypothetical NLL and one with the additional
2 300 megawatts of load.
3 The difference between the two portfolios identifies
4 the incremental generation resources included in the
5 modeled system after the hypothetical NLL is added.
6 Although the hypothetical NLL produces the incremental
7 resource need in the portfolio comparison, the resulting
8 resources are assumed to operate as part of the Company' s
9 integrated production system rather than as resources
10 dedicated exclusively to the hypothetical NLL .
11 Q. How is the incremental revenue requirement
12 reflected in the NLL GRM Model?
13 A. The NLL GPM Model begins with the revenue
14 requirement reflected in the 2025 general rate case and
15 adds approximately $219 million associated with the
16 incremental generation resources and net power supply
17 expense identified through the portfolio comparison.
18 The incremental costs are incorporated into the
19 applicable production functions and classified and
20 allocated using the PAEM and GRM. The resulting
21 hypothetical revenue requirement therefore includes both
22 the costs reflected in the 2025 general rate case and the
23 incremental generation-related costs included in the
24 hypothetical NLL scenario.
ALLEN, DI 38
Idaho Power Company

1 Q. Does the NLL GRM Model include additional
2 major transmission projects to serve the hypothetical NLL?
3 A. No. The comparison between the 2025 IRP
4 portfolio and the counterfactual portfolio with the
5 additional 300-megawatt customer did not identify any
6 incremental major transmission projects that would be
7 required to serve the additional load. Accordingly, the NLL
8 GRM Model does not include a separate addition for major
9 transmission investment or transmission revenue
10 requirement .
11 This result is specific to the assumptions and
12 portfolio comparison used in the hypothetical analysis . It
13 does not establish that an actual NLL would require no
14 additional transmission facilities . Any transmission
15 requirements associated with an actual customer would
16 depend on the facts evaluated in the applicable proceeding.
17 Q. What growth-related investments and customer-
18 class growth are reflected in the NLL GRM Model?
19 A. The NLL GRM Model carries forward the growth-
20 related investments and customer-class growth identified
21 between the 2023 and 2025 general rate cases . It then adds
22 the hypothetical NLL customer, its assumed demand and
23 energy usage, and the incremental generation resources
24 identified through the portfolio comparison.
ALLEN, DI 39
Idaho Power Company

1 The model therefore measures growth from the 2023
2 general rate case to the hypothetical study, including both
3 the historical changes for existing classes and the
4 addition of the hypothetical NLL .
5 Q. How does the NLL GRM Model develop the
6 functional growth shares and customer-class growth factors?
7 A. The identified growth-related investment
8 includes both the historical growth-related investment and
9 the incremental generation resources identified through the
10 hypothetical portfolio comparison . That investment is
11 evaluated against the applicable investment and rate-base
12 information in the NLL GRM Model to develop the functional
13 growth shares .
14 Customer-class growth factors are developed from
15 changes in the applicable allocation measures between the
16 2023 general rate case and the NLL GRM Model, including the
17 addition of the hypothetical NLL. Exhibits Nos . 8 and 9
18 provide the supporting calculations .
19 Q. How does the NLL GRM Model allocate the
20 embedded and growth-related portions of the applicable
21 costs?
22 A. The embedded portion is allocated using the
23 applicable PAEM allocation factors . The growth-related
24 portion is allocated using growth-weighted allocation
25 factors developed for the hypothetical scenario. The two
ALLEN, DI 40
Idaho Power Company

I portions are then combined to determine total class cost
2 responsibility.
3 Accordingly, the NLL GRM Model does not allocate the
4 entire $219 million of incremental generation-related
5 revenue requirement to the hypothetical NLL or directly
6 assign a specific generation resource to that class . The
7 hypothetical NLL receives a greater relative share of the
8 growth-related portion based on its measured growth, while
9 the allocation also recognizes that the incremental
10 generation resources are assumed to operate as part of the
11 integrated production system.
12 Q. Where are the results of the NLL GRM Model
13 presented, and what assumptions principally affect those
14 results?
15 A. Exhibits Nos . 8 and 9 present the functional
16 growth shares, separated revenue requirements, allocation
17 factors, and class results .
18 The results reflect the assumed NLL demand and
19 energy usage, the applicable coincidence with system peak,
20 the measured customer-class growth, the incremental
21 generation-related costs identified through the portfolio
22 comparison, and the treatment of the incremental resources
23 as part of the integrated production system.
24
ALLEN, DI 41
Idaho Power Company

1 Q. What does the hypothetical NLL analysis
2 demonstrate?
3 A. The hypothetical NLL analysis demonstrates how
4 GRM allocates costs when a hypothetical NLL and incremental
5 generation-related costs are added to the class cost-of-
6 service study. It illustrates how the methodology
7 incorporates the hypothetical NLL' s measured growth while
8 also recognizing embedded responsibility for resources
9 assumed to operate as part of the integrated production
10 system.
11 The results are specific to the assumptions and
12 inputs used in the NLL GRM Model . They do not establish the
13 load characteristics, incremental resources, costs,
14 functional growth shares, allocation factors, or class
15 responsibility that would result for an actual NLL. Those
16 determinations will depend on facts that may differ by
17 customer and could change over time and should be addressed
18 in the proceeding reviewing the applicable NLL service
19 contract.
20 VI . Summary and Technical Conclusions
21 Q. Please summarize the principal technical
22 conclusions supported by your testimony.
23 A. My analyses support two principal technical
24 conclusions .
ALLEN, DI 42
Idaho Power Company

