20260331APPLICATION.pdf

-�IQAFIO R®
RECEIVED
Megan Goicoechea Allen March 31, 2026
Corporate Counsel IDAHO PUBLIC
mgoicoecheaallenC�idahopower.com UTILITIES COMMISSION
March 31, 2026
VIA ELECTRONIC FILING
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, Idaho 83720-0074
Re: Case No. IPC-E-26-07
Idaho Power Company's Petition to Evaluate Class Cost-of Service
Methodology, Consider Alternative Class Cost-of-Service Studies, and
Determine Cost of Service Considerations for New Large-Load Customers
Dear Commission Secretary:
Attached for electronic filing please find Idaho Power Company's Petition in the
above-entitled matter. Also attached is a Protective Agreement
Due to the voluminous nature of confidential and non-confidential information
provided, the Company is posting the documents to the secure FTP site to allow parties
to view the requested information remotely. Because certain attachments contain
confidential information, the FTP site is divided between confidential and non-confidential
information. The login information for the non-confidential portion of the FTP site will be
provided to all parties, while the login information for the confidential portion will only be
provided to those parties who have executed the Protective Agreement in this matter.
If you have any questions about the attached documents, please do not hesitate
to contact me.
Very truly yours,
\,� I coct�UA o&
Megan Goicoechea Allen
MGA:sg
Attachments

CERTIFICATE OF ATTORNEY
ASSERTION THAT INFORMATION CONTAINED IN AN IDAHO PUBLIC UTILITIES
COMMISSION FILING IS PROTECTED FROM PUBLIC INSPECTION
Idaho Power Company's Petition to Evaluate Class Cost of Service Methodology
and to Consider Alternative Class Cost of Service Studies and Determine the
Appropriate Cost of Service for New Large-Load Customers
Case No. IPC-E-26-07
The undersigned attorney, in accordance with Commission Rules of Procedure 67,
believes that Attachment 11 to the Application, dated March 31, 2026, contains
information that Idaho Power and/or a third-party claim constitutes trade secrets,
confidential business records, and/or other non-public records exempt from disclosure
under state or federal law including but not limited to Idaho Code § 48-801, et seq.; Idaho
Code § 74-101, et seq.; and/or 17 CFR Part 243 (Securities and Exchange Commission
Regulation FD). As such, it is protected from public disclosure, inspection, examination,
or copying.
DATED March 31, 2026.
�-/%r I�
Megan Goicoechea Allen
Counsel for Idaho Power Company

MEGAN GOICOECHEA ALLEN (ISB No. 7623)
LISA LANCE (ISB No. 6241)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
mgoicoecheaallen(a-),idahopower.com
IlanceCc)_idahopower.com
Attorneys for Idaho Power Company
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 ) IDAHO POWER COMPANY'S
ALTERNATIVE CLASS COST-OF- ) PETITION TO INITIATE DOCKET
SERVICE STUDIES, AND DETERMINE )
COST OF SERVICE CONSIDERATIONS )
FOR NEW LARGE-LOAD CUSTOMERS )
COMES NOW, Idaho Power Company ("Idaho Power" or "Company"), in
compliance with Order No. 36892 and pursuant to Commission Rules of Procedure 33
and 53 (IDAPA 31.01 .01.033 and .053) and hereby petitions the Idaho Public Utilities
Commission ("Commission") to initiate a docket to evaluate and develop a record on
Idaho Power's Class Cost-of-Service ("CCOS") methodology including consideration of
alternative methodologies. This Petition is based on the following:
PETITION - 1

I. INTRODUCTION
1. The instant Petition stems from the Stipulation and Settlement
("Stipulation") approved by the Commission in the Company's 2025 General Rate Case,'
which included a non-revenue stipulated agreement to facilitate Commission evaluation
of the Company's cost-of-service methodology. More specifically, Section C, Subsection
10 of the Stipulation, provides in pertinent part:
The Stipulating Parties agree that it would be appropriate for the
Commission to address the CCOS methodology and associated policy
issues in a separate proceeding in which alternatives to the Company's filed
CCOS methodology in this case, including a CCOS study with an hourly-
informed class allocation of Production and Transmission revenue
requirement, will be presented for the Commission' s consideration. To this
end, Idaho Power agrees to initiate a single-issue case related to CCOS
methodology for the Commission's consideration ("Single Issue CCOS
Case") in advance of filing a Notice of Intent for its next GRC but in no event
later than the end of the first quarter of 2026. Prior to filing that case, Idaho
Power will meet with Staff and other interested Parties to identify alternative
CCOS studies that will be presented by the Company for Commission
consideration. . .
2. In reviewing the proposed settlement, the Commission agreed that "a
focused, single-issue proceeding will provide the Company, Staff, and intervening parties
with the most effective forum to collaborate, develop a robust record, and fully examine
the CCOS methodology.112 In its Order approving the Stipulation, the Commission also
noted that it intended to review and determine the appropriate cost of service for new
large-load ("NLU) customers as part of the CCOS case to ensure that other customer
classes are not adversely affected by NLL.3
In the Matter ofldaho Power Company's Application for Authority to Increase its Rates and Charges for Electric
Service in the State ofldaho,Case No. IPC-E-25-16,Order No. 36892(Dec. 30,2025).
2Id. at 12.
s Id. at 13.
PETITION - 2

3. Accordingly, the Company submits this Petition to initiate the single-issue
CCOS evaluation docket contemplated by the Stipulation and Commission Order No.
36892, and to provide a focused forum to develop a record on CCOS methodology
outside of a general rate case. This Petition does not request rate relief, does not propose
tariff changes, and does not initially ask the Commission to approve any specific CCOS
methodology. Rather, this Petition is intended to initiate the development of "a complete
and targeted evidentiary record"4 and procedural process to support the Commission's
review and evaluation of multiple methodological approaches and any proposed changes.
To that end, Idaho Power requests that the Commission (1) issue a Notice of Petition and
Notice of Intervention Deadline and (2) following the intervention period, direct Staff to
work with parties to establish a procedural schedule that provides opportunities to
exchange proposals, respond to other party positions, and offer recommendations. The
resulting record will support the Commission's consideration of CCOS methodological
approaches in this docket and, in its disposition of this docket, provide guidance to Idaho
Power regarding CCOS methodology for future CCOS studies and future general rate
case filings.
II. STAKEHOLDER ENGAGEMENT AND FILING OVERVIEW
4. Prior to initiating the Single Issue CCOS Case contemplated by the
Stipulation, the Company engaged with Commission Staff and other interested parties to
identify issues within the scope of this docket and to seek input regarding potential
procedural approaches for developing an appropriate record.
4 Id. at 12.
PETITION - 3

5. Consistent with the Stipulation, as part of this collaborative process, Idaho
Power convened a stakeholder kickoff discussion on February 13, 2026, to introduce the
evaluation docket concept and preview the categories of CCOS methodologies the
Company intended to include in its initial filing materials. Idaho Power also requested
Commission Staff and interested parties submit written pre-filing input by February 27,
2026, so that those comments could be considered in the Company's initial filing and
placed in the record in connection with this Petition.
6. Written submissions received in response to that pre-filing solicitation
included Commission Staff, Clean Energy Opportunities for Idaho ("CEO"), Federal
Executive Agencies ("FEA"), Idaho Irrigation Pumpers Association ("IIPA"), Micron
Technology ("Micron"), and NW Energy Coalition ("NWEC"), and are provided in
Attachment 1 (Stakeholder Comments).
7. To facilitate the Commission's review and evaluation of cost-of-service
methodology and policy issues in this case, this Petition includes: (1) a brief overview of
the relevant regulatory history; (2) a description of Idaho Power's most recently filed
CCOS methodology; (3) a summary of four alternative CCOS methodologies presented
in a common format, together with supporting workpapers; and (4) a discussion of cost-
of-service issues specific to new large-load customers. In addition, this Petition is
accompanied by the following attachments that together constitute the filing package for
Commission and stakeholder consideration:
PETITION -4

Table 1. List of Attachments
Attachment # Title Brief description
1 Stakeholder Comments Written pre-filing submissions
from interested parties
2 CCOS Process Guide Step-by-step description of 2025
CCOS + alternatives
3 New Large Load Considerations Background and industry
Memo approaches for large loads
4 2025 CCOS Model 2025 CCOS model results,
calculations, and derivations
5 2025 CCOS Allocation Factor Derivation of allocation factors
Derivation Workpapers used in 2025 CCOS
6 EFAC Model EFAC model results,
calculations, and derivations
7 EFAC Allocation Factor Derivation of allocation factors
Derivation Workpapers used in EFAC
8 AED-4CP Model AED-4CP model results,
calculations, and derivations
9 AED-4CP Allocation Factor Derivation of allocation factors
Derivation Workpapers used in AED-4CP
10 Hourly-Informed Model Hourly-Informed model results,
calculations, and derivations
11 Hourly-Informed Allocation Derivation of allocation factors
Factor Derivation Workpapers used in Hourly-Informed
12 EFAC P&T Model EFAC P&T model results,
calculations, and derivations
13 EFAC P&T Allocation Factor Derivation of allocation factors
Derivation Workpapers used in EFAC P&T
III. RELEVANT REGULATORY HISTORY
8. The following regulatory history is provided solely to orient the Commission
and stakeholders to: (a) how Idaho Power's CCOS methodology has been presented in
prior general rate cases and related proceedings, and (b) how certain methodological
questions have emerged over time. It is not intended to be exhaustive, nor is it offered for
the purpose of advocating for a particular methodological outcome in this docket.
9. Summary Timeline of Key CCOS Milestones. The table below summarizes
major CCOS milestones from prior proceedings and why they are relevant to this docket.
PETITION - 5

Table 2. CCOS Regulatory Milestones (Selected Prior Proceedings)
Proceeding/Order What occurred Why it matters for this docket
1983 GRC Idaho Power presented Establishes an early baseline
U-1006-185 multiple CCOS studies (e.g., that multiple CCOS methods
Order No. 17856 AED, PED/MPED, 12CP, may be presented and
(Feb. 4, 1983) W12CP) within the evaluated; demonstrates that
functional ization, classification, methodological choices can
and allocation framework; the affect class responsibilities and
Commission selected a may require gradualism tools
W12CP approach as the when translated into rates.
reference used in that
proceeding and applied
gradualism tools.
1987 GRC Idaho Power again presented Reinforces that CCOS has
U-1006-265A multiple CCOS studies; the historically been examined by
Order No. 21365 Commission continued to use function and that allocation
(Jul. 29, 1987) W12CP as a starting point and choices can be sensitive to
made function-by-function system conditions and class
determinations in that case. impacts.
1994 GRC Idaho Power presented one Reinforces that CCOS has
IPC-E-94-5 cost-of-service study based on historically been examined by
Order No. 25880 the W12CP method; the function and that allocation
(Jan. 31, 1995) Commission found it choices can be sensitive to
appropriate to again utilize the system conditions and class
W12CP methodology to impacts.
establish revenue requirement
for the customer classes.
2003 GRC Idaho Power filed a CCOS Illustrates that the Commission
IPC-E-03-13 using functionalization, has previously used a GRC to
Order No. 29505 classification, allocation and identify CCOS issues needing
(May 29, 2004) W12CP-style concepts; the focused review outside the
Commission accepted the immediate rate case timeline.
CCOS study for that
proceeding while also directing
further review of certain CCOS
methodology issues before the
next GRC.
PETITION - 6

2004 In response to Order No. Provides precedent for a
Investigation 29505, the Commission standalone CCOS-focused
IPC-E-04-23 opened a separate docket and forum and underscores why an
Order No. 29868 Staff convened workshops to evaluative docket (with
(Oct. 31, 2005) examine CCOS issues; transparent materials and
improvements were made to opportunities to test
process/transparency, but no alternatives) can be useful
consensus emerged on when class impacts are
contested methodological material.
questions given differing class
impacts.
2008 GRC Idaho Power presented Demonstrates evolution of
IPC-E-08-10 multiple cost-of-service studies coincident-peak constructs and
Order No. 30722 in this case, including a CCOS classification choices; relevant
(Jan. 30, 2009) using a 3CP/12CP structure, for understanding continuity
load-factor splitting concepts versus change when
for certain plant categories, comparing current and
and marginal-weighted energy alternative methods. Reinforces
allocators; the Commission that multiple CCOS methods
approved a specific CCOS may be presented and
structure for that proceeding evaluated by the Commission
and it served as a foundation in a GRC.
in later cases.
2011 GRC Idaho Power's filed CCOS Shows how CCOS
IPC-E-11-08 maintained the Commission- methodologies have historically
Order No. 32426 approved 2008 framework with been refined incrementally
(Dec. 30, 2011) targeted refinements, including within the embedded-cost
Demand Response treatment framework, supporting a
in peak calculations, metering measured evaluation of
cost allocation updates alternatives in this docket.
reflecting AMI deployment,
and updates to
coincident-peak inputs.
Resolved by settlement, the
signing parties agreed that the
proposed cost-of-service study
is not binding in future cases.
PETITION - 7

2023 GRC Idaho Power retained the Provides context for why
IPC-E-23-11 general framework while hourly-informed approaches
Order No. 36042 expanding the summer and other alternatives have
(Dec. 28, 2023) coincident-peak allocator from entered stakeholder
3CP (June—August) to 4CP discussions and why this
(June—September) and docket includes multiple
adopting an updated cost methods for evaluation.
classification convention for
fixed/variable costs. Resolved
by settlement, the settling
parties agreed to use the
Company's filed cost-of-
service methodology on a
limited basis for settlement
purposes but did not agree on
a particular cost-of-service
methodology. Settling parties
also agreed to engage in
workshops exploring
time-of-use and an "Hourly
Informed" CCOS concept for
comparison.
2025 GRC For the 2025 GRC, Idaho This docket is initiated to satisfy
IPC-E-25-16 Power refined coincident-peak the settlement obligation and to
Order No. 36892 inputs by using "net peak" develop a record on CCOS
(Dec. 30, 2025) coincident demand (excluding methodology alternatives
contemporaneous outside the general rate case
non-dispatchable output) for timeline.
certain allocators; in Order No.
36892, the Commission
approved a settlement that
includes the Company's
commitment to initiate a
single-issue CCOS
methodology case by the end
of the first quarter of 2026.
PETITION - 8

10. Key Takeaways for this Evaluation Docket. The regulatory history
summarized above demonstrates that:
a. CCOS is a recurring methodological topic that has been addressed
in multiple GRCs using the embedded-cost functionalization,
classification, and allocation framework, with refinements over time
rather than abrupt changes.
b. When methodological choices materially affect class cost
assignment, consensus can be difficult, and a standalone forum can
help clarify options, inputs, and points of disagreement.
11. Moreover, as the Commission has cautioned in past Idaho Power rate
cases, a cost-of-service study is not a perfect tool for assigning system and service costs
to customer classes; while class cost-of-service studies provide a useful starting point for
allocating revenues, the Commission must and does consider other factors such as rate
continuity, equity and proportionality.5 In addition, the Commission has recognized the
inherent limitations of any cost-of-service study: "[T]he preparation of a cost-of-service
study is a combination of art and science with the results hinging on key assumptions and
allocation methods.116
5 See, e.g., In the Matter of the Application of Idaho Power Company for Authority to Increase its Interim
and Base Rates and Charges for Electric Service, Case No. IPC-E-03-13, Order No. 29505 at 45 (May
29, 2004).
6 In the Matter of the Application of Idaho Power Company for Authority to Increase its Rates and
Charges for Electric Service to Customers in the State of Idaho, Case No. I PC-E-94-05, Order No. 25880
at 26 (Jan. 31, 1995). See also In the Matter of the Application of Idaho Power Company for Authority to
Increase its Rates and Charges for Electric Service to Customers in the State of Idaho, Case No. U-1006-
185, Order No. 17856 at 6 (Feb. 4, 1983) ("All cost-of-service studies suffer from common defects. They
attempt to reduce a dynamic system to a static one for purposes of study and therefore omit important
considerations, and their results vary according to their originators' subjective assumptions underlying
their objective arithmetic. We do not belittle the value of cost-of-service studies for rate setting purposes.
But the limitations of the studies should be stated so that their results can be used with an awareness of
their limitations.")
PETITION - 9

12. Against this framework, the Company has endeavored in this filing to
support a focused evaluation of CCOS methodology options, the inputs they require, and
how alternative methodological choices may affect cost allocation outcomes and has
included supporting materials (Attachments 1 - 13) that provide the documentation and
analytical detail necessary to evaluate Idaho Power's 2025 CCOS Methodology and the
alternatives presented in this filing. As later described, each of these alternatives were
previously presented by other interested parties in recent general rate case proceedings.
IV. OVERVIEW OF 2025 CCOS METHODOLOGY
13. Idaho Power's most recently filed CCOS methodology as part of Case No.
IPC-E-25-16, referred to herein as the "2025 CCOS Methodology," follows the traditional
three-step framework of functionalization, classification, and allocation to assign
Idaho jurisdictional costs to customer classes based on the functions those costs support
and the cost drivers they are intended to reflect.
Functionalization, Classification, and Allocation
14. Functionalization (Production, Transmission, and Distribution).
Functionalization assigns plant investment, operating expenses, taxes, and related items
to the utility's primary operation functions — Production, Transmission, and Distribution —
based on the part of the system each cost supports. As part of this step, plant records are
reviewed and, where appropriate, associated with more specific facilities (e.g.,
substations, primary and secondary lines, meters) to support equitable allocation across
customer classes.
15. Classification (Demand- Energy-, and Customer-Related). Following
functional ization, costs are classified as demand-, energy-, or customer-related
consistent with the National Association of Regulatory Commissioners ("NARUC")
PETITION - 10