1 First, PAEM provides a reasonable embedded class
2 cost-of-service methodology. PAEM classifies eligible
3 production plant between demand-related and energy-related
4 components using peak and average system demand, while
5 maintaining separate classification and allocation
6 treatment for cost categories with different
7 characteristics . PAEM is transparent and reproducible, and
8 the PAEM Model fully allocates the applicable costs and
9 reconciles to the applicable revenue requirement.
10 The comparison studies demonstrate how alternative
11 classification and allocation choices affect class cost
12 responsibility and informed the Company' s evaluation of the
13 individual methodological choices reflected in the PAEM.
14 The Hourly-Informed Method may provide useful supplemental
15 information regarding customer-class load shapes, the
16 timing of energy usage, modeled resource-dispatch patterns,
17 and the allocation outcomes produced by an hourly energy-
18 based approach. However, because it allocates production
19 and transmission costs through customer energy usage rather
20 than separately measuring class responsibility for
21 generation and transmission capability, it should not serve
22 as the primary embedded CCOS methodology.
23 Second, GRM provides a defined and repeatable method
24 for incorporating measured customer-class growth into the
25 allocation of identified growth-related portions of
ALLEN, DI 43
Idaho Power Company

1 generation and transmission costs . GRM combines embedded
2 cost responsibility with measured customer-class growth
3 while preserving embedded allocation treatment for all
4 remaining costs . The GRM analysis also demonstrates that
5 the methodology changes the allocation of the applicable
6 costs among customer classes but does not change the
7 Company' s total revenue requirement.
8 The historical analyses demonstrate how PAEM and GRM
9 affect class cost responsibility under the investments,
10 customer-class growth, and other information evaluated. The
11 hypothetical NLL analysis further illustrates how GRM
12 operates when a hypothetical NLL and incremental
13 generation-related costs are added to the class cost-of-
14 service study. The resulting allocations are specific to
15 the inputs and assumptions used in each analysis .
16 Q. Does this complete your testimony?
17 A. Yes, it does .
ALLEN, DI 44
Idaho Power Company

1 DECLARATION OF CONNOR L. ALLEN
2 I, Connor L. Allen, declare under penalty of perjury
3 under the laws of the state of Idaho:
4 1 . My name is Connor L. Allen. I am employed by
5 Idaho Power Company as a Regulatory Analyst in the
6 Regulatory Affairs Department and am competent to be a
7 witness in this proceeding.
8 2 . On behalf of Idaho Power, I present this
9 pre-filed direct testimony and exhibits in this matter.
10 3 . To the best of my knowledge, my pre-filed
11 direct testimony and exhibits are true and accurate .
12 I hereby declare that the above statement is true to
13 the best of my knowledge and belief, and that I understand
14 it is made for use as evidence before the Idaho Public
15 Utilities Commission and is subject to penalty for perjury.
16 SIGNED this 23rd day of September 2026, at Boise,
17 Idaho .
18
19 Signed:
ALLEN, DI 45
Idaho Power Company

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
EXHIBIT 1
CCOS PAEM and GRM Model Process Guide

Idaho Power Company Exhibit 1:CCOs PAEM and GRM Model Process Guide
CCOS PAEM and GRM Model Process Guide
Case No. IPC-E-26-07
This Process Guide describes the technical framework and model procedures used to
implement Idaho Power's Peak and Average Embedded Method ("PAEM") and Growth
Responsibility Method ("GRM"). PAEM provides the embedded class cost-of-service framework,
while GRM builds upon that framework by incorporating measured customer-class growth into
the allocation of identified growth-related portions of applicable production and transmission
costs.
Under both methodologies, costs are assigned among customer classes through
functionalization, classification, and allocation. These steps identify the utility function
associated with each cost, determine whether the cost is demand-related, energy-related, or
customer-related, and allocate the resulting costs among customer classes based on the
applicable cost drivers.
This Process Guide describes the methodology and principal procedures implemented in the
models. The supporting allocation-factor derivation workpapers document the detailed inputs
and calculations used to develop the applicable embedded allocation factors, customer-class
growth factors, functional growth shares, and Growth-Weighted Allocation Factors.
Idaho Power Company's PAEM Methodology
Idaho Power Company's PAEM functionalizes, classifies, and allocates costs to reflect how
customer classes use and rely upon Idaho Power's electric system across the primary utility
functions and cost drivers.
The methodology recognizes that electric utility costs are incurred to provide customers with
access to the system, the capacity necessary to meet demand requirements, and the energy
required to serve ongoing consumption. Consistent with these characteristics, costs are first
functionalized among Production, Transmission, Distribution, Customer, and Miscellaneous
functions and are then classified as demand-related, energy-related, or customer-related before
being allocated among customer classes using the applicable allocation factors.
Under PAEM, eligible production plant, excluding battery storage resources, is classified
between demand-related and energy-related components using the Peak&Average method
described in the NARUC Electric Utility Cost Allocation Manual ("Peak &Average"). Peak &
Average recognizes that both peak demand and energy usage are important determinants of
production plant cost responsibility. Because production facilities support both the capability
Page 1 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 1 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
required to meet system demand and the ongoing provision of energy throughout the year,
their costs cannot be directly assigned between those functions through cost tracing alone.
Peak &Average uses peak system demand and average system demand as observable measures
of these cost-causative characteristics. Peak demand reflects the maximum generating
capability the system must provide to meet customer demand requirements, while average
demand reflects the sustained utilization of production resources needed to serve customer
energy requirements throughout the year.
The classification percentages are determined as follows:
• Energy-Related Percentage
= Average Demand - (Average Demand + Peak Demand)
• Demand-Related Percentage
= Peak Demand - (Average Demand + Peak Demand)
The demand-related and energy-related percentages are complementary and total 100 percent.
Peak and average demand establish relative classification weights; their sum does not represent
the amount of generating capacity the Company must construct.
Under the methodology:
• Production plant subject to the Peak & Average classification is classified between
demand-related and energy-related components.
• Variable production-related costs, such as fuel, are classified as energy-related.
• Battery storage resources are classified as demand-related and allocated using the base
and intermediate 12CP demand allocators.
• Demand response purchased power is classified as demand-related and allocated using
the peak 4CP demand allocators.
• All other purchased power is classified as energy-related.
• Transmission facilities are classified as demand-related.
• Distribution, customer, and miscellaneous costs are classified according to the cost
characteristics they are intended to serve.
Battery storage resources are classified as 100 percent demand-related because their modeled
purpose is to provide system capacity during peak-demand periods. They are allocated using the
base and intermediate 12CP demand allocators because their modeled capability is available
during peak-demand periods throughout the year, rather than only during the summer peak
period.
Demand-related production costs associated with base and intermediate load-serving resources
are allocated using 12-month net coincident peak ("12CP") demand allocators. Demand-related
Page 2 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 2 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
production costs associated with peaking resources are allocated using four-month coincident
peak ("4CP") demand allocators derived from the June through September monthly net
coincident peak demands. These allocators are designed to reflect customer-class contributions
to the system conditions that drive production capacity requirements.
Energy-related costs are allocated using seasonal energy allocators that combine normalized
energy usage and marginal-cost-weighted energy usage. Customer-related costs are allocated
using customer allocators designed to reflect the number of customers served and the activities
required to provide customer-related services.
Following functionalization, classification, and allocation, the resulting costs are summarized by
customer class to develop class cost responsibility results.
Idaho Power Company's GRM
Idaho Power Company's GRM builds upon PAEM by incorporating measured customer-class
growth into the allocation of identified growth-related portions of applicable production and
transmission costs. GRM retains PAEM's functionalization and classification procedures while
separately allocating the embedded and growth-related portions of the applicable production
and transmission revenue requirement components.
Under the GRM:
• Functional growth shares are developed for the applicable demand-related and energy-
related production plant classifications and for transmission.
• The functional growth shares separate the applicable revenue requirement components
into embedded and growth-related portions.
• Embedded portions are allocated using the applicable PAEM allocation factors, while
growth-related portions are allocated using the applicable Growth-Weighted Allocation
Factors.
• The resulting embedded and growth-related allocations are combined to determine total
class cost responsibility.
Variable-energy costs remain subject to the PAEM allocation framework and are not separated
for growth-weighted treatment.
Development of Growth Shares
GRM begins by reviewing production, battery-storage, and transmission projects occurring
between successive class cost-of-service studies to identify investments associated with
customer growth.