Electric Utility Cost Allocation Manual framework. Demand-related costs reflect the
capacity necessary to serve customers at their peak usage and commonly include
Production and Transmission plant associated capacity-driven expenses. Energy-related
costs generally vary with kilowatt-hour ("kWh") consumption and include variable
production expenses such as fuel and purchased power. Customer-related costs are
driven primarily by the number of customers served and include items such as metering,
meter reading, billing, and customer service. Under the 2025 CCOS Methodology,
Production and transmission plant are classified as 100 percent demand-related;
Purchased Power is classified as 100 percent energy-related; and Distribution plant is
separated into demand- and customer-related components using the Company's
established fixed-to-variable ratio informed by a three-year load-duration curve.
16. Allocation. After functionalization and classification, Idaho Power applies
factors intended to reflect how customer classes use the system.
a. Demand-classified production allocation. A key element of the 2025
CCOS Methodology is the use of net-peak based coincident demand
measures, including 12CP and 4CP values calculated at the hour of
each month's highest net peak (i.e., system demand adjusted to exclude
contemporaneous output from non-dispatchable resources). Under this
structure, Production plant associated with base and intermediate
resources is allocated using annual net-peak 12CP values, derived at
the hour of each month's highest net system load, which adjusts system
peak to exclude output from non-dispatchable resources. Production
plant associated with peaking resources are allocated using net-peak
PETITION - 11

4CP values from June through September to reflect summer capacity
conditions.
b. Transmission allocation. For Transmission, costs are allocated using
the D13 allocation factor. D13 is derived by averaging (i) ratios based
on actual coincident system peak demands and (ii) ratios based on
coincident peak demands weighted by monthly transmission marginal
costs.
c. Distribution allocation. Distribution plant is assigned using non-
coincident group-peak allocators for demand components and average
customer counts for customer components.
d. Energy-related allocation. The Company's seasonal energy allocators
(E10S and E10NS) are derived by averaging normalized class energy
shares with normalized class energy shares weighted by monthly
marginal energy costs, producing summer and non-summer allocators
used in the study.
e. Customer-related allocation. Customer-related costs (including
metering, billing, and customer service) are allocated using customer
counts and activity measures reflecting the practices required to serve
customers.
17. The 2025 CCOS Methodology is intended to align with class cost
responsibility with observable cost drivers across three dimensions of electric service: (i)
capability to meet periods of highest load (reflected through net-peak coincident demand
allocators), (ii) year-round energy usage (reflected through seasonal energy allocators),
PETITION - 12

and (iii) customer-related activities (reflected through customer counts and activity
measures).
18. To preserve that linkage within an embedded cost-of-service framework,
the 2025 CCOS Methodology uses net-peak coincident-demand measures — calculated
at each month's highest net system load (system demand net of contemporaneous non-
dispatchable output) — to allocate demand-related Production and Transmission costs,
and it uses seasonal energy allocators that average normalized class energy with
marginal-weighted energy to allocate energy-related costs.
19. In combination, these elements are intended to reflect how the timing and
magnitude of class usage relates to embedded system costs: classes that contribute
more electric load during monthly net-peak conditions bear a greater proportional share
of demand-related costs, while classes with greater year-round energy use bear a
correspondingly larger proportional share of energy-related costs.
Model Structure and Documentation
20. Idaho Power's 2025 CCOS Methodology is implemented in two main
components. The Assign Module (AS Module) performs the functionalization and
classification stages by organizing Idaho jurisdictional costs (by FERC account) into
operating functions and classifying those costs as demand-, energy-, or customer-related.
The Functionalized Cost Module (FC Module) then performs the allocation and
summarization stages by applying the applicable allocation factors and compiling class
cost responsibility results.
21. A step-by-step description of the 2025 CCOS Methodology — including the
functional ization approach, classification conventions, and allocator definitions — is
provided in Attachment 2 (CCOS Process Guide). The underlying calculations, allocator
PETITION - 13

derivations, and model outputs supporting the method are provided in Attachments 4
(2025 CCOS Model) and Attachment 5 (2025 CCOS Allocation Factor Derivation
Workpapers), which are included to facilitate review and replication by Commission Staff
and interested parties.
V. ALTERNATIVE CCOS METHODOLOGIES AND RESULTS COMPARISON
22. Based on party positions in recent GRCs, as well as feedback received from
stakeholders in the February 13, 2026, meeting, Idaho Power presents four alternative
CCOS methodologies described below to support evaluation of methodological options
within the embedded cost-of-service framework. Each alternative is presented in a
common structure (functionalization, classification, and allocation) and is described in
terms of how it differs from the Company's 2025 CCOS Methodology.
23. Unless otherwise noted, each alternative retains the same underlying Idaho
jurisdictional cost inputs and the same general model structure. A step-by-step
description of each alternative, including where it diverges from the 2025 CCOS
Methodology in the CCOS flow, is provided in Attachment 2 (CCOS Process Guide).
Supporting Workpapers and outputs are provided in Attachments 6 - 13 (alternative
CCOS models and allocation factor derivation workpapers for each method).
EFAC Method (Production-Only Load-Factor Classification)
24. Overview. The Energy & Fixed Allocation Classification ("EFAC") method
modifies the classification step for certain Production-related cost categories by splitting
those costs between demand-related and energy-related components using the Idaho
jurisdictional load factor.
PETITION - 14

25. Rationale for inclusion. EFAC is included because the Commission has
previously approved the use of a load-factor-based split to classify certain Production
(Generation) and power supply cost categories between energy- and demand-related
components prior to the Company adopting the current "fixed vs. variable" classification
approach. EFAC provides a way to evaluate a previously vetted classification construct
alongside the 2025 CCOS Methodology within the same embedded CCOS framework.
26. Functionalization. EFAC does not change functional ization.
27. Classification. Under EFAC, applicable Production-related categories are
separated into: (i)a demand-related share equal to one minus the jurisdictional load factor
and (ii) an energy-related share equal to the jurisdictional load factor. Consistent with the
load-factor classification concept, the EFAC model also applies the same split to Public
Utility Regulatory Policy Act of 1978 ("PURPA") and purchased-power expenses recorded
in FERC Account 555. Fuel remains classified as energy-related and demand response
incentive payments remain classified as demand-related, reflecting their underlying
drivers. EFAC does not otherwise change customer-related classifications.
28. Allocation. EFAC does not introduce new allocation factors. The model
applies the existing demand- and energy-related allocations to the revised (split)
classification base; differences in class outcomes arise from the revised classification of
applicable Production costs.
AED-4CP Method (Production Demand Allocation Alternative)
29. Overview. The Average & Excess Demand ("AED") with four coincident
peaks ("AED-4CP") method modifies the allocation of demand-related Production costs
by using a single, unified annual allocator derived from each class's average demand and
excess demand, consistent with AED concepts described in the NARUC manual
PETITION - 15

framework.
30. Rationale for inclusion. AED-4CP is included because the Federal
Executive Agencies' witness described an AED-4CP allocator as an alternative for
allocating demand-related Production costs among classes and discussed its application
in the context of Case No. IPC-E-24-07. The method is presented here to allow a
comparison of the AED allocator approach to the current coincident-peak approach using
consistent inputs.
31. Functionalization. AED-4CP does not change functionalization.
32. Classification. AED-4CP does not change classification. Demand-,
energy-, and customer-related cost pools remain defined as the underlying method.
33. Allocation. Under AED-4CP, the model develops one annual capacity-
responsibility for each class by blending: (i) average demand (weighted by the system
load factor) and (ii) excess demand (the non-negative amount by which a class's June-
September 4CP demand exceeds its average demand, weighted by one minus the
system load factor). The resulting annual AED share is used as the Production demand
allocator (D10P), with seasonal components presented as proportional partitions of the
same annual allocator (D10BS and D10BNS).
Hourly-Informed Method (Production & Transmission Allocation)
34. Overview. The Hourly-Informed method modifies the classification and
allocation of bulk-power costs by relating Production and Transmission cost responsibility
to hourly system usage and resource output patterns, rather than relying on monthly
coincident-peak measures.
PETITION - 16

35. Rationale for inclusion. The Hourly-Informed method is included because
the settlement framework that established the single-issue CCOS docket contemplated
presentation of an hourly-informed class allocation of Production and Transmission
revenue requirement as part of the alternatives to be evaluated. The method is included
to facilitate evaluation of an hourly allocation approach alongside embedded peak-based
approaches using the same overall CCOS structure and filing package.
36. Functionalization. The Hourly-Informed method does not change
functional ization.
37. Classification. Under the Hourly-Informed method, Production is classified
by resource type (e.g., hydro, thermal baseload, thermal peaking, battery storage,
demand response, purchased power) rather than by demand/energy conceptual buckets.
Transmission remains within the Transmission function and is grouped for allocation as
Transmission Plant and Transmission-Direct (Accounts 350-359), with Transmission-
Direct items remaining directly assigned. Customer-related classifications are not
modified under this approach.
38. Allocation. The method converts annual Production and Transmission
Plant costs into hour-specific values and allocates those costs to classes based on each
class's hourly megawatt-hour ("MWh") usage. Conceptually: (i) annual costs are
organized by resource (Production) or plant grouping (Transmission), (ii) costs are
distributed across hours based on hourly output or served-energy patterns using either
weighted dispatch — where hourly output is multiplied by hourly prices — or simple hourly
dispatch when hourly prices do not apply, and (iii) each hour's cost is allocated to classes
in proportion to class hourly MWh, with hourly allocations summed to annual totals.
PETITION - 17

Transmission-Direct remains directly assigned and outside the pooled hourly allocation.
In practice, the Hourly-Informed method allocates Production and Transmission to
classes using hour-specific costs per MWh values applied to hourly MWh, which results
in a fully time-varying, usage-based assignment of bulk-power costs.
EFAC P&T Method (Production & Transmission Load-Factor Classification)
39. Overview. EFAC P&T extends a load-factor-based split to both Production
and Transmission Plant by classifying those bulk-power cost pools between demand-
related and energy-related components and then allocating each component using an
allocator aligned with its driver.
40. Rationale for inclusion. EFAC P&T is included in response to stakeholder
input that Transmission provides both energy and demand-related benefits and that the
model should support evaluation of alternative energy/demand splits for both Production
and Transmission, not Production alone. This variant is presented to support side-by-side
comparison of the Production-only EFAC and Production-and-Transmission EFAC under
the same framework.
41. Functionalization. EFAC P&T does not change functional ization.
42. Classification. Under EFAC P&T, applicable Production and Transmission
Plant categories are separated into: (i) a demand-related share equal to one minus the
jurisdictional load factor and (ii) an energy-related share equal to the jurisdictional load
factor. Fuel remains classified as energy-related and demand response incentive
payments remain classified as demand-related, reflecting their underlying drivers.
Transmission — Direct (Accounts 350-359) remains directly assigned and is not pooled
for classification. EFAC P&T does not otherwise change customer-related classifications.
PETITION - 18

43. Allocation. After the classification split, the demand-classified portion of
Transmission Plant continues to be allocated using the Company's D13 approach. The
energy-classified portion of Transmission Plant is allocated using an energy-based
allocator (E13) derived analogously to D13 but using served energy (MWh) rather than
coincident demand (kW). Differences relative to the 2025 CCOS Methodology method
arise from (i) the revised classification base and (ii) the use of an energy-based
transmission allocator for the energy-classified share of Transmission plant.
Summarized Results (Comparative Output Across Methods)
44. Idaho Power provides a comparison of class responsibility outcomes under
the 2025 CCOS Methodology and each alternative to facilitate review of how differing
classification and allocation approaches affect results across major customer classes.
45. For purposes of this Petition, the comparative presentation is streamlined
to focus on major customer classes and relative differences across methodologies. Two
complementary figures are provided: (i) a table showing the percent changes in allocated
cost-of-service revenue requirement by major customer class under the 2025 CCOS
Methodology and each alternative method (Figure 1), and (ii) a scatter plot illustrating the
range and variance of results across methodologies for each major customer class
(Figure 2).
46. The figures are intended to aid visualization and high-level comparison.
Complete model outputs, allocator derivations, and class-level results for each
methodology — including: (i) the 2025 CCOS Methodology, (ii) EFAC, (iii) AED-4CP, (iv)
Hourly-Informed, and (v) EFAC P&T — are provided in Attachment 4-13 (CCOS models
and allocation factor derivation workpapers), which contain the underlying calculations
supporting the summarized results presented in this Petition.
PETITION - 19

Figure 1. Percent Change in Allocated Cost-of-Service Revenue Requirement by
Customer Class and CCOS Method
Customer Class 2025 CCOS EFAC AED-4CP Hourly EFAC P&T
Uniform Tariff Schedules
Residential 14.42% 12.99% 12.49% 7.49% 12.07%
Small General 10.78% 11.20% 4.48% 11.19% 11.25°%
Large General(9S) (0.40%) 0.43% (8.85%) 2.71% 0.79%
Large General(P/T) (1.20%) 0.05% (11.72%) 7.31% 0.87%
Large Power 0.58°% 2.70% (12.25°%) 14.78% 4.35%
Irrigation 10.36% 10.78% 52.67°% 6.58% 10.85%
Total Uniform Tariff Schedules 8.43% 8.26% 9.18% 7.17% 8.12%
Special Contracts
Micron (0.72%) 1.75% (13.28%) 18.45% 3.91%
Simplot- Donn (6.91%) (2.81%) (17.67%) 21.21% 0.02%
DOE/I N L 3.84% 6.38% (16.64%) 26.93% 8.72%
Simplot-Caldwell (16.09%) (12.37%) (25.57%) 9.49% (9.33%)
Lamb Weston (13.75%) (10.12%) (23.22%) 5.51% (7.48%)
Total Special Contracts (8.26%) (5.39%) (20.73%) 12.79% (3.04%)
Total 7.48% 7.48% 7.48% 7.48% 7.48%
Figure 1 presents the percent change in allocated cost-of-service revenue requirement for the
major customer classes under the 2025 CCOS Methodology and four alternative methods
presented. 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 requirement increase reflected in the 2025 General Rate Case
Settlement Stipulation.
Notes:
(1) Percent values represent changes in allocated cost-of-service revenue requirement.
(2) Special contract customers shown are those included in the Company's CCOS comparison
analysis. Brisbie is excluded because it does not have test-year sales and produces
non-meaningful percent changes.
(3) The "Total" row is shown for reference only and does not represent a class-specific allocation.
PETITION - 20

Figure 2. Difference from 2025 CCOS Methodology by Customer Class
(Percentage Points)
Residential ♦ 4 ♦EFAC P&T
♦Hourly-Informed
Small General S AED-4CP
Large General (9S) 0 4♦ •EFAC
arge General (9P/T) M
Large Power N
Irrigation
Micron 0*
Simplot-Donn
DOE/INL 0*
Simplot-Caldwell
Lamb Weston
(25.00) (15.00) (5.00) 5.00 15.00 25.00 35.00 45.00
Difference vs. 2025 CCOS Method (Percentage Points)
Figure 2 shows, by customer class, the difference between each alternative CCOS method and
the 2025 CCOS Methodology. Values represent the percentage-point difference between the
alternative method and the baseline. A vertical reference line identifies the system-average
revenue requirement increase reflected in the 2025 General Rate Case settlement(7.48 percent).
Notes:
(1) Values shown are calculated as the alternative CCOS result minus the 2025 CCOS
Methodology result, expressed in percentage points.
(2) Positive values indicate a higher allocated revenue requirement relative to the 2025 CCOS
Methodology; negative values indicate a lower allocated revenue requirement.
(3) Customer classes shown correspond to those presented in Figure 1. Brisbie is excluded
because it does not have test-year sales and produces non-meaningful percent changes.
PETITION - 21

VI. NEW LARGE LOAD CONSIDERATIONS
47. As previously noted, in approving the Stipulation in the 2025 GRC the
Commission was supportive of the provision requiring the Company to initiate a single-
issue case addressing the CCOS methodology, which it noted would also provide a forum
for the Commission to review and determine the appropriate cost of service for new large-
load customers to help ensure that other customer classes are not adversely affected.
Consistent with that directive, Idaho Power provides the discussion below and New Large
Loads Memo (Attachment 3) to supply background information, summarize industry
practices, and facilitate a transparent record on NLL considerations in this docket.
48. Across the industry, sustained load growth driven by data centers, artificial
intelligence computing, advanced manufacturing, and electrification is arriving faster and
in larger, more concentrated increments than historical patterns. Stakeholders observe
that these step-change additions can increase firm capacity requirements, reshape daily
and seasonal peaks, and compress operating flexibility, raising questions about how cost
causation is reflected in class revenue responsibility when growth is non-homogeneous.
Why New Lar_pe Loads Are an Important Issue
49. An important issue for consideration in this case is that the operational
characteristics of some emerging loads may differ materially from traditional customer
classes, including higher load factors and reliability expectations that can affect system
flexibility and reserve margins. In combination with the magnitude and timing of step-
change additions, these characteristics can create planning and investment challenges
that differ from those associated with gradual, geographically diffuse load growth.
PETITION - 22