Page 3 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 3 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
Projects are reviewed to determine whether customer demand and energy growth contributed
to the need or scale of each investment. This standard distinguishes growth-related investment
from investment needed primarily to maintain, replace, or otherwise support the existing
system.
Identification as growth-related does not mean that a facility exclusively serves growing
customer classes. Once placed in service, the facility may support reliability, resource
integration, operations, and the requirements of both existing and growing customer classes.
After growth-related projects are identified, the value of identified growth-related investment
for each applicable production and transmission function is evaluated relative to the total
investment reviewed for that function. This comparison establishes a function-specific growth
attribution percentage representing the portion of the evaluated investment associated with
customer growth.
Associated network upgrades are evaluated within the transmission function even when the
upgrades are required to integrate a generation resource.
The resulting growth attribution percentage is then applied to the change in production and
transmission rate base between the studies being evaluated to estimate the growth-related
portion of rate base for each applicable production and transmission function.
For each applicable function:
• Growth-Related Functional Rate Base = Change in Functional Rate Base x Functional
Growth Attribution Percentage
The resulting growth-related rate base is then compared to the corresponding current-
study rate base balance to determine a growth share for each applicable production and
transmission function.
• Functional Growth Share = Growth-Related Functional Rate Base.-:.- Current Functional
Rate Base
The resulting growth shares are subsequently used to separate the total production and
transmission revenue requirements into embedded and growth-related portions.
Application of Growth Shares to Revenue Requirement
Once growth shares have been established for the applicable production and transmission
functions, those shares are applied to the associated revenue requirement components in order
to identify the growth-related portion of the total revenue requirement.
The GRM begins with the total production and transmission revenue requirements developed
under the PAEM. The methodology separates the existing functional revenue requirement into
Page 4 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 4 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
embedded and growth-related portions; it does not independently develop a project-specific
revenue requirement or change the total revenue requirement.
For each applicable production and transmission function, the calculated growth share is
applied consistently to each revenue-requirement component assigned to that function,
including:
• Rate base;
• Operating expenses;
• Other revenues; and
• Related revenue-requirement components.
The growth-related and embedded portions of each revenue requirement component are
calculated as:
• Growth-Related Component =Total Functional Component x Growth Share
• Embedded Component =Total Functional Component x Embedded Share
Embedded Share = 1 — Growth Share.
Applying the growth share in this manner allows the methodology to identify the portion of
revenue requirement associated with growth-related production and transmission investment
while preserving the underlying functionalization and classification structure established under
the PAEM.
Once the growth-related and embedded portions have been determined, the embedded
portion continues to be allocated using the embedded allocation framework, while the growth-
related portion is allocated using the applicable Growth-Weighted Allocation Factors.
The resulting embedded and growth allocations are then combined to determine the total class
cost responsibility for each applicable production and transmission function.
Growth-Weighted Allocation Factors
Once growth shares have been established and the applicable production and transmission
revenue requirements have been separated into embedded and growth-related portions,
Growth-Weighted Allocation Factors are developed to allocate the growth-related portion
among customer classes.
The Growth-Weighted Allocation Factors are designed to recognize both traditional embedded
cost responsibility and measured growth responsibility. Rather than replacing the Company's
embedded allocation factors, the methodology combines the existing embedded allocators with
allocators derived from measured customer growth occurring during the analysis period.
Page 5 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 5 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
The development of Growth-Weighted Allocation Factors begins with the applicable allocator
from the PAEM. Customer growth occurring between the studies being evaluated is then
measured for each applicable production and transmission function.
Class growth factors are developed by measuring positive incremental changes in the applicable
allocation factors between the studies evaluated. Those positive changes are normalized to
determine each class's proportionate share of measured growth for the applicable function.
A customer class without a positive incremental change does not receive a positive class growth
factor. The class nevertheless continues to receive cost responsibility through the embedded
component of the applicable Growth-Weighted Allocation Factor.
Customer migration between rate schedules is distinguished from actual customer-class growth.
When necessary, prior-period class information is restated to reflect migrating customers in the
class in which they appear in the current study before changes in the applicable allocation
factors are measured.
The class growth factor does not replace the embedded allocation factor. Rather, it is combined
with the applicable embedded allocation factor to develop the Growth-Weighted Allocation
Factor.
For each applicable production and transmission function:
The functional growth share performs two related roles in the model. First, it separates the
applicable functional revenue requirement into embedded and growth-related portions.
Second, the functional growth share and its complementary embedded share are used to
weight the embedded allocation factor and class growth factor when developing the Growth-
Weighted Allocation Factor.
Growth-Weighted Allocation Factor= (Embedded Share x Embedded Allocation Factor) +
(Growth Share x Class Growth Factor)
Where:
• Embedded Share represents the portion of the applicable function's revenue
requirement attributable to the pre-existing system and equals 1 — Growth Share.
• Growth Share represents the portion of the applicable function's revenue requirement
attributable to growth-related investment.
• Embedded Allocation Factor represents the applicable allocation factor developed under
the PAEM.
• Class Growth Factor represents the factor developed from measured positive customer-
class growth during the study period.
Page 6 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 6 of 18