50. Another issue that has arisen in NLL discussions is the distinction between
customer-specific delivery facilities and broader system impacts. While some projects
require dedicated assets (e.g., new substations or radial delivery facilities), other
upgrades affect shared system-related investment, raising questions about how costs
should be attributed when large, concentrated loads drive incremental reinforcement on
shared infrastructure.
51. Finally, these important considerations are often accompanied by
forecasting variability and timing risk— e.g., multi-phase buildouts and evolving operating
profiles — which can complicate investment decisions relative to load commitments and
increase the importance of safeguards intended to protect other customers from timing,
credit, or default risk during multi-year ramps.
What Utilities Are Doing (Industry Approaches)
52. In response to these issues, Idaho Power, along with other utilities and
regulators across jurisdictions, are using a range of tools to manage cost-allocation and
risk associated with NLLs. For purposes of organizing the record, these approaches are
grouped into three broad categories: contractual commitments, direct assignment, and
growth-sensitive cost-of-service approaches.
53. Contractual commitments. Contract-based provisions are used to
improve planning certainty and reduce stranded-cost risk for large loads. These
provisions commonly include fixed contract demand schedules and minimum billing
demand ("take-or-pay") structures, as well as credit support and termination/make-whole
protections intended to manage default and timing risks.
PETITION - 23

54. Direct assignment. Direct assignment approaches focus on assigning
local interconnection infrastructure costs such as transmission, substation, and
distribution costs to the customer(s) driving the investment (often implemented through a
Contribution in Aid of Construction ("CIAC") or other upfront funding mechanisms), with
the stated objective of keeping customer-specific facilities outside embedded allocators.
55. Growth-sensitive cost-of-service approaches. Some jurisdictions are
examining frameworks that distinguish growth-driven portions of costs from non-growth
portions, while retaining traditional allocators for embedded (non-growth) costs. For
example, Arizona Public Service proposed a growth-based overlay that applies only to
the growth-driven increment of certain production-related costs, while retaining traditional
allocators for non-growth-driven investment. In addition, Portland General Electric's
proposed Peak Growth Modifier("PGM") approach applies only to growth-related portions
of Transmission and Production investment, with non-growth portions remaining allocated
using standard coincident-peak allocators. These approaches are both discussed in more
detail in Attachment 3.
Idaho Power's Current Approach to New Larpe Loads
56. Idaho Power classifies new service requests of 1 megawatt ("MW") or
greater as large-load inquiries and conducts engineering studies to determine whether
existing facilities can accommodate service at the required voltage and reliability levels.
Where upgrades are required and the customer elects to proceed, the Company uses
Construction Agreements (and, where appropriate, Procurement Agreements) to define
scope, align long-lead procurement, and require up-front customer funding (CIAC) for
customer-specific delivery facilities so those costs are not included in rate base.
PETITION - 24

57. For prospective larger loads, Idaho Power further differentiates the service
pathway. Under Schedule 19, if a customer's aggregate power requirements at the same
premises exceeds 20 MW, the customer is ineligible for service under that schedule and
is required to make special contract arrangements with the Company. These
Commission-approved Energy Services Agreements ("ESA") provide a mechanism to
tailor service and include provisions intended to protect the Company and other
customers, and for ratemaking purposes each customer with an ESA is treated as a
separate class with conditions and contract terms affecting rates.
58. As described in the NLL materials, ESAs typically incorporate contract
demand schedules, minimum billing demand (take-or-pay) provisions, credit support
requirements, notice/resizing limits, and termination/make-whole protections to clarify
planning quantities and mitigate timing and default risks for other customers during multi-
year project ramps.
Future Considerations in ESA and GRC Proceedings
59. Should NLLs become a more prominent feature on the system, future
proceedings may increasingly distinguish between (i) front-end safeguards that govern
how large loads are integrated and how risks are managed at the time service is initiated,
and (ii) cost allocation questions associated with investments and revenues associated
with each respective NLL.
60. Contractual commitments (ESA terms) as a primary safeguard tool.
Idaho Power's current framework relies on Commission-approved ESAs for customers
above the 20 MW threshold, which may incorporate provisions such as take-or-pay
minimum billing, credit support, and termination/make-whole structures intended to
mitigate stranded-cost and default risk for other customers as appropriate depending on
PETITION - 25

the customer. In that context, future ESA reviews may provide a forum for the Commission
and parties to consider, on a fact-specific basis, whether the suite of safeguards in the
given ESA appropriately addresses the size, ramp profile, and timing risks presented by
the project at issue.
61. Direct assignment and the delivery/system boundary. The Company's
current approach requires CIAC and related direct-funding constructs for customer-
specific local interconnection infrastructure, so those costs are not placed in rate base.
As future prospective NLL projects are evaluated, future records may further examine
where the boundary is drawn between customer-specific facilities and networked assets,
and whether direct assignment tools remain appropriately targeted to facilities that are
dedicated to a specific project.
62. Growth-sensitive CCOS approaches as a future GRC lens. Growth-
sensitive approaches provide a framework that separates growth-driven portions of costs
from non-growth portions while retaining traditional allocators for embedded costs. As
concentrated growth continues, future CRCs could include additional evidence and
analysis evaluating whether such lenses are informative for distinguishing incremental
cost drivers from embedded system costs when assessing class revenue responsibility.
63. Taken together, these considerations do not dictate any particular outcome.
Rather, they provide a structured way to organize future records around: (1) ESA
safeguards that shape planning certainty and risk allocation at the outset; (2) direct
assignment of customer-specific delivery infrastructure; and (3) the manner in which
growth-related costs are reflected in embedded cost allocation once those costs are
included in test-year data in future general rate cases.
PETITION - 26

VII. STAKEHOLDER COMMENTS AND COMPANY RESPONSES
64. Stakeholders provided input during the February 13 workshop and through
written submissions provided afterward. The written submissions are provided in
Attachment 1 (Stakeholder Comments).
65. For purposes of summarizing the pre-filing input, the comments reflected
several recurring themes related to transparency, methodological scope, and the
treatment of certain cost categories. The summary below is intended to describe themes
raised by commenters and to identify how the Company's filing package is structured to
support review; it is not intended to characterize a consensus view or resolve disputed
methodological questions.
66. Transparency, documentation, and comparability across methods.
Several commenters requested that the docket record support clearer comparison across
CCOS approaches, including improved documentation and access to supporting
calculations so that parties can trace allocator derivations and understand how
assumptions affect outcomes.
Company Response: To support this objective, the Company is providing a step-
by-step CCOS Process Guide (Attachment 2) and fully functional CCOS workpapers
(Attachments 4 - 13) containing allocator derivations and comparative outputs for the
methods presented.
67. Production and Transmission treatment (including demand vs. energy
considerations). Some commenters raised questions about whether Production and
Transmission are appropriately represented when treated solely through demand- or
peak-oriented constructs and suggested evaluating approaches that recognize both
PETITION - 27

demand- and energy-related service dimensions. For example, Commission Staff's pre-
filing feedback stated that Transmission provides both demand- and energy-related
benefits and asked that the Company provide an evaluation of alternative demand/energy
allocation for both Production and Transmission.
Company Response: In response to these themes, the filing presents multiple
methods that vary classification and/or allocation treatment across Production and
Transmission, with supporting documentation in Attachment 2 and associated CCOS
models in Attachment 6 - 13.
68. Allocation granularity (including hourly-informed methods). Some
commenters requested inclusion of at least one approach that uses more granular data
(including hourly data) to evaluate how class responsibility changes when allocations are
tied to hour-by-hour usage patterns. Both CEO and NWEC specifically reference data
granularity as a reason to include or evaluate an hourly-informed approach rather than
reliance on estimates or averages.
Company Response: Consistent with the settlement framework underlying this
docket, the filing includes an Hourly-Informed CCOS approach alongside other
embedded, peak-based approaches to facilitate comparative evaluation using a
consistent filing package.
69. AED methodology and implementation details. Some commenters
supported evaluation of an AED approach but emphasized that the method should follow
accepted AED design and be applied as a single set of AED allocation factors across
demand-related Production cost elements (rather than a segmented approach). The
Federal Executive Agencies' pre-filing feedback describes this point and references the
PETITION - 28

NARUC manual's AED design.
Company Response: The filing includes an AED-4CP alternative and provides
supporting allocator derivations and model outputs in the workpapers, so parties can
evaluate the implementation details and test sensitivities as appropriate.
70. Purchased power classification. Some commenters questioned whether
treating purchased power as solely energy-related fully reflects the attributes of many
purchased power arrangements and asked that the Company evaluate alternative
classification approaches.
Company Response: The EFAC methods included in this filing evaluate an
alternative purchased power treatment for FERC Account 555 by classifying expenses
between demand- and energy-related. The filing package is structured to provide
transparent allocator derivations and comparative outputs across multiple methods, and
the stakeholder submissions in Attachment 1 provide the detailed perspectives for the
Commission's consideration as the docket proceeds.
71. New Large Loads and non-homogenous growth. Some commenters
highlighted that rapid or concentrated load growth may raise additional questions about
cost causation and requested background information on approaches used in other
jurisdictions. Commission Staff's pre-filing feedback also discussed non-homogenous
load growth as a motivating issue for evaluation in this docket.
Company Response: The filing includes New Large Loads Memo (Attachment 3)
to provide background and summarize select emerging industry approaches, alongside
the CCOS methods and workpapers included for evaluation.
PETITION - 29

72. Process and record development. Two commenters — CEO and NWEC
— offered process suggestions including consideration of a Staff-authored report as a
potential means to frame options for Commission review. CEO also raised concerns
about the Company presenting things in a biased fashion and NWEC asserting that a
Staff-authored report would provide a fair method to develop a record for the Commission.
Company Response: Idaho Power is not requesting a Staff-authored report as part
of the initial procedural schedule and instead requests that the Commission set (or direct
Staff and parties to confer on) a procedural schedule that supports development of an
evidentiary record through discovery and filed testimony or comments (including reply
opportunities as appropriate), with a technical hearing only if the Commission determines
modified procedure is not appropriate.
73. Taken together, the stakeholder submissions in Attachment 1 and the
analytical materials provided in Attachments 2 - 13 are intended to provide transparency,
enable comparative review, and support ability for interested parties to examine and test
the methodologies presented. Idaho Power recognizes that stakeholders hold differing
views about preferred methodologies, and the record developed in this docket will enable
to the Commission to consider and determine the methodological and policy questions
raised by the various stakeholders.
VIII. COMMUNICATIONS AND SERVICE OF PLEADINGS
74. Communications and service of pleadings, exhibits, orders, and other
documents relating to this proceeding should be served on the following:
PETITION - 30

Megan Goicoechea Allen Timothy Tatum
Lisa Lance Grant T. Anderson
IPC Dockets 1221 West Idaho Street (83702)
1221 West Idaho Street (83702) P.O. Box 70
P.O. Box 70 Boise, ID 83707
Boise, ID 83707 ttatum(c)_idahopower.com
mgoicoecheaallen(a-),idahopower.com ganderson(a-),idahopower.com
IlanceCc)_idahopower.com
dockets idaho power.com
IX. CONCLUSION AND REQUEST FOR RELIEF
As more fully described herein and in compliance with Order No. 36892, Idaho
Power submits this Petition to initiate a single-issue proceeding where CCOS
methodology can be examined and evaluated by the Commission after development of a
complete and targeted evidentiary record. To that end, the Company respectfully requests
the Commission: (1) issue a Notice of Petition and Notice of Intervention Deadline to
inform interested persons that the Company has filed the Petition and set deadlines by
which interested persons may intervene; and (2) direct Staff to work with parties following
the intervention period to establish a procedural schedule providing opportunities for the
parties to exchange proposals, respond to other party positions, and offer
recommendations, which will facilitate the development of a robust record that will support
the Commission's review and consideration of the various CCOS methodological
approaches and ultimately enable it to provide guidance to the Company regarding CCOS
methodology for future CCOS studies and future general rate case filings in its disposition
of this docket.
PETITION - 31

Dated at Boise, Idaho, this 31 st day of March 2026.
�-/�?I c�ec ea
MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company
PETITION - 32

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 31 st day of March 2026, 1 served a true and correct
copy of IDAHO POWER COMPANY'S PETITION upon the following named parties by
the method indicated below, and addressed to the following:
Commission Staff Hand Delivered
Deputy Attorney General U.S. Mail
Idaho Public Utilities Commission Overnight Mail
11331 W. Chinden Blvd., Bldg No. 8 FAX
Suite 201-A (83714) FTP Site
PO Box 83720 X Email
Boise, ID 83720-0074
,eta01
Stacy Gust, Regulatory Administrative
Assistant
PETITION - 33

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
ATTACHMENT 1

Attachment 1 - Stakeholder Comments
Memorandum
To: Idaho Power Company
From: Staff of the Idaho Public Utilities Commission
Date: February 27, 2026
Subject: Feedback on Idaho Power's February 13, 2026, Class Cost of Service Meeting
Backl4round
Order No. 36892 approved the Proposed Settlement in Case No. IPC-E-25-16. The
Settlement included an agreement to initiate a single-issue case related to class cost-of-service
("CCOS")methodology for the Commission's consideration in advance of the filing a Notice of
Intent for its next general rate case, but in no event later than end of the first quarter of 2026.
Prior to filing that case, Idaho Power agreed to meet with Staff and other interested Parties to
identify alternative CCOS studies that will be presented by the Company for Commission
consideration.
On February 13, 2026, Idaho Power met with Staff and other interested Parties to discuss
the proposed CCOS single-issue case scope and process. As a result of the meeting, Idaho Power
requested feedback on the proposed process and any additional CCOS methods for the Company
to consider.
Principles Important to Class Allocation
Staff believes there are three primary principles specific to CCOS methods that should
guide the development and evaluation of the proposed CCOS models and methods in the
upcoming case. These principles include: (1) Cost Causation, (2) Cost Follows Benefit, and(3)
Avoidance of Undue Discrimination.
The development of CCOS methods in the upcoming case will be used to determine the
baseline of how much cost each customer class is allocated primarily based on the above three
principles. Because Staff believes the scope of the CCOS docket is focused on CCOS methods,
other principles such as Promotion of Utility Efficiency and Gradualism, are out of scope for this
case. Efficiency and Gradualism are considerations for rate design and setting of final rates that
use the baselines as a result of the different CCOS methods that will be investigated.

However, Staff believes there are other regulatory standards and principles that should
also be considered, which relate to the information and data used in a class cost of service
including: (1) the Know and Measurable Standard, (2)the Used and Useful Standard, and(3)the
Matching Principle.
Primary Principles
Cost Causation
Cost Causation is the primary and foundational principle that needs to be followed when
allocating the Company's revenue requirement to the different customer classes receiving
service. It simply means that customers should pay for the Company's prudently incurred costs
that they cause to the system. From a customer class perspective, the class that creates the need
for the Company to invest in infrastructure or to incur expenses should be allocated the cost.
Cost Follows Benefits
Costs should be allocated based on the amount of benefits each class realizes as a result
of an investment or expense. This principle is subtly different than the Cost Causation in that an
investment that a Company makes primarily triggered by a single class may benefit other classes
once the investment is made or the expense is incurred, and as such, those classes that benefit
should bear their share of the benefits received.
Avoidance of Undue Discrimination
Allocation of costs and resulting rates must be allocated in a fair manner to ensure that
rates are fair,just, and reasonable and are not unduly preferential to a customer or customer
class. This occurs if certain customers or customer classes have different rates or services that
are not justified based on legitimate cost-based factors and do not reflect the actual cost to serve
them causing illegal cross-subsidization.
Secondary Principles and Standards
Known and Measurable Standard
Any adjustments to the data and information to the historical test year used to determine a
customer class allocation should be verifiable and non-speculative financial and operational data.

Any adjustments should have a high degree of certainty that the change will occur and the impact
is quantifiable.
Used and Useful Standard
This is a standard that ensures that only infrastructure and assets that are able to provide
service and benefits to customers are included in rate base.
MatchingPrinciple
rinciple
From a regulatory perspective, this principle is focused on matching costs that are
prudently incurred, as well as used and useful, during the specific period ratepayers receive
service and that the Company is receiving revenues for those costs.
Presentation of Multiple CCOS Methods
Staff supports the Company providing multiple CCOS methods in its application for the
upcoming cost of service docket. There are several different ways to allocate cost to the
Company's classes that are valid based on the principles stated above, yet each of these methods
can favor some classes at the expense of others. By presenting several different methods,
intervening parties and the Commission can better understand how each method allocates cost
differently based on consumption patterns of the different customer classes and how the
principles used in cost allocation are weighed.
Staff generally believes that the three methods presented in its February 13, 2026,
meeting will provide a sufficient basis for comparison of different CCOS methods. However,
Staff believes that multiple variations of these core methods should be investigated and the
Company should be prepared to investigate their effect during the course of the case.
Benefits Outside of Peak Periods
Staff believes that the classification of some Transmission and Generation as only
demand-related does not appropriately value the benefits those resources provide to customers
outside of peak periods. Staff generally agrees with the development of the Energy and Fixed
Allocation Classification(`EFAC")method, which Staff believes will help address the issue, by
"split[ing] the production costs into energy-related and demand-related components using a load-

factor-based approach." Company Class Cost-of-Service presentation, February 13, 2026.
However, Staff has two variations that the Company should provide in its EFAC model.
First, Staff would like the Company to evaluate splitting both Production and
Transmission functions into energy-related and demand-related components, not just the
Production function. Staff believes that Transmission provides both energy and demand-related
benefits to the Company's customers.
Second, Staff would like the Company to develop its models to easily change the
proportion of energy and demand-related components individually for Transmission and
Production so that the sensitivity of those proportions on resulting allocations can be evaluated.
This will allow intervening parties to have the ability to propose different energy and demand-
related proportions using a basis other than system load factor.
Non-Homogenous Customer Class Load Growth
Staff believes the scope of cost causation for Demand-Classified and Energy-Classified
Transmission and Generation needs to expand from traditional average embedded cost allocation
methodologies currently used by Idaho electric utilities. This is due to new large loads or
abnormally large growth in existing customer classes driving in resources that have on average,
higher capacity cost($/MW) and energy cost ($/MWh) than resources serving customers with
normal levels of growth.
Staff preferentially supports the inclusion of the two growth-sensitive CCOS methods
presented in the Company's February 13, 2026,presentation for evaluation in the upcoming case.
Staff also supports the evaluation of its own proposal to adjust allocation of demand-classified
generation and transmission cost to customer classes based on the amount of transmission and
generation rate base that occurs relative to the load-weighted average service date of current
customers in each class included as Attachment A to this memo.
Although Staff agrees that the Company's other two methods, Direct Assignment and
Contractual Commitments, are other ways to isolate the incremental higher cost of high load
growth customers, Staff believes that the latter is already being done to a great extent through
new large load special contracts and the former is problematic given Staff's experience with
subscription methods investigated in developing PacifiCorp's Multi-State Protocol used for
jurisdictional allocation. Staff also believes direct assignment of generation and transmission

resources to specific customer classes that provide benefits to all customers once integrated into
the system is problematic from a Cost Follows Benefit perspective.

6r�Cost of Service Study
Pro osal s )
Idaho Power Co. Class Cost of Service Meeting
Staff -- February 13, 2026
Y,I v
USES

Problem Statements
. _
1 . Benefits outside of peak-periods
• The classification of some Transmission and Generation as only
demand-related does not appropriately value the benefits those
resources provide to customers outside of peak-periods.
2. Non-homogenous customer-class load growth
• The scope of cost causation for Demand-Classified and Energy-Classified
Transmission and Generation needs to expand due to new large loads or
abnormally large growth in existing customer classes driving in resources
that have, on the average, higher capacity cost ($/MW) and Energy cost
($/MWh) than resources serving customers with normal levels of growth.

Benefits Outside of Peak Periods
Proposal - Energy and Demand Classification of T&G
• Generation and Transmission should be classified based on
proportion of benefits of energy vs. capacity.
• COSS proposals should allow sensitivity analysis for varying
proportions to understand the effect.
cItI.
0/2 ,0

Problem Statements
1 . Benefits outside of peak-periods
• The classification of some Transmission and Generation as only demand-
related does not appropriately value the benefits those resources provide
to customers outside of peak-periods.
2. Non-homogenous customer-class load growth
• The scope of cost causation for Demand-Classified and Energy-
Classified Transmission and Generation needs to expand due to new
Large loads or abnormally large growth in existing customer classes
driving in resources that have, on the average, higher capacity cost
($/MW) and Energy cost ($/MWh) than resources serving customers
with normal levels of growth.

Non - Homogenous Customer-Class Load Growth
Proposal — Allocation of T&G Demand-Classified Costs
Adjust allocation of demand-classified generation and transmission cost to
customer classes based on amount of rate base that occurs relative to the
load-weighted average service date of current customers in each class.
T&G Ratebase
($-Actual)
ys�
_ - - - - - - Today
t/7
I �s
Load Wtd
CD Cn U) Avg. Service Date
N Cn Cn
D 00 0

Non - Homogenous Customer-Class Load Growth
Proposal — Allocation of T&G Demand-Classified Costs
Hypothetical Example of Load-Weighted Service Date for a Single Class
Effect of adding new large customer to class:
Customer Age(yrs) Ld(MW) Age x Load �/ Customer Age(yrs) Ld MW Age x Load
1 12 5 60 ` 1 12 5 60
2 8 8 64 v 2 8 8 64
3 7 4 28 /0tz
3 7 4 28
4 3 6 18 Q� 4 3 6 18
Total Class 20 170 5 1 18 18
Total Classy-h 38 188
Ld. Wtd. Age = 170/20 = 8.5 yrs �J ..t
Ld. Wtd Service Date = 2026 - 8.5 = 2018 Ld. Wtd. Age = 188/38 = 4.9 yrs
Ld. Wtd Service Date = 2026 -4.9 = 2021

Non - Homogenous Customer-Class Load Growth
Proposal — Allocation of T&G Demand-Classified Costs
• Hypothetical Allocation Example
%_/ /'I
%of Current RB
Class A 62.5% Op
Class B 75% Ld Share @Peak Dem-Class. Cost RB Allocator WTD Alloc. Alloc. % Final Alloc.
T&G Ratebase Class C 100% ` o
($-Actual) Class A 25% $0.5M 62.5% $0.313M 20.3/o $0.41 M
Class B 55% $1.1 M 75% $0.825M 53.6% $1.07M
Today Class C 20% $0.4M 100% $0.4M 26% $0.52M
$1.6M
Total 1000 / OM $1.538M 100% $2.OM
$1.2M
$1.0M , 0&0
—� Load Wtd s
n n n Avg. Service Date
S v v
W W Cn
Cn CD Cn
D co 0

Non - Homogenous Customer-Class Load Growth
Proposal — Allocation T&G Demand-Classified Costs
• Benefits of Proposal
. .
• Aligns customer class allocation of demand-classified T&G cost based on
cost causation principles - cost causer pays the cost they cause to the
system.
• Leverages current cost of service allocation method(s).
• Scalable overtime. qt/01-11
• Preserves generational equity at the customer class level.
• The method is applied to all classes.
�s
�s

Non - Homogenous Customer-Class Load Growth
Proposal — Allocation of T&G Demand-Classified Costs
• Definition of Transmission and Generation Rate Base.
• Includes all Company investment of resources required to increase
system capacity to meet load.
' ' N
• Transmission Rate Base: Includes all transmission investment needed to bring
market purchases into the system and needed to support Company generation
(interconnection + system upgrades)
• Generation Rate Base: Includes all investment in Company generation and energy
storage. ' —
• Rate Base amounts for specific plant adjusted for capitalized
maintenance and upgrades. ue0

Non - Homogenous Customer-Class Load Growth
Proposal — Allocation T&G Demand-Classified Costs
• Load-weighted average service date depends on number of customers in
each class and variability of load between customers.
• Classes with large number of customers (residential and small commercial)
• Service date based on service point creation date of current customers.
• Assume load for each customer is relatively homogeneous, based on average load per customer
within the class. - %I IV Iff —
• Classes with fewer customers with varying loads per service point (large general, large
power, irrigation)
• A customer is synonymous with a service point and service date is based on service point creation
date.
• Load for each service point is based on each service point historical peak (or capacity of
interconnection)
Iv
• Special Contract .q�0
• Service date defined by the end date of the load ramp for each customer. S
• Load based on contracted load at end of load ramp (or capacity of interconnection)

Non - Homogenous Customer-Class Load Growth
Proposals — Allocation of Energy-Classified Costs
• Becomes important if classification of T&G plant is split between
energy and demand .
• First Proposal JAm -
• All loads under 20 MW allocated based on an equal cents/kWh.
• All loads over 20 MW based on marginal cost of energy.
• Second proposal W C*Yb4l'
• Proportion of T&G plant allocated to energy is adjusted using same Rate Base Load-
Weighted Service Date adjustment as Demand-Classified T&G.
�U
s�
s

.�•►
February 27, 2026
To: Idaho Power
Reference: CCOS Docket
Subject: Initial Input of Clean Energy Opportunities for Idaho
Clean Energy Opportunities for Idaho (CEO) appreciates the work by Idaho Power to present alternatives
and to welcome input into the upcoming CCOS docket. Our pre-filing input is provided below.
Contents
Intro:New conditions call for multi-CCOS in future GRCs...............................................................................1
1. Inclusion of an Hourly CCOS for Generation and Transmission........................................................2
2. Modifications to EFAC&AED: Transmission * 100%Demand..........................................................3
3. Peakers should not be allocated based on 4 Summer Peaks..............................................................4
4. AED method should calculate Irrigator average for summer season.............................................4
5. Proposed EFAC method should apply to infrastructure, not fuel or purchased power.............5
6. Refer to EFAC by a name that does not include "Fixed"........................................................................6
7. Docket should delineate issues and regulatory choices for serving NLL........................................6
8. Both fairness and the appearance of fairness matter..........................................................................7
Summaryof Requests.................................................................................................................................................8
Intro: New conditions call for multi-CCOS in future GRCs
Transformative changes in the industry call for improvements to CCOS, yet the regulatory process values
gradualism. To better navigate a period of adaptation, we envision this docket should enable GRC's for the
foreseeable future to present multiple approaches to CCOS. This intro highlights some of those changes
and speaks to why a singular CCOS cannot adequately inform GRC's over the coming years.
Massive changes have transformed the electric industry since the 1992 NARUC manual issued. Such
changes undermine the assumptions upon which the 1992 accounting methods were based. For example:
• Shift to Non-Fuel Generation. We have a dramatically different fleet of generation resources. In 1990,
generation in the US was 88% steam-fired boilers, while it is approaching 50% fuel-free generation in
IPC's portfolio today. The Company's goal of 100% clean implies a transition to no fuel costs. Putting
fuel costs into energy and capital costs into demand is no longer an adequate proxy for reality.
• Transmission is used differently. It is no longer limited to high voltage lines for accessing remote
generation sites and efficiently distributing power across the service territory. The development of
organized wholesale markets and opportunities to lower energy costs via transactions across utility
service territories has changed how customers benefit from transmission resources.
• Capacity is time sensitive. New fuel-free generation such as solar makes traditional system peak
hourly load no longer an accurate reflection of peak summer capacity requirements that drive the need
for incremental resources.
1

.�...
• Generation Dispatch changes. Region-wide resource dispatch systems, such as EDAM and EIM,
mean generation is dispatched based on regional load characteristics and not just the historic within the
service territory conditions. The use of BESS resources as reserves and for price arbitrage further
complicates the split of generating assets into "baseload" and "peak" groups.
• Peakers #f(4CP). Market conditions mean that IPC "peakers" dispatch across times of day and months
of the year, not just during peak hours in the 4CP summer months, further muddying the traditional
12CP/4CP cost allocation regime.
• Transformational Growth. The addition of a new type of enormous "megaloads" forces consideration
of future incremental costs and not just historic cost patterns to ensure that fairness is maintained and
that cost causers pay for the costs they cause.
• Data Granularity. We have more accurate data than was available when usage information was
collected by monthly meter readings. We can now observe how individual customer classes benefit
from the use of generation and transmission resources across seasonal and diurnal cycles rather than
rely on allocating cost data based on monthly aggregation of customer consumption data.
Multi-CCOS are needed: Legacy and New
We envision that this docket should enable the next GRC and GRC's for the foreseeable future to present,
at minimum, a CCOS representative of 1) a Legacy approach and 2) an hourly approach. Given that any
CCOS method involves not only math but also subjective choices related to what is fair and reasonable,
different approaches are needed in order to -
• Ensure that the implications of certain choices are understood as the Commission and parties
navigate this period of adaptation
• Allow for continued vetting of any new approach
• Allow for gradualism as improvements to CCOS are refined
In its February kick-off presentation, Idaho Power proposed two alternatives to CCOS which are both
included in the 1992 NARUC Manual and which we are referring to as "Legacy" approaches: one based on
Load Factor (which the Company has previous used') and one based on Average & Excess demand. While
CEO does not view legacy monthly methods as the most accurate for today's environment, we
acknowledge the value of including a legacy CCOS methodology for comparison in upcoming GRC's, and
thus support the endeavor to consider improvements, such as choices related to classification. In addition to
deliberating legacy methods, we believe it essential that this docket lead to new approaches to CCOS —
such as hourly—to inform upcoming GRC.
The remainder of this document speaks to specific requests related to the CCOS docket filing.
1. Inclusion of an Hourly CCOS for Generation and Transmission
CEO appreciates and supports the inclusion of an Hourly informed CCOS as proposed by the Company in
its February kick-off meeting. At a more detailed level, we also ask that the Hourly CCOS address changes
' E.g., IPC-E-11-08 Larkin Direct, pl8:19-25: `In the class cost-of-service study all steam and hydro production plant
has been classified on a demand and energy basis using the methodology preferred by the Commission in prior
general rate proceedings. The energy portion of the steam and hydro production investment has been determined by
use of the Idaho jurisdictional load factor of 53.88 percent."
2

Ada-A.
to Transmission functionalization and the allocation of the financing costs of Company-owned G&T
resources as described below.
1.1 Transmission Sub-Functionalization: CEO requests that the Company include in its analyses a sub-
functionalization of transmission assets to break out the substation equipment, towers and conductors
needed to interconnect separate production resources to the larger within service territory high voltage bulk
transmission system. Costs related to those subgroupings should be allocated directly to their
corresponding production assets. CEO requests that such sub-functionalization include:
a) Transmission assets used to connect power from the Hells Canyon Complex to the Boise Bench
substation be charged to Company-owned Hydro generation,
b) All assets connecting north and west of the service territory facilitating access to Mid-C as well as
any costs associated with the use of Rocky Mountain Power resources to access up to 20OMW from
southwest markets be charged to market purchases.
c) Connections east of American Falls be allocated to Jim Bridger and
d) The north flow rights on the 345kV line running from Valmy to Midpoint be allocated to Valmy and
the solar farms connected to it.
e) Remaining transmission costs be allocated across all hours based on the MW load in each hour.
1.2 Financing Costs: Financing costs are implicitly included in the price of long-term purchased power,
which the hourly method then allocates by hour. Thus, the hourly method is more accurate if the cost of
capital for company-owned G&T resources are also included in their respective G&T costs before allocation
to customers classes on an hourly basis.
2. Modifications to EFAC & AED: Transmission # 100% Demand
The Company proposed that the EFAC and AED methodologies to be included in this docket should apply
to the classification of Generation and not to Transmission. CEO's position is that no methodology in the
CCOS docket should choose to classify Transmission infrastructure as 100% associated with serving peak
demand capacity. The EFAC and AED methodologies should apply to the classification of Production AND
Transmission infrastructure costs.
The Company's IRP describes how transmission enables the Company to lower energy costs, e.g., by
selling power when cost effective to do so and by accessing markets which provide low-cost energy
resources. IRPAC discussions included mention of low-cost energy expected in 2031 as projects related to
renewable energy goals in other states would export low-cost excess power. In the Micron docket (IPC-E-
24-44), we heard the Company testify that transmission costs were not driven entirely by capacity needs.
Customers who benefit from the lower energy costs enabled by transmission should share fairly in the cost
of the infrastructure that enables those low energy costs.
A Downside to Unfairness: A choice to classify Transmission as 100% Demand has the impact of
burdening small customers with a higher allocation of Transmission costs while flat-load customers,
including new large loads, may benefit from lower energy costs enabled by Transmission. The public will
increasingly pay attention to rising energy costs and is concerned for fairness. Yet public concern doesn't
typically manifest as engagement in the wonky details of cost classification. A perception of unfairness over
who is paying for transmission could elevate pushback against transmission projects, an outcome that
neither we nor the Company wants to see.
3

Clean Energy Opportunities for Idaho
3. Peakers should not be allocated based on 4 Summer Peaks
Empirical data demonstrates that 4 summer coincident peaks are not an accurate indicator of how pecker
plants are used and useful, as seen in the figure below which shows the MWh generated by peaker
resources across 365 days of the year. If monthly summer CP were an accurate allocator, one might expect
to see needle peaks during those times. Instead, we see peakers used often in summer &winter and
seldom during certain fall and spring months.
Peaker plants provide benefits outside of 4 monthly peaks
MWh across 365 days, 2023, for Danskin, Bennett, & Salmon diesel
12000
10000
8000
6000
400
20r
1-oct 1-Nov
-200i_
Shaded area =Summer months
♦= Days within which monthly peak occurred
An hourly method addresses the actual usage of Peaker resources. For the Legacy/ monthly methods
presented in this docket, CEO assumes that the methodologies used to classify infrastructure as Energy or
Demand (e.g., load factor or AED) would also be applied to peakers as a Production resource.
4. AED method should calculate Irrigator average for summer season
CEO asks the Company to include an AED scenario where the Irrigation class load average demand is
calculated based on the class energy demand during the four Summer months rather than all 12 months in
recognition of the fact that the class uses power largely on a seasonal rather than year-round basis.
An annual average does not accurately reflect how Schedule 24 customers
use the system (2023 data)
1000.0
(A 800.0
f 600.0
c
-� 400.0
J 200.0
0.0 (� Lo ^, F N V 2(�N M L^ n 00 p�� V � w F2 F N V 2 2 O N � QN1 .M-1 q w 1 O N n c') A w
N V w Co CD
N V n a--L U) Lo
.--� .--� .--L .-+ .--L N N N N N co M M M V V V V V Lo M m m Lo w w w W h r- r- n n 00 0o co
Hour of the year
4

jp Clean Energy Opportunities for Idaho
5. Proposed EFAC method should apply to infrastructure, not fuel or
purchased power.
The Company proposes that EFAC "Classifies production-related costs into demand and energy
components using a load-factor-based approach.112 We believe the spirit of the load factor allocator is to
recognize that infrastructure may serve both capacity and energy needs. We particularly do not believe that
a load factor allocator should apply to purchased power. We expand on why this matters below.
The Company's resource plan calls for an increasing reliance on purchased power, including market
transactions and long-term purchases of renewables. In 2024, the Company purchased 30% of its energy
(per its annual report). To illustrate the scale of growth, we roughly estimate from this chart (presented to
IRPAC) that the Company is on a path to source about half of its energy from purchased power by 2031:
Draft Preferred Portfolio: Sources of R,
Energy
Labels added by CEO. Note Annual Energy by Resource Type(GWh)
growing role of purchased
power by 2031...
M000SAW
■
15.00D ■
10.000 Mark.
s.000 ■ H�ro
0 _
2026 2027 2029 2029 20)0 201 2032 2033 204 Ms 2036 20P 2038 2039 2M0 2M1 2041 2M3 2091 201S
&,000
•»yero •ra,n.x •<N G» %E S Sow •WM WE •Mdoe. •aha
One of CEO's ultimate interests is long-term affordability, which is impacted by price signals, which may be
informed by CCOS. The cost per kWh of purchased power can be particularly time-varying. Access to
markets may offer exceptionally low-cost power during certain hours and high-cost power during other
hours. Why not allocate actual costs of purchased power by hour to customer classes based on their actual
share of energy consumption by hour? There is less need for a theoretical estimate of who benefited from
purchased power costs when the data is available, and the resulting CCOS would more accurately inform
the cost per hour to serve load.
CEO has interest in pursuing how, if a load factor is used to classify certain costs, the method may be
combined with an hourly treatment of purchased power.
2 IPC February Kick Off Slides, p12.
5