Idaho Power Company Exhibit 1:CCOs PAEM and GRM Model Process Guide
The functional growth share and embedded share used in this weighting are complementary
and total 100 percent. The resulting Growth-Weighted Allocation Factor blends the applicable
embedded allocation factor and class growth factor.
The resulting Growth-Weighted Allocation Factor is applied only to the growth-related portion
of the applicable functional revenue requirement. The embedded portion is separately allocated
using the applicable PAEM allocation factor.
GRM does not directly assign an identified project to an individual customer or customer class
and does not allocate the entire applicable functional cost solely to classes with measured
growth.
Rationale for Growth-Weighted Allocation Factors
Investments identified as growth-related may be driven, in whole or in part, by customer
growth. Once placed in service, however, those facilities operate as part of the integrated
production or transmission system and may support reliability, resource integration, operations,
and the requirements of both existing and growing customer classes.
GRM therefore does not allocate the identified growth-related portions solely on the basis of
measured customer-class growth. Instead, Growth-Weighted Allocation Factors combine
embedded cost responsibility with measured customer-class growth. This treatment recognizes
both the role of customer growth in the identified investment and the facility's operation as
part of the integrated system.
I. PROCESS OVERVIEW
A. Functionalization
Functionalization is the process of assigning the Company's revenue requirements to specific
utility operating functions: Production, Transmission, Distribution, Customer, and
Miscellaneous. These operating functions recognize the different roles played by various
facilities in the electric utility system. In the Company's accounts, these roles are identified to
some degree, particularly in recording plant costs as production-, transmission-, or distribution-
related. However, this functional breakdown is not sufficient for cost-of-service purposes. As
such, individual plant items are examined and, where possible, the associated investment costs
are assigned to one or more operating functions, such as substations, primary lines, secondary
lines, and meters. This level of functionalization allows costs to be more equitably allocated
among classes of customers.
Page 7 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 7 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
B. Classification
The Electric Utility Cost Allocation Manual, published in January 1992 by the National
Association of Regulatory Utility Commissioners, provides the general framework for classifying
utility costs as customer-related, demand-related, or energy-related. The Peak & Average
treatment described in this Process Guide applies the peak and average demand classification
method discussed in the Manual to eligible production plant. These three cost components are
used to reflect that an electric utility makes service available to customers continuously;
provides as much service, or capacity, as customers may require at any point in time; and
supplies energy to provide customers the ability to do useful work over an extended period of
time. These three concepts of availability, capacity, and energy are related to the three
components of cost, designated as customer, demand, and energy components, respectively. To
classify a particular cost by component, focus is given to whether the cost varies because of
changes in the number of customers, changes in demand imposed by customers, or changes in
energy used by customers.
Examples of customer-related costs include the following:
• Plant investments and expenses associated with meters and service drops
• Meter reading
• Billing and collection
• Customer information and services
• Certain investment in the distribution system
These costs are incurred based on the number of customers on the system, irrespective of the
amount of energy consumed, and are generally considered fixed costs.
Demand-related costs are investments in production, transmission, and a portion of the
distribution plant, together with the associated operation and maintenance ("O&M") expenses
necessary to accommodate the maximum demand imposed on the Company's system.
Energy-related costs include costs incurred to produce or acquire energy to serve customer
consumption, such as variable production-related expenses, as well as energy-related
production plant costs classified under the Peak & Average Classification Methodology.
C. Allocation and Summarization of Results
Once costs are functionalized and classified, they are allocated to customer classes based on the
applicable allocation factors. Under the GRM, Growth-Weighted Allocation Factors are also
applied to identified production and transmission revenue requirement components as
Page 8 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 8 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
described elsewhere in this Process Guide. After individual costs are allocated to the various
classes of service, the Company totals these costs to arrive at a breakdown of utility rate base
and expenses by class. The results are summarized to measure the 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.
II. ASSIGN AND FUNCTIONALIZED COST
MODULES
The class cost-of-service modeling framework uses two principal modules. The Assign Module
("AS Module") performs the functionalization and classification processes described in this
Process Guide. The Functionalized Cost Module ("FC Module") performs the class allocation
process and summarizes the resulting class cost responsibility.
Under GRM, the modeling framework develops functional growth shares and Growth-Weighted
Allocation Factors for the applicable production and transmission functions. The FC Module
applies the functional growth shares to the associated revenue-requirement components,
allocates the embedded and growth-related portions using the applicable allocation factors, and
combines the resulting allocations to determine total class cost responsibility.
Each operation performed within the FC Module is shown as a separate worksheet to make the
allocation process transparent and easier to follow.
III. CLASSIFICATION
GRM does not change the classifications established under PAEM. The applicable production
and transmission costs retain their PAEM classifications when separated into embedded and
growth-related portions for allocation.
A. Production Plant
Eligible production plant, excluding battery storage resources, is classified between demand-
related and energy-related components using Peak &Average.
For purposes of the classification calculation, peak system demand is measured using the
Company's 1 NCP demand, and average system demand is calculated as total annual system
energy divided by 8,760 hours. The classification percentages are as follows:
• Energy-Related Percentage
= Average Demand - (Average Demand + Peak Demand)
Page 9 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 9 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
• Demand-Related Percentage
= Peak Demand _ (Average Demand + Peak Demand)
The demand-related and energy-related percentages are complementary and total 100 percent.
Peak and average demand establish relative classification weights; their sum does not represent
the amount of generating capacity the Company must construct.
The resulting percentages are applied to eligible production plant accounts to determine the
demand-related and energy-related classifications used in the class cost-of-service study.
The model separately identifies energy-related production plant costs as "Energy- Fixed" and
variable-energy costs as "Energy-Variable." Energy- Fixed represents production plant
classified as energy-related through Peak &Average, while Energy-Variable represents costs
incurred as energy is produced or purchased.
Battery storage resources are classified as 100 percent demand-related because their modeled
purpose is to provide system capacity during peak-demand periods. They are allocated using the
base and intermediate 12CP demand allocators because their modeled capability is available
during peak-demand periods throughout the year, rather than only during the summer peak
period.
B. Transmission Plant
Transmission plant is classified as 100 percent demand-related because transmission investment
is principally associated with the system capability required to reliably serve demand under
limiting normal and contingency conditions. The relevant cost characteristic is the capability
required under those system conditions, rather than annual energy throughput.
C. PURPA and Purchased Power Expenses
PURPA and purchased-power expenses booked to FERC Account 555 are generally classified as
100 percent energy-related. These costs are incurred to acquire energy to serve customer
consumption.