1P Clean Energy Opportunities for Idaho
6. Refer to EFAC by a name that does not include "Fixed"
The Company has proposed the name "Energy & Fixed Allocation Classification" or EFAC, and describes a
key difference from current method is "EFAC classifies production costs using energy vs. demand drivers,
not fixed vs. variable categories".3 We find the use of"Fixed" in the name is confusing when a key
difference is that the method does not use "fixed" to classify costs. Incorporating the term "Load Factor" may
be appropriate. We do appreciate the underlying premise that fixed cost resources may be used for both
energy and demand.
7. Docket should delineate issues and regulatory choices for serving NLL
First, types of"Growth" could be put into two buckets: Incremental and Transformational. Some
stakeholders may raise issues regarding the degree to which variations between customer class
incremental growth rates should be considered in ratemaking. CEO suggests that we not conflate those
issues with the challenges presented by transformational growth (i.e., NLL), which the visual below from E3
helps characterize, and which are separate from the consideration of embedded CCOS methodologies. We
believe this docket should better frame the issues and further develop the regulatory options for serving NLL
without harming other customers.
Incremental vs. Transformational Loads
Larger,incremental loads can be I
absorbed if integrated over time or with
targeted upgrades
Typically,incremental loads are easily
managed within the existing system
without incurring significant fixed costs
Transformational loads can disrupt the
system and require significant new
infrastructure investment with large
upfront fixed costs and long asset
lifetimes;system attributes such as new
generation supply costs can also be
impacted due to a large demand shift
Structural inefficiencies can make it difficult to
quickly reach new equilibria under transformational
load growth
QEnergy Environmental Economics 79
This docket is a key opportunity to address certain matters of fairness as it relates to transformational New
Large Loads (NLL) and to flesh out instruments or alternatives potentially useful in NLL contracts. The topic
is fraught with tradeoffs that cannot be easily solved via the filing of a couple of methodologies.
Mathematical approaches are built on underlying choices related to accuracy & complexity, which are
3 IPC February Kick Off Slides, #12.
6

J J
intertwined with different perspectives of fairness. Before we get buried in the math, a robust dialogue is
needed to delineate the issues and choices.
We ask that the Company propose a process, such as workshops, to incorporate time for interactive
discussion on NLL. Prior to and during such workshops —
a) Parties should identify key issues related to New Large Loads. As examples, such issues may
include:
• The utility incurs costs to serve future loads before those loads occur. How should the
regulatory process consider costs incurred by IPC that would not otherwise occur but for a
future large load customer and yet occur prior to the customer's usage of those resources?
• Is there a size greater than 20MW that defines a NLL?
• Are there conditions when future costs are so significantly different from past that forward-
looking data should be considered in the apportionment of costs?
b) Parties should also have opportunity to present alternatives for discussion in workshops.
c) At minimum, CEO asks that this docket consider the potential for a CIAC prepayment approach to
the costs of G&T cost growth that would not otherwise occur but for the NLL yet are associated with
G&T resources not solely used by the NLL.
8. Both fairness and the appearance of fairness matter.
A reality is that the final report in dockets like this tends to get a disproportionately higher audience than the
comments of intervenors. E.g., in dockets related to on-site generation, audiences were far more likely to
have read the VOIDER study than the comments of intervenors.
In 2018 to 2020, parties invested time and resources into a docket (IPC-E-18-16) related to fixed cost
recovery. Staff and other parties raised concerns that the Company framed issues in the report as a means
of advocating for its own interests.'As the public pays more attention to power costs, objectivity and the
appearance of objectivity are both important. We suggest that either-
- Staff files the final report to the Commission in this docket or
- Staff and parties review a draft of a Company prepared final report for the purposes of screening for
objectivity prior to the Company filing the report among the case files.
- All parties should have opportunity to file comments in response to the report. We see no need for
any party to file surrebuttal comments.
' IPC-E-18-16 Staff Comments p2, 1/21/2020: "Rather than undertaking a comprehensive customer fixed-cost
analysis, the Company provided the Commission a position paper advocating its preferred rate design;"
7

Summary of Requests
In sum, CEO respectfully asks that—
1. An Hourly informed CCOS should be included in the filing as proposed by the Company and addressing
the refinements requested above.
2. No methodology in the CCOS docket should choose to classify Transmission infrastructure as 100%
associated with serving peak demand capacity. The EFAC and AED methodologies should apply to the
classification of Production AND Transmission.
3. Peakers should not be allocated based on 4 Coincident Peaks.
4. AED method should calculate Irrigator average usage for summer season, not all 12 months.
5. The proposed load factor allocator method (EFAC) should apply to infrastructure, not fuel or purchased
power. The growing reliance on purchased power, the time-varying nature of purchased power, and the
availability of hourly data all justify pursuit of a more accurate and informative method for addressing
purchase power in CCOS.
6. The "Energy & Fixed Allocation Classification" method should have a name that does not include
"Fixed." The term is confusing given the method is presented as an alternative to using "fixed" in the
classification of costs.
7. We ask the Company to propose a process, such as workshops, to better delineate the issues and
consider the regulatory choices for serving the transformational impacts of New Large Loads. At
minimum, CEO asks that this docket consider the potential for a CIAC solution.
8. We suggest that either Staff files the final report, and if not then Staff and parties should have
opportunity to review a draft of the final report for the purposes of screening for objectivity prior to the
Company filing the report among the case files. All parties should have opportunity to file rebuttal
comments. We see no need for any party to file surrebuttal comments.
8

The Federal Executive Agencies Initial Feedback to Idaho Power Company's
Class Cost of Service Case
RE: February 13, 2026 Prefiling Kickoff Meeting
February 27, 2026
The Federal Executive Agencies (FEA) appreciates the opportunity to provide initial
feedback to Idaho Power Company(I PC) regarding its Class Cost-of-Service presentation
that it gave stakeholders at the February 13, 2026 Kickoff Meeting. FEA reserves the right to
address any of the issues presented in the class cost of service case, including all matters
presented at the Kickoff Meeting.
Average and Excess Demand Methodology
FEA supports IPC's proposal to present the AED approach as an alternative methodology in
the upcoming class cost of service case. However, the average and excess demand (AED)
methodology should follow accepted industry design for AED,which is described within
the 1992 NARUC Electric Utility Cost Allocation Manual (NARUC Manual), pp. 49-52. The
AED description by IPC on slides 14 and 15 of its February 13th presentation seems to
deviate somewhat from the NARUC manual.
The AED methodology allocates all fixed production cost elements (e.g., production plant
in service) based upon a single set of AED allocation factors. Each rate class in the class
cost-of-service study has an AED allocation factor, and those class-by-class allocation
factors total 100%.When applied to any demand-related production cost element in the
class cost-of-service study, those allocations factors distribute 100% of that cost among
the rate classes.
The industry accepted application of the AED methodology combines each class's average
demand (i.e. class energy consumption) and a measure of each class's excess demand
into a single set of AED allocation factors. Excess demand is peak demand, less average
demand.When applying the AED methodology, a qualitative weight is used to combine
class average demand allocation factors and class excess demand allocation factors into a
single set of AED allocation factors. A utility's annual system load factor is oftentimes used
for this purpose, with class energy allocation factors weighted at the system load factor
percentage and class excess demand allocation factors weighted at one minus the system
Load factor. FEA supports the use of IPC's annual system load factor for this purpose.
A typical measure of peak demand used when applying the AED methodology is each rate
class's contribution to system peak, or each class's coincident peak(CP), for a selected
number of months. A four coincident peak(4CP) measure of peak demand can be a
reasonable measure of peak demand for purposes of applying the AED methodology,
1

thereby allowing for the use of AED-4CP as a label when referring to the application of the
AED methodology with the selection of four peak months.
When calculating excess demand allocation factors, an adjustment is necessary to set
excess demand at zero for classes with peak demand that is below average demand to
avoid having classes with negative excess demand.This adjustment retains an allocation of
demand-related production costs to these classes (e.g., street lighting)through the energy
allocation factors that would otherwise be partially or fully negated with negative excess
demand.
In addition, IPC receives capacity and energy benefits from most power purchases that are
included in its power supply portfolio, including purchases from renewable generators.
Addressing these benefits in the classification of energy- and demand-related production
costs is an important step that precedes cost allocation using the single set of AED
allocations factors.
On IPC's slide 14, IPC is correct that the final AED allocation factors are a"load-factor-
weighted combination of average and excess demand."The AED methodology uses those
AED allocation factors to allocate all fixed production cost elements (e.g., steam, hydro,
and other production plant in service) among the rate classes. If IPC's filing uses this AED
approach, then that would alleviate FEA's concerns regarding IPC's statements on slides 14
and 15 that may suggest IPC envisions using average demand allocation factors to allocate
baseload and intermediate demand-related costs and excess demand allocation factors to
allocate peaking demand-related costs. As explained above, that segmented allocation
would not represent a correct application of the AED methodology that utilizes load-factor-
weighted AED allocation factors. Instead, it would be a modification of IPC's existing Base-
Intermediate-Peak(BIP) methodology, and FEA does not support inclusion of a modified
BIP method in this case that is incorrectly labelled as an AED method.
Consistent with the NARUC Manual, FEA recommends that IPC include an AED
methodology with a single set of class AED allocation factors applied to the total fixed
production cost elements as an alternative class cost-of-service study in its initial filing in
this case.
Demand-Related Transmission Cost Allocation Among the Rate Classes
On slide 17, IPC indicates that it will apply hourly informed cost allocation methods to
demand-related transmission costs in addition to demand-related production costs. The
specific set of cost classifications and allocations selected by the preparer of a class cost-
of-service study determines the potential effects of that class cost-of-service study on a
utility's customers.This applies to all functionalized utility costs, or a utility's entire
2

revenue requirement. The result of the application of a class cost-of-service study to a
utility's entire revenue requirement is what matters—it can affect each customer's
electricity costs.Therefore, FEA fully anticipates that this case will involve additional
stakeholder positions regarding the allocation of demand-related transmission costs other
than IPC's existing method and those IPC will present with its hourly informed method.
Stated another way, transmission cost allocation methodologies will be just as relevant in
the case as production cost allocation methodologies.
3

Allen, Connor
From: Eric L. Olsen <[e-mail]>
Sent: Monday, March 2, 2026 8:48 AM
To: Austin Rueschhoff; Mike Louis; Allen, Connor; Anderson, Grant; Goicoechea Allen,
Megan; Walker, Donovan;Tatum, Tim; Aschenbrenner, Connie; Prassinos, Jordan; White,
Tami; Erika Melanson; Donn English; Michael Eldred; Michael Ott; Matt Suess; Thor
Nelson; Kristine A. Roach; 'Peter'; '[e-mail]'; '[e-mail]';
'[e-mail]'; Courtney White; kelsey; 'Mike Heckler'; Katie O'Neil; Ed Jewell;
Medlyn, Emily; Dwight D. Etheridge; 'Freeman,Jelani'; Lance Kaufman
Cc: Lance; Lance, Lisa; Brady, Jessi;York,Jessica; Steve Hubble; Kurt Boehm
Subject: [EXTERNAL] RE: Idaho Power CCOS Kickoff Meeting
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the
sender before proceeding, and check for additional warning messages below.
Good Morning:
Here are the IIPA's initial areas it wants to focus on in the Class cost of service Case:
Demand and energy classification of generation and transmission costs
Coincident peak weightings
Hourly cost of service modeling
Real time and day ahead market prices
Demand response
Time of use and real time pricing
Drivers for GWW, SWIP-N, 132H, and other recent or planned substations
Long run cost impacts of load growth
- * marginal transmission capacity cost by class
- * allocation treatment of Post 2023 incremental capital
- * segmentation of historical transmission by class per year
Eric L.Olsen
KAre;;, -
a, ECHo&OLSSEN HAWK
i

Allen, Connor
From: Austin Rueschhoff <DARueschhoff@hol land hart.com>
Sent: Friday, February 27, 2026 4:28 PM
To: Mike Louis;Allen, Connor; Anderson, Grant; Goicoechea Allen, Megan; Walker, Donovan;
Tatum, Tim; Aschenbrenner, Connie; Prassinos, Jordan;White,Tami; Erika Melanson;
Donn English; Michael Eldred; Michael Ott; Matt Suess;Thor Nelson; Kristine A. Roach;
'Peter'; '[e-mail]'; '[e-mail]'; '[e-mail]'; Courtney
White; kelsey, 'Mike Heckler'; Katie O'Neil; Ed Jewell; Medlyn, Emily; Dwight D. Etheridge;
'Freeman,Jelani'; Eric L. Olsen; Lance Kaufman
Cc: Lance; Lance, Lisa; Brady, Jessi;York,Jessica; Steve Hubble; Kurt Boehm
Subject: [EXTERNAL] RE: Idaho Power CCOS Kickoff Meeting
Attachments: Blank Direct Testimony.pdf; Maloney Direct Testimony.pdf
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the
sender before proceeding, and check for additional warning messages below.
Good afternoon Connor and other stakeholders,
Micron provides the following initial feedback for Idaho Power's upcoming COSS docket concerning Idaho Power's
allocation of purchased power costs.
In Idaho Power's 2024 rate case(IPC-E-24-07), FEA witness Larry Blank opposed Idaho Power's decision in its
2023 COSS to classify 100%of purchased power costs as 100%energy related. Mr. Blank noted that this was a
departure from Idaho Power's prior COSS in which Idaho Power used the Idaho jurisdictional load factor for
classifying purchased power costs as being either energy or demand-related costs. Mr. Blank further stated that:
"Except for economy energy transactions,purchased power costs typically reflect a combination of capacity and
energy costs embedded in the prices for those purchases. Stated another way, IPC receives both capacity and
energy benefits from most power purchases that are included in its power supply portfolio, including purchases
from renewable energy generators. Therefore, I cannot support a blanket classification that all purchased power
costs can be reasonably classified as energy-related costs."(IPC-E-24-07, Direct Testimony of Larry Blank, page 9,
Lines 7-16).
In its 2025 rate case (IPC-E-25-16), Idaho Power witness Riley Maloney testified that Idaho Power reviewed Mr.
Blank's recommendation in the 2023 rate case and that Idaho Power"acknowledges that certain proposals, such
as classifying a portion of purchased power costs as capacity-related may have merit, in keeping with the principle
of gradualism, additional modifications have not been incorporated into the Company's filed 2025 CCOS study."
Both of those pieces of testimony are attached for reference.
Micron supports Mr. Blank's recommendation in the 2024 rate case to classify some portion of purchased power
costs as capacity related and requests that Idaho Power present this as an alternative in its initial filing in the
upcoming COSS proceeding.
Thankyou,
Austin Rueschhoff
Austin Rueschhoff
Partner, Holland & Hart LLP
1

n NW Energy Coalition
for a clean and affordable energy future
NW Energy Coalition's Initial Comments on Idaho Power's Proposed Class Cost Of
Service Docket
February 27, 2026
Parties,
The NW Energy Coalition thanks all parties for the thoughtful and collaborative approach to
improving Idaho Power's Class Cost of Service methodologies. As we enter an unprecedented
level of growth and have access to modernized metering information and computing power,
now is a critical time to address this issue. These initial comments cover the following:
1. NWEC goals for the docket: accuracy, fairness, and enabling responsible growth.
2. Classification: Generation and Transmission are inextricably tied together and should
be accounted for in all potential methods presented to the Commission.
3. Allocation: coincident peaks drive the need for additional infrastructure.
4. Methods: using the most granular data available is both feasible and more accurate
than estimates or averages.
5. New Large Loads: the recent appearance of super large loads requires a
comprehensive review of resource planning, procurement, class cost of service methods,
and contractual provisions.
6. Process: like other policy related dockets, a Staff-authored report along with party
testimony and public comments is an appropriate method to build a record of the
Commission.
1. NWEC goals for the docket: accuracy, fairness, and enabling responsible growth.
The NW Energy Coalition believes that load growth is a sign of a healthy and vibrant
economy. We support the creation of additional housing,jobs, and economic activity that
delivers meaningful benefits to the people of Idaho. We believe everyone has the right to
adequate, reliable, and fair priced energy services. This right comes with an obligation to
pay one's fair share and use Idaho's shared resources for the benefit of the state and its
people.
811 V Avenue.Suite 305,Seattle,WA 98104 [phone]
www.nwenerev.orre [e-mail]