An exception is demand response purchased power, which is classified as 100 percent peak
demand-related because those expenses are incurred during the Company's summer peak
period to reduce or manage demand when additional system capability is needed.These costs
are allocated using the applicable peak-demand allocation methodology.
Variable production-related costs, including fuel and similar variable production expenses, are
classified as energy-related.
Page 10 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 10 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
D. 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-to-variable ratio computation method used in prior
Company class cost-of-service studies. The fixed-to-variable ratio is determined using a system
capacity utilization measurement based on a three-year average load duration curve.
This approach recognizes that certain distribution facilities are installed to accommodate
customer demand requirements, while other facilities and investments are incurred primarily
based on the number of customers served. Accordingly, distribution plant is classified between
demand-related and customer-related components consistent with the underlying cost
characteristics of the facilities being studied.
IV. FUNCTIONALIZATION
A. 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.
B. 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.
C. 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 1) fuel inventory, which is
functionalized based on energy production and 2) materials and supplies, which are
functionalized based on the appropriate plant function. Energy efficiency program expenses are
functionalized to the Production function because demand-side management resources may be
considered analogous to supply-side production resources. Following functionalization, these
costs are classified consistent with other eligible production resources under the Peak &
Average Classification Methodology.
Page 11 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 11 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
D. 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 such specific service item.
E. O&M Expense
In general, the basis for the functionalization of 0&M expense is the same as that for the
associated plant.
F. Labor Components
For each applicable expense account in each functional group, the labor component is
separately functionalized. For example, for Account 535 the labor-related supervision and
engineering expense is functionalized based on the cumulative labor as functionalized for
accounts 536 through 540. Similarly, the allocation of supervision and engineering associated
with hydraulic maintenance expense, Account 541, is based on the composite labor expense for
accounts 542 through 545. Total functionalized labor expense serves the additional purpose of
functionalizing employee pensions and other labor-related taxes and expenses.
G. 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.
V. ALLOCATION
A. Derivation of Peak Demands
For customers taking service through Advanced Metering Infrastructure (AMI) and interval
meters, system coincident demands are taken directly from their meter data. As this represents
greater than 99% of Idaho Power's customers, it is significant enough to average and apply to
any non-AMI or non-interval customer. Coincident demand values for each rate class are
calculated by summing interval metered data, at the hour of net peak (the peak system hourly
load value when the output from non-dispatchable resources, such as solar and wind
generation, is excluded) or at the hour coincident to system peak for the year prior to the test
year. These monthly coincident demand values are adjusted upward for non-interval metered
customers and system losses. Using these adjusted monthly coincident demand values,
Page 12 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 12 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
allocation factors are created for each month by dividing each rate class's value by the total
adjusted retail metered demand in the given month. Allocation factors are then multiplied by
the forecasted test year system demand at the applicable peak time, by month.
To calculate non-coincident peak demands, by rate class, a non-coincident (group) demand
factor is defined. The demand factor is the ratio of a non-coincident peak demand to the
average demand. To determine the test-year monthly non-coincident peak demands by rate
class, each rate class's monthly non-coincident demand factors are applied to the test-year
monthly average demand values for each rate class.
To account for the partial requirement nature of on-site generation customers, measurement of
the energy delivered to customers is the basis of energy and system coincident load statistics.
On-site generation exports are independently valued outside the Class Cost-of-Service study.
B. Marginal Cost Usage
While production demand allocators are not marginal-cost weighted, marginal-cost weighting is
used in the development of energy-related and transmission-related allocation factors.
Marginal-cost weighting combines embedded allocation measures with information regarding
the relative monthly cost of serving customer loads and recognizes the influence of seasonal
load profiles on cost responsibility.
Transmission marginal costs are seasonalized based on the Company's monthly loss-of-load-
expectation ("LOLE") analysis conducted as part of its Integrated Resource Plan ("IRP"). The
monthly LOLE amounts for the five-year period from 2025 through 2029 are averaged to define
the share of the annual capacity cost assigned to each month. The total demand-related
transmission marginal costs for each month are then derived by adding the monthly values for
both categories of transmission costs.
Marginal energy costs are determined from the simulated hourly operation of the Company's
power supply system over 37 streamflow conditions for the five-year period from 2025 through
2029.
Marginal costs are used solely to develop allocation factors and are not used to develop the
Company's revenue requirement.
C. Production Plant Cost Allocation
Production plant costs are allocated according to the classifications established under PAEM.
Eligible production plant is first classified between demand-related and energy-related
components using Peak & Average. The resulting demand-related and energy-related portions
are then allocated using the applicable production demand and energy allocation factors.
Page 13 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 13 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
The demand-related portion of eligible production plant associated with serving base and
intermediate load is allocated using 12-month net coincident peak ("12CP") demand allocators.
The demand-related portion of eligible production plant associated with serving peak load is
allocated using four-month coincident peak ("4CP") demand allocators derived from the June
through September monthly net coincident peak demands. These allocators reflect customer-
class contributions to the system conditions that drive production capacity requirements.
The energy-related portion of eligible production plant is identified within the model as Energy-
Fixed and is allocated using the applicable EF10S and EF10NS seasonal energy allocation factors
described in Section V.F. Variable-energy costs are separately identified as Energy- Variable and
are allocated using the applicable EV10S and EV10NS seasonal energy allocation factors.
The production cost allocation methodology used in the study is based on the concept that the
costs associated with each generation resource can be categorized according to the type of
loads being served. Utilities typically experience three distinct production costing periods driven
by customer loads: base, intermediate, and peak.The base period is equivalent to low-load or
off-peak periods where loads are generally at their lowest, typically during nighttime hours. The
intermediate period represents shoulder periods driven by mid-level loads that typically occur
during winter daytime hours and during the early morning and evening hours of the summer
months. The peak period is driven by the Company's highest loads, which generally occur during
summer afternoons and evenings.
The base and intermediate load requirements on the Company's system are typically served by
the same generation resources. Accordingly, these two categories are combined for production
cost allocation purposes. Generation resources constructed primarily to serve peak demand,
such as combustion turbines, are treated separately because they are generally operated to
serve peak load conditions. Consistent with that concept, demand-related costs associated with
peak-serving resources are allocated separately from demand-related costs associated with
base and intermediate resources. Marginal-cost weighting is not applied to these production