Specific to Idaho Power's service territory, new super large loads coming from Micron's
expansion likely meet this test because they lead to creating many,well paid jobs for a broad
spectrum of Idahoans. Meanwhile, the product of Micron's energy demands is useful for
Idahoans along with the rest of the world. The same can be said for Idaho's agricultural
sector, the Idaho National Lab, and most other industrial and large commercial uses. By
contrast, new super-large loads that do not create many meaningful jobs and produce
products that are primarily useful to those outside of Idaho, social media posts and training
Artificial Intelligence models for example, may not meet this test.
Our goals in this docket are not to exclude any new user on the system nor impose costs that
are not attributed to that class. But we all face unprecedented needs for capital investments
to repair and improve the transmission and distribution system, address rising wildfire risks,
meet growth, and address quickly inflating costs. We recognize that Idaho Power has a duty
to serve customers. But now is the critical time for the Commission and stakeholders to
prioritize these capital needs to balance this duty to serve with the duty to keep rates
affordable. Improving the Class Cost of Service Method to more accurately assign costs and
comprehensively addressing the range of issues super-large loads bring is an important step
forward.
2. Classification: Generation and Transmission are inextricably tied.
Classifying the costs of Generation, Transmission, and Distribution may have the largest overall
impact on the costs assigned to each customer class. Each of these functions plays a role in
providing the useful service that every customer needs—the flow of energy to provide useful
work and the capacity to meet the demand for that flow. Cost of service methods that assume
any of the functions are purely demand related or purely energy related are not tied to reality of
the system. Put more simply, generation that supplies a customer's energy needs is useless
without the transmission and distribution system to deliver to the end user. This reality applies
to both existing customers and new customers. Accordingly,NWEC supports class cost of
service methods that distinguish the portion of the infrastructure costs that meets a base level of
energy from the portion that meets the incremental demand.
In this docket, we are focused on the classification of Generation and Transmission because
these functions are shared across all customer classes. NWEC's understanding is that all the
initial methods identified by Idaho Power can be adapted to improve the classification of
Generation and Transmission costs according to how each contributes to serving customers'
energy and demand. When presenting potential methods to the Commission we encourage Idaho
Power to treat Generation and Transmission based on the principle that energy-related
generation requires some amount of transmission to be useful.
3. Allocation: coincident peaks drive the need for additional infrastructure.
NWEC believes that coincident peak demands are the primary driver of the need for new
infrastructure. We support allocation methods that focus on the coincidence of each class of
customer's use of the system compared to overall system operations. The underlying issue
though is how to accurately determine when the meaningful coincident peak occurs. Methods
used to date focus on the monthly peak, but new methods can be more accurate and granular by
2

assessing the hourly coincidence and assigning costs and benefits accordingly. We recognize
that Idaho Power's system has both peaks and troughs throughout the day that cause different
costs which must be reflected in the class cost of service methods. Idaho Power's current
method and the Average and Excess Demand Method both require the use of monthly peaks to
assign costs, which will always be less accurate than using the available data to take an hourly
perspective. Meanwhile, the Energy and Fixed Allocation Classification does not apply to the
allocation of costs, according to Idaho Power's workshop presentation. We look forward to
working with the parties to explore cost allocation that uses the best available data and the most
granular view to accurately assign costs and benefits to customers.
4. Methods: using the most granular data available increases accuracy.
NWEC believes that the modern, sophisticated metering system Idaho Power has in place, along
with advancements in analytical tools and computing power enables a more granular and robust
cost of service method. Prior methods that used averages may have been necessary to address
the available data and ability to process results. We believe now is the time to apply the tools
already available to improve the accuracy of the class cost of service methodologies. The
Energy and Fixed Allocation Classification uses granular data but suffers from not appearing to
apply to the allocation of costs. The Hourly Informed method appears to be the best potion to
use the tools available today.
5. New Large Loads: requires a comprehensive review of resource planning,
procurement, class cost of service methods, and contractual provisions.
As stated above,NWEC is not opposed to load growth that delivers meaningful benefits to
Idaho in terms of housing, employment, and useful products and services. We support Idaho
Power's long-standing efforts to address large loads and follow the cost causer pays principle.
In the past, new large loads, those 20 megawatts and above, were manageable through including
incremental load in the planning forecast and using the line extension policies and special
contracts. But the new trend of super large loads that can fundamentally change the cost
structure of the utility in a short time frame requires a more comprehensive approach to this
issue. Idaho Power and stakeholders have addressed a similar issue before by adopting the
Schedule 20 for Speculative High-Density Loads. We are not saying that solution applies to all
new loads, rather we endorse the principle that some types of new load are so meaningfully
different from existing uses that a new approach to planning, resource procurement, cost of
service, and tariff is necessary.
We appreciate the ideas Idaho Power put forth to distinguish growth related costs based on
Arizona Public Service and Portland General Electric,both utilities that face significant levels
of new loads. APS seems particularly relevant because that territory is growing for a variety of
reasons, while PGE's territory is experiencing a more concentrated growth of large loads. Both
methods appear to distinguish between costs related to serving existing customers and costs
related to serving new customers. We support this distinction.
Overall, we believe this issue also requires improvements to the Integrated Resource Planning
load forecast and portfolio selection process to lay a foundation for making this distinction. And
we believe that improvements to Idaho Power's resource procurement process is another
3

important step to identify the costs that are attributable to growth. We do not have specific
recommendations on these topics yet. We raise this to encourage all parties to take a more
comprehensive approach to identifying the costs attributable to growth as a precursor to
adopting methods to assign these costs.
6. Process: a Staff-authored report along with party testimony and public comments
is an appropriate method to build a record of the Commission.
NWEC helped negotiate the settlement provisions that lead to this docket. We appreciate
Idaho Power's initial proposals, commitment to open the docket, and to run the various
analytical methods. The workshop presentation was complete and presented in a
collaborative fashion. And we continue to support Idaho Power initiating the docket and
providing further information because they hold the basic data we all need to assess these
issues. As we move forward, we suggest that one part of the record is a Staff-authored
report laying out the cost-of-service options and the policy choices embedded in each. Staff
are the party with the duty to balance the interests of all participants. Each party is then free
to present their unvarnished opinion and analysis of the options. We believe this is a robust
and fair way to develop a full record for the Commission.
NWEC appreciates the collaborative nature of this process thus far. We thank Idaho Power for
producing a clear, thoughtful, and helpful workshop presentation. Our comments above are
based on our understanding of the issues currently. We look forward to working through this
further.
Respectfully,
Benjamin J. Otto
Senior Policy Associate
NW Energy Coalition
4