demand allocators because the seasonal characteristics of customer loads are already reflected
through the underlying 12CP and 4CP allocation factors.
Production plant costs assigned to the base and intermediate production category include
Accounts 310 through 316, Steam Production; Accounts 330 through 336, Hydraulic Production;
and the Langley Gulch Combined-Cycle Combustion Plant ("CCCP"), recorded within Accounts
340 through 346, Other Production. The costs identified under the Steam Production category
represent the Company's investment in coal-fired generation facilities, while the costs identified
under the Hydraulic Production category represent the Company's investment in hydroelectric
generation facilities. The majority of costs related to the Company's coal-fired facilities have
been excluded from the 2024 base financial data used to develop the 2025 test year. These
Page 14 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 14 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
costs are instead reflected through the levelized revenue requirement additions associated with
Valmy and Bridger and are incorporated into the total revenue requirement.
Utilities typically serve customer loads by operating the lowest-cost generation resources first
and dispatching higher-cost resources as system demand increases. Idaho Power operates its
generation portfolio in a similar manner. Because hydroelectric generation represents a
significant portion of the Company's resource portfolio, streamflow conditions and operating
economics influence the relative contribution of hydroelectric and thermal resources
throughout the year. Hydroelectric production can vary materially based on water availability,
requiring thermal generation to increase or decrease accordingly. As a result, hydroelectric and
thermal generation resources work together to serve base and intermediate load requirements
throughout the year. Although the relative contribution of these resources may vary by month,
the combined output of hydroelectric and thermal resources remains substantially more
consistent across seasons than the output of peaking combustion turbines.
Accounts 340 through 346, Other Production, contain the Company's investment in gas-fueled
generation resources. These accounts include both CCCPs and simple-cycle combustion plants
("SCCPs"). Because these resources are used to serve different load requirements, they are
categorized separately for allocation purposes. The Langley Gulch CCCP is treated as a base and
intermediate load-serving resource, while the Bennett Mountain and Danskin SCCPs are treated
as peak-serving resources. The production plant investment associated with these combustion
turbines is therefore allocated using the peak-load allocation framework.
Battery storage resources recorded in Account 387 are excluded from Peak&Average and
classified separately as 100 percent demand-related. They are allocated using the base and
intermediate 12CP demand allocators because their modeled capability is available during peak-
demand periods throughout the year rather than only during the summer peak period.
Within the FC Module, D1013S and D10BNS allocate demand-related production costs associated
with serving base and intermediate loads. D10P allocates demand-related production costs
associated with serving peak loads. D1013S and D10BNS represent the non-weighted average 12-
month coincident net-peak demands for the summer and non-summer seasons, respectively.
D10P represents the non-weighted average four-month coincident net-peak demands for June
through September. Energy- Fixed and Energy-Variable costs are allocated using the applicable
EF10 and EV10 seasonal energy allocation factors described in Section V.F.
D. Transmission Cost Allocation
Transmission plant is classified as 100 percent demand-related and is allocated using the
transmission allocator D13.
Page 15 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 15 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
D13 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 system peak demands for
each customer class. Second, weighted coincident peak demand values are derived by
multiplying the actual monthly coincident system 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 D13.
This averaging approach reflects each class's contribution to coincident system demand and the
relative monthly cost of transmission capability.
E. Distribution Cost Allocation
The demand-related components of distribution plant, both primary and secondary, are
allocated using the non-coincident group peak demand allocators D2O, D3O, D5O, and D6O.
The customer-related components of distribution plant, both primary and secondary, are
allocated using the average number of customers represented by customer allocation factors
C2O, C3O, C5O, and C6O.
F. Energy-Related Cost Allocation
Seasonal energy allocation factors are derived by averaging each customer class's normalized
share of energy usage with its normalized energy share weighted by monthly marginal energy
costs. Separate summer and non-summer factors are developed by first calculating each class's
proportionate share of normalized energy usage for the applicable season. Each class's monthly
normalized energy usage is then weighted by the applicable monthly marginal energy costs, and
the resulting weighted shares are normalized. The normalized energy share and marginal-cost-
weighted energy share are averaged to produce the applicable seasonal energy allocation factor.
The model maintains separate energy allocation-factor families for Energy- Fixed ("EF1O") and
Energy- Variable ("EV1O"). EF1O applies to energy-related production plant costs classified
through Peak & Average, while EV1O applies to variable-energy costs, including applicable
energy production and purchased-power costs.
EF1O and EV1O are calculated using the same seasonal energy-allocation methodology and
therefore produce identical allocation results under PAEM. The factors are maintained
separately because GRM may apply growth-weighted treatment to the identified growth-
related portion of eligible Energy- Fixed production plant costs, while Energy-Variable costs
remain allocated using EV10 under the PAEM framework.
The averaging methodology used to derive EF1O and EV1O is consistent with the general
approach used to derive the transmission allocation factor D13.
Page 16 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 16 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
G. Customer-Related Cost Allocation
The principal customer accounting expenses requiring allocation are meter-reading expenses,
customer records and collections expenses, and uncollectible accounts. Meter-reading expenses
and customer records and collections expenses are allocated based upon a review of the
Company's actual practices in reading meters and preparing customer bills. The allocation of
uncollectible accounts is similarly based upon a review of actual Company data. Customer
assistance expenses are allocated based on the average number of customers within each class.
H. State and Federal Income Tax Allocation
State and federal income taxes attributable to the Idaho jurisdiction are allocated to each
customer class and special contract customer according to each class's allocated share of rate
base. Once state and federal income taxes have been allocated to each customer class, they are
functionalized based on the functionalization of total rate base and expenses applicable to that
class.
I. Growth-Weighted Allocation Factors
Under GRM, the applicable production and transmission revenue requirements are separated
into embedded and growth-related portions using the functional growth shares described
previously. The classifications established under PAEM remain unchanged.
Embedded portions are allocated using the applicable PAEM allocation factors described in this
section. Growth-related portions are allocated using the corresponding Growth-Weighted
Allocation Factors. As described previously, each Growth-Weighted Allocation Factor combines
the applicable PAEM allocation factor with a customer-class growth factor derived from
normalized positive changes in the corresponding allocation measure between the studies
being evaluated.
Growth-Weighted Allocation Factors are developed for the applicable production demand,
Energy- Fixed, and transmission categories receiving growth-weighted treatment. Energy-
Variable costs do not receive growth-weighted treatment and remain allocated using the
applicable EV10 factors. Distribution, customer, and other costs not receiving growth-weighted
treatment remain allocated using the applicable PAEM allocation factors.
The embedded and growth-related allocations are combined to determine total class cost
responsibility for each applicable production and transmission function. The combined
allocations reconcile to the applicable functional revenue requirements.
Page 17 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 17 of 18