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

Idaho Power Company Class Cost-of-Service Process Guide
Class Cost-of-Service Process Guide
Case No. IPC-E-26-07
This process guide provides a technical description of Idaho Power Company's Class Cost-of-
Service study methodologies for Case No. IPC-E-26-07. The methodology for separating costs
among classes consists of three steps, generally referred to as functionalization, classification,
and allocation. In all three steps, recognition is given to how costs are incurred by relating these
costs to how the utility operates to provide electrical service.
Idaho Power Company's 2025 CCOS Methodology
Under the Company's 2025 Class Cost-of-Service (CCOS) method, the model functionalizes,
classifies, and allocates costs to reflect how customer classes use Idaho Power's system across
the primary operating functions and cost drivers.The method begins by identifying how plant
investments and expenses support production, transmission, distribution, customer service, and
other utility functions, and then classifies each cost as demand-, energy-, or customer-related
to align with the ways in which customers make use of the system over time. The model is
structured to model year-round system availability requirements, the capability needed to meet
periods of highest load, and the energy required to serve continuous consumption.
The 2025 CCOS method uses net-peak-based coincident demand measures, (12CP and 4CP),
calculated at the hour of each month's highest net load (system demand adjusted to exclude
contemporaneous output from non-dispatchable resources). These net-peak values are used to
allocate demand-classified production-related costs. Under the model's structure:
• Production plant associated with base and intermediate resources is allocated using
annual net-peak 12CP values, consistent with serving load throughout the year; and
• Production plant associated with peaking resources is allocated using net-peak 4CP
values for June through September, reflecting the periods when these units are typically
required to support the system.
Energy-related costs, such as fuel, purchased power, and other variable production expenses,
are allocated using seasonal energy allocators that average normalized usage weighted by
marginal energy costs.
Customer-related costs, including metering, billing, and customer service, are allocated based
on the number of customers and the activities required to serve them.
By classifying costs and applying demand-, energy-, and customer-related allocators based on
system data used in the study, the model describes how customers rely on Idaho Power's
system throughout the year. Classes that contribute more during monthly net-peak hours
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Idaho Power Company Class Cost-of-Service Process Guide
receive a greater share of demand-related production costs, while classes with higher
year-round energy use receive a corresponding share of energy-related costs. In this way, the
method is intended to represent both ongoing utilization of system resources and the
operational conditions that influence system planning and investment within the Idaho
jurisdiction.
EFAC Method
Under the Energy- and Fixed-Allocation-Classification (EFAC) method, the model modifies the
classification of eligible production-related costs to reflect the two services production assets
provide: (i) continuous, year-round energy delivery and (ii) capability above average usage
required to meet peak system load. EFAC accomplishes this by applying the Idaho jurisdictional
load-factor to production categories, splitting each into:
• A demand-related component, equal to one minus the load-factor (average system load
peak system load), representing the portion of costs associated with maintaining
system capability to meet peak conditions; and
• An energy-related component, equal to the load-factor, representing the portion of
production costs associated with serving ongoing, year-round energy needs.
This method uses the jurisdictional load-factor to express the relationship between the system's
average and peak conditions and to classify the share of the production fleet associated with
continuous usage versus peak-driven capability. In this way, the load-factor split is intended to
represent the dual role of production resources: supplying continuous energy and maintaining
capability for peak-supporting reliability.
Under this method, production categories—such as steam, hydro, and non-fuel components of
purchased power—are separated into demand- and energy-related portions based on the
load-factor split. Variable cost items, such as fuel, remain 100 percent energy-related, while
peak-oriented programs such as demand-response incentives remain 100 percent
demand-related. These distinctions describe the conceptual differences between variable inputs
that follow MWh usage and fixed inputs associated with system capability.
After classification, this method allocates the demand-classified portion of production costs
using the model's existing allocator framework. The demand-classified portion of base and
intermediate resources is assigned using the Summer and Non-Summer coincident-peak
allocators (D10BS and D10BNS), while peaking resources are allocated using the four-month
net-peak allocator (D10P), which reflects capacity requirements during the highest-risk summer
months.
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Idaho Power Company Class Cost-of-Service Process Guide
Energy-classified components are allocated using the seasonal energy allocators E10S and
E10NS, which assign costs based on each class's share of seasonal energy consumption.
By incorporating the system load-factor into classification and applying the allocator set based
on Idaho Power's system data inputs used in the study, the EFAC method is intended to
represent customer classes' contributions to year-round energy needs and peak-related system
conditions.
AED-4CP Method
Under the Average & Excess Demand with four coincident peaks (AED-4CP) method, the model
modifies the allocation of demand-related production costs by applying a single, unified annual
AED allocator that reflects each class's contribution to both year-round system usage and
summer capacity (coincident-peak) requirements, as described in the 1992 NARUC Manual.
The AED-4CP allocator combines two components:
• Average demand, representing the level of load that production resources must serve
continuously across the year, weighted by the system load-factor; and
• Excess demand, defined as the non-negative difference between a class's four-month
(June—September) net-peak coincident demand and its average demand, weighted by
one minus the system load-factor.
The method's blended structure represents both the continuous load served by production
resources and the additional capability associated with meeting summer peak conditions.
Classes with sharper summer peaks therefore receive a larger excess-demand component, while
classes with smoother usage patterns are represented more strongly by their average-demand
component.
Under this model, the resulting annual AED-4CP value becomes the production-demand
allocator (D10P) applied to production. For seasonal presentation, the same annual AED value is
proportionately time-sliced into Summer (D10BS) and Non-Summer (D10BNS) in proportion to
the seasonal shares used in the model, such that D10BS + D10BNS = D10P for each class.
Hourly-Informed Method
Under the Hourly-Informed method, the model modifies the classification and allocation of
Production and Transmission costs using full-year hourly data. The method converts annual
Production costs into hour-specific values (using weighted hourly dispatch when hourly prices
apply and simple hourly dispatch when they do not) and converts Transmission Plant costs into
a single annual $/MWh-served by dividing Transmission Plant cost by total served MWh; it then
allocates Production based on each class's hourly MWh consumption and applies the annual
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Idaho Power Company Class Cost-of-Service Process Guide
Transmission Plant $/MWh-served to each class's metered hourly MWh. The method proceeds
in three stages:
• Resource-type cost classification: Production costs are classified by resource type (e.g.,
Hydro, Thermal Baseload, Thermal Peaking, Batteries, Demand Response, Purchased
Power).
• Hourly cost distribution: Each Production resource's annual cost is distributed across
8,760 hours based on its hourly output or contribution, using either weighted dispatch
(hourly output multiplied by hourly prices) or simple hourly dispatch where prices do
not apply. Transmission Plant costs are likewise distributed across hours in proportion to
hourly MWh served, reflecting how bulk-power delivery varies with system usage.
• Hourly allocation to classes: Hour-specific Production and Transmission costs are
allocated to classes in proportion to each class's hourly MWh usage.
Under this method's structure, Production and Transmission costs are allocated on an
hour-specific $/MWh basis applied to hourly served energy, resulting in cost allocations that
vary with each class's hourly MWh usage.
EFAC P&T Method
Under the EFAC P&T(Energy- and Fixed-Allocation-Classification for Production &Transmission)
method, the model extends EFAC's load-factor-based classification to both bulk-power
functions so that embedded costs reflect two services: (i) continuous, year-round energy
delivery and (ii) capability above average usage required to meet peak system conditions. EFAC
P&T applies the Idaho jurisdictional load-factor at the classification stage to Production and
Transmission, splitting each into:
• A demand-related component, equal to one minus the load-factor (average system load
peak system load), representing the portion of costs associated with maintaining
system capability to meet peak conditions; and
• An energy-related component, equal to the load-factor, representing the portion of
production costs associated with serving ongoing, year-round energy needs.
Items that vary directly with MWh, such as production fuel, remain 100 percent energy-related,
while peak-oriented programs such as Demand Response (DR) remain 100 percent
demand-related. Transmission — Direct (Accounts 350-359) continues to be directly assigned.
Following classification, Production costs are allocated through the Company's established
allocator set. Energy-classified Production is allocated using E10S and E10NS, and
demand-classified Production is allocated using MOBS, D10BNS, and D10P.
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Idaho Power Company Class Cost-of-Service Process Guide
For Transmission Plant, EFAC P&T retains D13 for the Demand share and introduces a new
energy-based transmission allocator, E13, for the Energy share. E13 is constructed analogously
to D13 but on energy: (i) compute class actual energy ratios from the sum of monthly served
MWh, (ii) compute class weighted energy ratios by multiplying monthly served MWh by
monthly transmission marginal cost, and (iii) compute the simple average of (i) and (ii) to form a
single non-seasonal E13 factor.
Under this method's structure, classes with higher contributions to peak conditions receive a
larger share of the demand-classified costs and classes with greater year-round energy use
receive a larger share of the energy-classified Production and Transmission costs.
I. PROCESS OVERVIEW
A. Functionalization
Functionalization is the process of assigning the Company's revenue requirements to operating
functions, including Production,Transmission, Distribution, Customer, and Miscellaneous, with
additional sub-functionalization where plant records support identification (e.g., substations
primary lines, secondary lines, meters).
1. Changes under the EFAC Method
EFAC does not change functionalization.
Il. Changes under the AED-4CP Method
AED-4CP does not change functionalization.
Ill. Changes under the Hourly-Informed Method
Hourly-Informed does not change functionalization.
IV. Changes under the EFAC P&T Method
EFAC P&T does not change functionalization.
B. Classification
The NARUC Electric Utility Cost Allocation Manual provides the basis for Idaho Power's
classification process. Classification identifies each cost as demand-related, energy-related, or
customer-related to reflect that an electric utility makes service available to customers
continuously; provides as much service, or capacity, as the customer may require at any point in
time; and supplies energy to provide customers the ability to do useful work over an extended
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Idaho Power Company Class Cost-of-Service Process Guide
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 the customers, or changes
in energy used by the 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 to be fixed costs.
Demand-related costs are investments in production, transmission, and a portion of the
distribution plant and the associated operation and maintenance (O&M) expenses necessary to
accommodate the maximum demand imposed on the Company's system.
Energy-related costs are generally the variable costs associated with operating generating
plants, such as fuel.
1. Changes under the EFAC Method
Under EFAC, the model classifies production-related costs using the Idaho jurisdictional
load-factor, separating each cost into demand-related and energy-related components. The
load-factor determines the energy-related share, and the remaining portion is demand-related.
Il. Changes under the AED-4CP Method
AED-4CP does not change classification.
Ill. Changes under the Hourly-Informed Method
Under the Hourly-Informed method, the model classifies Production and Transmission for use in
the hourly cost-build. Production plant and related expenses flow into the hourly structure
through resource-type assignment. Transmission classification continues to distinguish between
Transmission Plant, which flows into the hourly structure, and Transmission — Direct (Accounts
350-359), which remains directly assigned
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Idaho Power Company Class Cost-of-Service Process Guide
I V. Changes under the EFAC P&T Method
Under EFAC P&T, the model classifies Production and Transmission Plant using the Idaho
jurisdictional load-factor, separating each cost into demand-related and energy-related
components. The load-factor determines the energy-related share, and the remaining portion is
demand-related. Variable items such as fuel remain 100 percent energy-related, and
Transmission — Direct (Accounts 350-359) continues to be directly assigned.
C. Allocation and Summarization of Results
After costs are functionalized and classified, they are allocated to customer classes using the
applicable allocation factors and summarized to develop class cost responsibility results.
1. Changes under the EFAC Method
EFAC continues to use the existing allocation factors, with differences in results stemming from
the revised classification of eligible production-related cost categories under the load-factor
split.
11. Changes under the AED-4CP Method
AED-4CP allocates demand-related Production using an AED-4CP allocator that blends each
class's average demand and non-negative excess demand using the system load-factor to
produce the annual capacity allocator.
W. Changes under the Hourly-Informed Method
Hourly-Informed applies an allocation for Production and Transmission Plant based on
hour-specific resource costs and each class's hourly MWh usage.
I V. Changes under the EFAC P&T Method
EFAC P&T continues to use the existing Production allocators for demand- and energy-classified
amounts, and for Transmission the demand-classified portion continues to be allocated using
D13 while the energy-classified portion is allocated using the new E13 allocator.
II. ASSIGN AND FUNCTIONALIZED
COST MODULES
The Company's class cost-of-service model is implemented in a single Microsoft' Excel
workbook comprised of two modules. The first module, referred to as the Assign Module (AS
Module), performs the functionalization and classification steps by categorizing Idaho
jurisdictional costs (by FERC account) into operating functions and classifying those costs as
demand-related, energy-related, or customer-related. For example, the AS Module categorizes
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Idaho Power Company Class Cost-of-Service Process Guide
the Company's investment in steam plant into the production function and as a demand-related
classification. The second module, referred to as the Functionalized Cost Module (FC Module),
performs the class allocation process by applying the applicable allocation factors to the
functionalized and classified costs and summarizing class cost responsibility results. Each
operation performed by this module is shown as a separate worksheet to make the allocation
process transparent and easier to follow.
1. Changes under the EFAC Method
EFAC does not change the mechanics of either module; rather, the AS Module applies EFAC's
load-factor split at classification to applicable Production categories, and the FC Module
continues to apply the existing Production allocators to the resulting demand- and
energy-classified amounts.
IL Changes under the AED-4CP Method
AED-4CP does not change the AS Module; in the FC Module, demand-related Production is
allocated using the AED-4CP allocator, which blends each class's average demand and excess
demand using the system load-factor to produce the annual D10P allocator, and for seasonal
presentation the same annual AED-4CP value is proportionately time-sliced into D10BS and
D10BNS, such that D10BS + D10BNS = D10P for each class .
Ill. Changes under the Hourly-Informed Method
Hourly-Informed treats classification in the AS Module for use in the hourly cost-build, with
Production flowing into the hourly structure through resource-type assignment and
Transmission continuing to distinguish between Transmission Plant, which flows into the hourly
structure, and Transmission — Direct (Accounts 350-359), which remains directly assigned; the
FC Module then assembles annual costs by Production and Transmission grouping, distributes
those costs across 8,760 hours based each resource's hourly output or contribution using
weighted dispatch when hourly prices apply and simple hourly dispatch when they do not,
computes hour-specific$/MWh-served, and sums hourly allocations to obtain annual results.
IV. Changes under the EFAC P&T Method
EFAC P&T applies the Idaho jurisdictional load-factor split in the AS Module to both Production
and Transmission, separating each into demand-related and energy-related components, and in
the FC Module allocates Production using the established allocator set while allocating
Transmission Plant by continuing to use D13 for the demand-classified portion and using E13 for
the energy-classified portion
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Idaho Power Company Class Cost-of-Service Process Guide
III. 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 corresponding 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 relevant plant function. Energy efficiency program expenses are
functionalized consistent with baseload production resources for purposes of this study.
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 item, 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
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Idaho Power Company Class Cost-of-Service Process Guide
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.
IV. CLASSIFICATION
A. Steam and Hydro Production
In this Class Cost-of-Service study all production plants (steam, hydro, other [including natural-
gas fueled and battery-storage capacity], and diesel) have been classified as 100% demand-
related; production plant investment is treated as fixed for classification in the 2025 CCOS study.
Transmission plants are also classified as demand-related, which is consistent with prior cost-of-
service studies.
1. Changes under the EFAC Method
EFAC classifies Steam and Hydro Production by applying the Idaho jurisdictional load-factor,
with the portion equal to the load-factor classified as energy-related and the remaining portion
(1 — load-factor) classified as demand-related.
11. Changes under the AED-4CP Method
AED-4CP does not change the classification of Steam and Hydro Production.
W. Changes under the Hourly-Informed Method
Hourly-Informed classifies Steam and Hydro Production by resource type, with steam units
mapped to Thermal Baseload or Thermal Peaking and hydro units mapped to the Hydro
resource type for use in the hourly cost-build.
IV. Changes under the EFAC P&T Method
EFAC P&T applies the Idaho jurisdictional load-factor at classification to Steam and Hydro
Production, separating each into demand-related and energy-related components consistent
with the method's treatment of other bulk-power assets.
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Idaho Power Company Class Cost-of-Service Process Guide
B. PURPA and Purchased-Power Expenses
PURPA and purchased-power expenses booked to FERC Account 555 are classified as 100%
energy-related in the 2025 CCOS study because these costs vary with the amount of energy
provided.
1. Changes under the EFAC Method
EFAC classifies Purchased Power (Account 555) using the Idaho jurisdictional load-factor, with
the portion equal to the load-factor classified as energy-related and the remaining portion
classified as demand-related. Fuel expenses remain 100 percent energy-related.
ll. Changes under the AED-4CP Method
AED-4CP makes no changes to the classification of Account 555.
M. Changes under the Hourly-Informed Method
Hourly-Informed classifies Account 555 and other purchased-power categories to the Purchased
Power resource type within Production, and these expenses flow into the hourly Production
cost stream for allocation.
IV. Changes under the EFAC P&T Method
EFAC P&T classifies expense-only Purchased Power (Account 555) using the Idaho jurisdictional
load-factor, with the load-factor determining the energy-related share and the remainder
classified as demand-related. Fuel expenses remain 100 percent energy-related.
C. Distribution Plant
Distribution substation plant accounts 360, 361, and 362 are classified as demand-related.
Distribution plant accounts 364, 365, 366, 367, and 368 are classified as either demand-related
or customer-related using the same fixed and variable ratio computation method used in the
Company's prior general rate case proceedings. The fixed-to-variable ratio is updated according
to a system capacity utilization measurement based on a three-year average load duration
cu rve.
1. Changes under the EFAC Method
EFAC makes no change to Distribution Plant classification.
ll. Changes under the AED-4CP Method
AED-4CP makes no change to Distribution Plant classification.
M. Changes under the Hourly-Informed Method
Hourly-Informed makes no change to Distribution Plant classification.
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Idaho Power Company Class Cost-of-Service Process Guide
I V. Changes under the EFAC P&T Method
EFAC P&T makes no change to Distribution Plant classification.
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, these interval-based coincident demand
measures are used to inform the treatment of any non-AMI or non-interval customer.
Coincident demand values for each rate class are calculated by summing interval-metered
demand at the hour of each month's net-peak (defined as the peak system hourly load after
excluding contemporaneous output from non-dispatchable resources, such as solar and wind
production), using system hourly load data from the year prior to the test year to identify the
applicable net-peak hours. These monthly coincident demand values are adjusted upward for
non-interval metered customers and system losses. Using these adjusted monthly coincident
demand values, 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 production customers, measurement of
the energy delivered to customers is the basis of energy and system coincident load statistics.
On-site production exports are addressed outside the CCOS allocation calculations.
1. Changes under the EFAC Method
EFAC makes no change to the derivation of monthly coincident or non-coincident peak
measures.
11. Changes under the AED-4CP Method
AED-4CP uses the same coincident and non-coincident derivation process and additionally
develops each class's four-month summer coincident demand (June—September), annual
average demand, and non-negative excess demand—the difference between the four-month
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Idaho Power Company Class Cost-of-Service Process Guide
coincident value and the annual average. These values are combined with the system
load-factor to form the annual AED-4CP allocator D10P. For seasonal presentation, the same
annual AED-4CP value is proportionately time-sliced into D10BS and D10BNS, such that D10BS +
D10BNS = D10P for each class.
Ill. Changes under the Hourly-Informed Method
Hourly-Informed does not use monthly coincident or non-coincident peak measures for
allocating Production and Transmission Plant. Instead, hourly class MWh serve as the allocator
basis. Class loads are aggregated for each hour of the test year, and these hourly values are used
to apply the study's hourly$/MWh-served cost streams.
I V. Changes under the EFAC P&T Method
EFAC P&T makes no change to the derivation of monthly coincident or non-coincident peak
measures.
B. Marginal Cost Usage
The 4CP/ 12CP approach does not apply marginal cost weighting to production plant allocators;
marginal-cost weighting is used in the study to seasonalize energy-related costs and develop
transmission marginal-cost weighted components. The weighting combines embedded
allocation measures with marginal-cost-weighted measures and incorporates seasonal load
profile information used in the study.
The marginal costs associated with new resource integration are seasonalized based on the
Company's monthly loss of load expectation (LOLE) analysis that was conducted as part of its
2023 Integrated Resource Plan (IRP). The monthly LOLE amounts for the five-year period 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.
Updated 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 2025
through 2029. It should be noted that the marginal costs have been used solely for purposes of
developing allocation factors and not for purposes of developing the Company's revenue
requirement.
1. Changes under the EFAC Method
EFAC makes no change to how marginal costs are developed or used.
11. Changes under the AED-4CP Method
AED-4CP makes no change to how marginal costs are developed or used.
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Idaho Power Company Class Cost-of-Service Process Guide
M. Changes under the Hourly-Informed Method
Hourly-Informed makes no change to how marginal costs are developed or used for seasonal
allocator construction elsewhere in the study; Production and Transmission allocations are
performed using hour-specific $/MWh-served values.
IV. Changes under the EFAC P&T Method
EFAC P&T makes no change to the development of marginal costs. EFAC P&T introduces a
Transmission-specific energy allocator, E13, for the energy-classified share of Transmission
Plant. E13 is constructed analogously to D13 but based on energy by averaging (i) class actual
energy ratios derived from summed monthly served MWh and (ii) class weighted energy ratios
formed by multiplying monthly served MWh by monthly transmission marginal cost.
C. Production Plant Cost Allocation
The class cost-of-service study allocates the costs of the Company's production peaking facilities
differently than its baseload resources. Rather than allocating all production plant using a single
allocation factor, the study applies different allocation factors based on the nature of the load
being served. Under this approach, production plant costs associated with serving summer peak
load are allocated separately from costs associated with serving the base and intermediate load.
For example, the costs associated with building and operating simple-cycle combustion
turbines, which are used primarily to serve summer peak loads, are allocated using a different
allocator than the Company's other production resources, including the Langley Gulch
combined-cycle combustion plant (CCCP). The study allocates production plant costs associated
with serving base and intermediate load using an average of net 12CP coincident demands,
without marginal cost weighting. The study allocates fixed production costs associated with
serving peak load using an average of net 4CP coincident demands occurring in June, July,
August, and September. This structure applies separate allocators to the baseload/intermediate
and peaking categories using the coincident demand measures described in this section.
The cost allocation method used in the study is based on the concept that the costs associated
with each of the Company's production resources can be categorized according to the type of
loads being served. Utilities typically experience three distinct time-based production costing
periods that are driven by customer loads. The costing periods are normally identified as base,
intermediate, and peak. The base period is equivalent to a low load or off-peak time period
where loads are at the lowest, normally during the nighttime hours. The intermediate time
period represents the shoulder hours which are driven by the mid-peak loads that typically
occur throughout the winter daytime and in the early morning and late evening during the
summer months. The peak category is driven by the Company's peak loads that occur during
summer afternoons and evenings. The base and intermediate loads on the Company's system
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Idaho Power Company Class Cost-of-Service Process Guide
are typically served by the same production resources. Accordingly, these two categories have
been combined for cost allocation purposes. The production resources that serve the peak
loads (i.e., combustion turbines) are normally only used for that purpose. Consistent with that
concept, the costs associated with peak-related resources have been segmented into a second
category for cost-allocation purposes. Under this approach, marginal cost weighting is not
applied to these production plant demand allocators; the seasonal distinction is reflected
through the use of 12CP and four-month 4CP coincident demand measures.
The production plant costs that have been classified as serving base and intermediate load are
captured in accounts 310 through 316, Steam Production and accounts 330 through 336,
Hydraulic Production. Accounts 340-346, Other Production, for the Langley Gulch CCCP, and
Account 387 where the Company's battery storage system is recorded. The costs identified
under the Steam Production category represent the Company's investment in coal-fired
production facilities, and the costs identified under the Hydraulic Production category represent
the Company's investment in its hydroelectric production 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 costs are instead captured in the levelized revenue
requirement additions for Valmy and Bridger, which are incorporated into the total revenue
requirement.
In general dispatch practice, production resources with lower variable operating costs are
dispatched before resources with higher variable operating costs, with additional resources
dispatched as system load increases. For Idaho Power, hydroelectric output can vary with
streamflow conditions and related operation considerations, which can affect the relative share
of energy supplied by hydro and thermal resources over the year. Consistent with this, the study
recognizes that the proportion of output from steam and hydro resources vary by month, while
the combined monthly output of these resources may differ less between summer and non-
summer periods than the output of peaking combustion turbines.
Accounts 340 through 346, Other Production, contain the Company's investment in gas-fueled
production plant. The production plant investment captured in accounts 340 through 346
represents both the Company's investment in simple-cycle combustion plants (SCCP), and
CCCPs. Because these resources are dispatched to meet different types of customer load, they
are listed independently between the Langley Gulch CCCP that serves base and intermediate
load, while Bennett Mountain and Danksin SCCPs are peak-load serving resources. The
investment identified as peaking plant is the investment in combustion-turbine production
resources that were constructed to meet the summer peak loads.
In the FC Module, D10BS and D10BNS describe the factors used to allocate the production plant
associated with serving the base and intermediate loads. D10P describes the allocation factor
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Idaho Power Company Class Cost-of-Service Process Guide
used to allocate the production plant associated with serving the peak loads. The MOBS and
D10BNS represent the non-weighted average 12 coincident net-peak demands for the summer
and non-summer seasons, respectively. D10P represents the non-weighted average four
coincident net-peak demands for June, July, August, and September.
1. Changes under the EFAC Method
EFAC continues to allocate Production Plant using the Company's existing Production allocators,
D10BS/D10BNS/D10P for Demand-classified Production Plant and E10S/E10NS for
Energy-classified Production Plant, as described in this section.
ll. Changes under the AED-4CP Method
AED-4CP allocates fixed Production Plant and related fixed Production O&M using a single
annual capacity allocator that blends two class-specific components using the system
load-factor.
For each class, the model develops (i) average demand (the class's annual average load) and (ii)
excess demand, defined as max(4CP — average, 0) using four net-peak coincident-peak months
(June—September).
Average demand is weighted by the load-factor, and excess demand is weighted by 1 —
load-factor. The blended value is then normalized across classes to form the annual AED-4CP
share (D10P), which is applied uniformly to Production Plant and related fixed Production O&M.
For seasonal presentation, the same annual AED-4CP value is proportionately time-sliced into
MOBS (Summer) and D10BNS (Non-Summer), such that MOBS + D10BNS = D10P for each class.
W. Changes under the Hourly-Informed Method
Hourly-Informed allocates Production Plant using full-year hourly data. Annual Production costs
are classified by resource type (e.g., Hydro, Thermal Baseload,Thermal Peaking, Batteries,
Demand Response, Purchased Power) and distributed across all 8,760 hours in proportion to
each resource's hourly output, with Hydro, Batteries, and Demand Response using hourly
dispatch and Thermal Baseload, Thermal Peaking, and Purchased Power using weighted hourly
dispatch (hourly output multiplied by hourly prices), producing hourly cost streams.
For each hour, the model expresses Production on a $/MWh-served basis by dividing the hour's
total Production cost by total metered customer load in that hour and applies that hourly rate
to each class's metered hourly MWh.
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Idaho Power Company Class Cost-of-Service Process Guide
I V. Changes under the EFAC P&T Method
EFAC P&T continues to allocate Production Plant using the Company's existing Production
allocators, D10BS/D10BNS/D10P for Demand-classified Production Plant and E10S/E10NS for
Energy-classified Production Plant, as described in this section.
D. Transmission and Distribution Cost Allocation
The study allocates transmission and distribution costs using a combination of direct assignment
and allocation factors. Allocation factors are selected based on the applicable demand- or
customer-related measures used in the study.
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. The Company applies this averaging approach to moderate
the influence of marginal-cost weighting on the resulting factor.
The capacity components of distribution plant, both primary and secondary, are allocated by
the non-coincident group peak demands for each customer class identified as demand
allocation factors D20, D30, D50, and D60.
The customer components of distribution plant, both primary and secondary, are allocated by
the average number of customers identified as customer allocation factors C20, C30, C50 and
C60.
1. Changes under the EFAC Method
EFAC makes no change to the allocation of Transmission or Distribution costs.
II. Changes under the AED-4CP Method
AED-4CP makes no change to the allocation of Transmission or Distribution costs.
M. Changes under the Hourly-Informed Method
Hourly-Informed allocates Transmission Plant on a served-energy basis across all 8,760 hours.
The study computes an annual transmission $/MWh-served by dividing total Transmission Plant
cost by total served MWh, applies that value to each class's metered hourly MWh, and sums
across hours to obtain annual class Transmission Plant allocation. Transmission — Direct
(Accounts 350-359) remains directly assigned and does not participate in the pooled hourly
allocation. Allocation of Distribution costs are unchanged.
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Idaho Power Company Class Cost-of-Service Process Guide
I V. Changes under the EFAC P&T Method
EFAC P&T reflects EFAC's classification split for pooled Transmission Plant into demand-related
and energy-related portions. The demand-related portion continues to allocate using D13. The
energy-related portion allocates using a new E13 factor constructed analogously to D13 but
based on energy: class shares of monthly served MWh are averaged with class shares of
monthly served MWh weighted by monthly transmission marginal cost to form a single,
non-seasonal, energy-based transmission allocator. Transmission — Direct (Accounts 350-359)
remains directly assigned. Allocation of Distribution costs are unchanged.
E. Energy-Related Cost Allocation
The energy-related cost allocators, EMS and E10NS, are derived by averaging the normalized
energy values for each customer class with the normalized energy usage values weighted by the
marginal energy costs. First, summer and non-summer ratios based on each class's
proportionate share of the total normalized energy usage for the test year are determined.
Next, summer and non-summer ratios based on the monthly normalized energy usage for each
customer class weighted by the monthly marginal cost are calculated. Finally, these two values
are averaged, resulting in the E10S and E10NS allocators used in this study. This averaging
approach is consistent with the methodology used in the derivation of the demand-related
allocation factor D13.
1. Changes under the EFAC Method
EFAC makes no change to how energy-related costs are allocated.
II. Changes under the AED-4CP Method
AED-4CP makes no change to how energy-related costs are allocated.
Ill. Changes under the Hourly-Informed Method
Hourly-Informed incorporates energy-related elements embedded within Production and
Transmission through the hourly bulk-power allocation—hourly resource cost streams applied
to hourly class MWh across all 8,760 hours—rather than through E10S/E10NS. For
energy-related items outside the hourly Production/Transmission scope, there is no change in
allocation and E10S/E10NS continue to apply.
IV. Changes under the EFAC P&T Method
EFAC P&T makes no change to the use of E10S/E10NS for energy-classified Production. For
Transmission, EFAC P&T introduces an energy-based allocator E13 for the energy-classified
share of pooled Transmission Plant; E13 is constructed analogously to D13 but on energy by
averaging class shares of monthly served MWh with class shares of monthly served MWh
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Idaho Power Company Class Cost-of-Service Process Guide
weighted by monthly transmission marginal cost. This addition does not change the
construction or use of other energy-related allocators.
F. Customer-Related Cost Allocation
The principal customer accounting expenses which require allocation are meter reading
expenses, customer records and collections, and uncollectible accounts. The meter reading and
customer records and collection expenses are allocated based upon a review of actual practices
of the Company in reading meters and preparing monthly bills. The allocation of uncollectible
amounts is similarly based upon a review of actual Company data. Customer assistance
expenses are allocated based on the average number of customers in each class.
1. Changes under the EFAC Method
EFAC makes no change to how customer-related costs are allocated.
11. Changes under the AED-4CP Method
AED-4CP makes no change to how customer-related costs are allocated.
M. Changes under the Hourly-Informed Method
Hourly-Informed makes no change to how customer-related costs are allocated.
1V. Changes under the EFAC P&T Method
EFAC P&T makes no change to how customer-related costs are allocated.
G. State and Federal Income Tax Allocation
The state and federal income taxes for the Idaho jurisdiction are allocated to each customer
class and special contract customer according to each class's allocated share of rate base. Once
the state and federal income taxes are allocated to each customer class, they are functionalized
based on the functionalization of total rate base and expenses for each class.
1. Changes under the EFAC Method
EFAC makes no change to how state and federal income taxes are allocated.
11. Changes under the AED-4CP Method
AED-4CP makes no change to how state and federal income taxes are allocated.
M. Changes under the Hourly-Informed Method
Hourly-Informed makes no change to how state and federal income taxes are allocated.
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Idaho Power Company Class Cost-of-Service Process Guide
I V. Changes under the EFAC P&T Method
EFAC P&T makes no change to how state and federal income taxes are allocated.
VI. REVENUE REQUIREMENTAND
APPLICATION
Once all costs have been properly functionalized, classified, and allocated, the Company can
determine the revenue requirement for each customer class. The sales revenue required
includes return on rate base, total operating expenses, and incremental taxes computed using
the net-to-gross multiplier.
Page 20 of 20