Idaho Power Company Exhibit 1:CCOS PAEM and GRM Model Process Guide
VI. CLASS COST RESPONSIBILITY AND
APPLICATION
Once the applicable revenue requirement has been functionalized, classified, and allocated, the
resulting class cost-of-service amounts reflect each customer class's allocated share of rate base,
operating expenses, depreciation expense, taxes, other revenues, and related components
included in the study.
These results are used to evaluate class cost responsibility and may support the development of
rates designed to recover the Company's authorized revenue requirement. PAEM and GRM
affect the allocation of applicable costs among customer classes; neither methodology increases
or decreases the Company's total revenue requirement.
Model Controls and Reconciliation
The models include controls to confirm that applicable costs are fully allocated, are not
allocated more than once, and reconcile to the applicable functional and total revenue
requirements. Under GRM, the controls also confirm that the embedded and growth-related
portions reconcile to the applicable functional revenue requirements and that the combined
class allocations reconcile to the total revenue requirement.
Page 18 of 18 Exhibit No. 1
Case No. IPC-E-26-07
C.Allen, IPC
Page 18 of 18

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
EXHIBIT 2
PAEM Model

SEE EXCEL SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
EXHIBIT 3
PAEM Model Allocation Factor Derivation
Workpapers

SEE EXCEL SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
EXHIBIT 4
2025 CCOS Growth Model

SEE EXCEL SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
EXHIBIT 5
2025 CCOS Growth Model Allocation Factor
Derivation Workpapers

SEE EXCEL SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
EXHIBIT 6
GRM Model

SEE EXCEL SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
EXHIBIT 7
GRM Model Allocation Factor Derivation
Workpapers

SEE EXCEL SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
EXHIBIT 8
NLL GRM Model

SEE EXCEL SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
EXHIBIT 9
NLL GRM Model Allocation Factor Derivation
Workpapers

SEE EXCEL SPREADSHEET