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-07
IDAHO POWER COMPANY
ATTACHMENT 3

Idaho Power Company New Large Loads Considerations Memo
New Large Load
Considerations Memo
This memo describes considerations related to New Large Loads and summarizes relevant
approaches and emerging trends in other jurisdictions, as well as those already in place at Idaho
Power. The memo is included with the Company's filing in Case No. IPC-E-26-07, to support the
Commission's review of New Large Load (NLL) considerations and related cost-of-service issues,
consistent with Order No. 36892.
I. Why New Large Loads (NLLs) Are an Important Issue for Electric
Utilities
In Order No. 36892 (IPC-E-25-16), the Idaho Public Utilities Commission indicated that the
appropriate cost of service for New Large Load customers should be reviewed in this focused,
single-issue proceeding to ensure that other customer classes are not adversely affected as
identified by the Commission in Order No. 36892. Consistent with that direction, this Memo is
submitted for informational purposes only. It is intended to provide background, summarize
industry practices, and frame issues raised by stakeholders so as to inform and facilitate the
Commission's and parties' discussion of NLL considerations in this docket.
Across the country, electric utilities are facing sustained load growth that is both larger in
magnitude and faster in timing than what many systems were designed around.' New load led
by data centers, Al computing, manufacturing expansion, and widespread electrification is
arriving in quantities that differ from historical incremental growth patterns. Stakeholders have
stated that this trend may differ from traditional growth, both in its concentration and in its
systemwide impacts, and that existing cost-allocation frameworks may not always capture the
cost-causation dynamics created by these emerging loads.'These additions increase firm
capacity requirements, elevate annual energy needs, and can significantly alter the shape and
timing of system peaks. Because many of these loads arrive in large, discrete steps rather than
'See, e.g.,Andrew Satchwell et al., Electricity Rate Designs for Large Loads: Evolving Practices and Opportunities
(Lawrence Berkeley Nat'l Lab,Jan. 2025), https://eta-publications.lbl.gov/sites/default/files/2025-
01/electricity_rate_designs_for_large_loads_evolving_practices_and_opportunities_final.pdf;
Natalie Mims Frick&Vinita Srinivasan, Large Load Literature Review:November 2025 Update(Lawrence Berkeley
Nat'l Lab, Nov. 2025), https://eta-pubIications.Ib1.gov/sites/default/files/2025-
12/I b n I_I I I revi ew_n ov_u pd ate_2025_fi n a I.pdf
z For references to stakeholder positions or remarks throughout,see generally Case No. IPC-E-26-07,Attachment 1
—Stakeholder Comments to Petition (Mar. 31, 2026).
Page 1 of 16

Idaho Power Company New Large Loads Considerations Memo
slowly accumulating, they challenge planning frameworks built for gradual, geographically
diffuse growth.
A core consideration is that the operational characteristics of some emerging loads may differ
from those of traditional customer classes. Facilities such as hyperscale data centers can
operate at relatively high load factors, may require continuous service, and may have limited
tolerance for interruptions, which can affect daily and seasonal load shapes. Stakeholders,
including NWEC and CEO, have stated that these load profiles can reduce operational flexibility,
affect reserve and resource adequacy planning considerations, and may be associated with
incremental investments that differ in timing, cost, or scale from investments historically made
to serve existing customers. These factors can introduce additional complexity for system
planning and operations, particularly where load growth occurs in large, discrete increments.
Another challenge is the distinction between customer-specific infrastructure and broader
network impacts. While certain facilities require unique, dedicated assets (e.g., new substations
or radial transmission feeds), other upgrades may affect the shared transmission and
distribution network. Staff, CEO, and FEA have raised questions about how costs should be
attributed when large, concentrated loads drive substantial incremental upgrades on shared
infrastructure. Some stakeholders have cautioned that existing embedded allocators -
developed in the context of more diversified system growth - may not fully reflect the
magnitude, timing, or marginal cost characteristics of certain new investments associated with
concentrated load additions. Where these issues are raised, parties may contend that applying
embedded allocators to growth-driven upgrades could increase the potential for
cross-subsidization if costs associated with serving NLLs are recovered from customer classes
whose usage patterns did not materially contribute to those investments.
Utilities also face significant uncertainty in forecasting these loads. Factors such as evolving
technology choices, multi-phase buildouts, the emergence of"super-large loads," and changing
corporate strategies make it difficult to predict the timing, scale, and coincident contribution of
these loads to system peaks. Stakeholders, especially NWEC and CEO, emphasize that traditional
forecasting, which relies on gradual, predictable class-level growth, may underestimate the
rapid changes in system conditions caused by single projects. The mismatch between when
capacity must be built and when construction certainty is available can create planning and
investment risk, increasing the likelihood of either stranded assets or insufficient infrastructure.
Staff further notes that this dynamic can challenge the "known and measurable" and "used and
useful" standards if utility procurement must occur before customer commitments are firm.
Finally, utilities must manage financial and reliability exposure when large, high-impact
customers materially influence system planning outcomes. When commitments, timelines, or
operating characteristics shift, utilities may face risks associated with unused capacity, revised
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Idaho Power Company New Large Loads Considerations Memo
build schedules, or changes in system needs. Stakeholders have emphasized the need for
protective contractual commitments, including tools such as take-or-pay provisions or CIAC, to
avoid shifting NLL-driven risks to other customers. The scale of today's large loads means that
uncertainty or variability from even a single project can have system-level implications,
reinforcing stakeholder concerns that the regulatory framework should ensure that NLL-driven
costs are assigned to their cost causers, that planning signals are reliable, and that other
customer classes remain protected from undue cost shifts.
II. What Utilities Are Doing
A. Contractual commitments
In response to planning, reliability, and cost-allocation challenges posed by very large,
customer-driven load growth, utilities increasingly rely on contractual commitments to better
align project development with the timing and scale of utility investments. In many jurisdictions
this approach includes separate class treatment implemented through special contracts or
dedicated schedules. Utilities often use these provisions to reduce uncertainty and clarify risk
allocation when loads arrive in discrete steps, may evolve across multi-phase buildouts, and can
influence system needs on their own. In practical terms, these commitments convert variable
project signals into more defined inputs for planning, cost recovery, and operations, while
preserving Commission oversight.
At a high level, these arrangements typically combine minimum-billing (take-or-pay) provisions,
so customers pay for a defined share of subscribed capacity regardless of interim usage, with
credit and collateral requirements that mitigate exposure to nonpayment or project delay and
provide confidence that long-lived upgrades are supported by durable revenue streams. By
linking revenue recovery to reserved capacity, these provisions aim to align a customer's
contract demand with the infrastructure sized to serve it. Where utilities and regulators employ
separate class treatment through special contracts or dedicated schedules for very large loads,
the resulting administrative distinction is intended to ensure that load characteristics and
growth are observed distinctly in cost-of-service inputs and anchored to enforceable
contractual quantities, rather than speculative forecast.
In parallel, contract demand and ramp provisions define the amount of load a customer
commits to take and set resizing and notice rules that limit abrupt changes, often with long
notice periods aligned to procurement and construction lead times. Utilities commonly use
contract durations and staged ramp-up structures to phase arrivals over several years, while
exit-fee/make-whole concepts address the risk that investments made to serve a project could
otherwise be left under-recovered if plans change.
Page 3 of 16

Idaho Power Company New Large Loads Considerations Memo
Taken together, these commitments operate as a risk-management toolkit: they aim to provide
clearer planning signals, define financial responsibilities, and set operational expectations in
contexts where a handful of projects can have system-level implications. Results will vary by
design choice,jurisdiction, and project-specific facts, so these instruments are best understood
as tools to address identifiable risks, not as guarantees that all risks are fully resolved.
Examples of this approach being used are:
• AEP Ohio — Data Center Tariff(Docket 24-508-EL-ATA): Includes minimum billed
demand, ramp schedules, contract capacity limits, onsite-generation rules, and financial
assurance requirements.
• Indiana Michigan Power — Industrial Power Tariff(Docket 46097): Specifies long-term
contract durations, minimum billing demand, capacity resizing limits, credit and
collateral requirements, and exit fees.
• Black Hills Energy — Large Power Contract Service Tariff (Docket 20003-146-ET-15):
Defines minimum capacity commitments, market-based procurement above defined
thresholds, and credit support for performance.
• Xcel Energy Minnesota — Competitive Response Rider/Google ESA (Docket 19-39):
Uses negotiated service terms, termination payment obligations tied to utility
investments, and incremental-cost protection mechanisms.
• Duke Energy Indiana — Electric Service Agreement with Meta (Docket 45975): Involves
dedicated renewable supply arrangements with customer responsibility for transmission
costs and associated upgrades.
• Entergy Mississippi — Large Power Rate (Docket 2014-UN-132): Applies minimum load
thresholds and billing commitments for large-load customers to support system planning
and cost recovery.
• Dominion Energy — GS-5 High Load Customer Rate Class (Virginia SCC Approval, 2025):
Establishes 14-year contractual service obligations with 85% minimum demand charges
for transmission and distribution and 60% minimum demand for generation, along with
exit-fee liability for early shutdowns.
• Georgia Power — Large-Load (>100 MW) Billing Rule (Georgia PSC Rulemaking, Docket
55378): Authorizes minimum billing requirements, recovery of upstream transmission
and generation costs, and expanded contract lengths of up to 15 years for high-load
customers.
B. Direct Assignment
Direct assignment is a cost-treatment approach used to distinguish between investments that
are dedicated to serving an individual customer or project site and facilities that provide
broader, shared system benefits. Where a project requires customer-specific delivery assets (for
Page 4 of 16

Idaho Power Company New Large Loads Considerations Memo
example, new or expanded site substations, high-capacity radial feeders, or relocation work),
the costs of those assets may be assigned to the requesting customer rather than recovered
through systemwide allocators. By contrast, network-wide investments with shared reliability or
capacity benefits typically remain recovered through embedded cost-of-service allocation.
This treatment is commonly implemented through mechanisms such as contributions in aid of
construction (CIAC), advance payments, or similar arrangements under which the customer
finances or pre-funds facilities that would not otherwise be needed absent the request. In
practice, these mechanisms can be paired with construction or procurement agreements that
specify scope, timing, cost responsibility, and any true-up mechanisms.
Direct assignment is often used in circumstances where large, customer-driven infrastructure
requirements raise questions about whether customer-specific facility costs should be
recovered through embedded allocators, particularly where project timing, development
schedules, or long-term load levels involve uncertainty. In those circumstances, direct
assignment can reduce the extent to which costs for dedicated facilities are recovered from
other customers.
From a planning perspective, direct assignment and up-front funding mechanisms can address
timing mismatch issues where facilities must be built before long-term load levels are fully
realized. By linking customer commitments to funding for customer-specific facilities, this
approach can reduce exposure to underutilization risk for assets that would not otherwise be
built absent the project, while allowing time-sensitive upgrades to proceed in accordance with
project development schedules.
More broadly, direct assignment provides a way to describe the boundary between customer-
specific delivery facilities and shared network facilities for purposes of cost treatment. The
extent to which direct assignment addresses timing and cost-allocation concerns depends on
project facts, the design of applicable tariffs or contracts, and the relevant regulatory context.
Examples of this approach being used are:
• Dominion Energy — Large-Load Connection Queue Process Standards (Docket
PUR-2026-00011): Requires staged viability screening and engineering readiness steps,
with customer-specific facilities funded through direct assignment before placement
into the formal interconnection queue.
• Georgia Power — Large-Load (>100 MW) Billing and Cost-Responsibility Rule (Docket
55378, 44280): Includes direct assignment of certain site-specific delivery and upstream
transmission and generation costs to high-load customers, including CIAC-type
structures and minimum billing provisions during construction.
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Idaho Power Company New Large Loads Considerations Memo
• Black Hills Energy — Large Power Contract Service Tariff (Docket EL18-029): Provides for
direct assignment of incremental substations, distribution upgrades, and transmission
facilities required to serve large loads.
• Montana-Dakota Utilities — Electric Service Agreement with Leola Data Center (Docket
EL24-028): Includes customer funding of site-specific substation construction and
related delivery facilities through CIAC and direct assignment provisions.
• Pacific Gas & Electric (California) — Electric Rule 30, Transmission-Level Retail
Interconnection (A.24-11-007/ Interim Tariff): Provides an interim transmission-level
retail interconnection path that is conditioned on advance/actual cost payments
(including voluntary pre-funding of specific network upgrades), with refund/allowance
mechanics reserved for the final decision.
• Wisconsin Electric Power (We Energies) — Very Large Customer (VLC) Rate & Bespoke
Resources Tariff(PSCW Filing): Proposes a structure under which VLCs pay for the power
consumed and facilities/resources built to serve them, paired with long-term
service/resource agreements, with the stated objective of avoiding cost shifts to other
customers.
• AEP Ohio — Data Center Tariff(Docket 24-508-EL-ATA): Requires large data center
customers to fund project-specific delivery and interconnection infrastructure, including
load studies, site-specific facilities, and upgrade costs identified through the service-plan
process.
• Xcel Energy Minnesota — Very Large Load Tariff Initiative (E002/RP-24-67;
E002/CN-23-212; E-002/M-25-289): Includes a direct-assignment framework under
which very large customers fund interconnection and infrastructure upgrades (subject to
an incremental cost test and credit assurance provisions)
C. Growth-sensitive CCOS Allocations
As load growth becomes increasingly concentrated, variable in timing, and significant in
magnitude, some utilities are exploring growth-sensitive cost-of-service (COS) approaches to
distinguish between costs driven by new large loads and costs associated with the pre-existing
system. The motivation for these approaches is not to replace long-established allocation
methodologies, but rather to address circumstances in which rapid or spatially concentrated
growth may place pressure on traditional allocators to distinguish between embedded system
costs and incremental cost drivers.
Under these approaches, utilities seek to differentiate between:
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Idaho Power Company New Large Loads Considerations Memo
• Embedded, non-growth costs that support the existing system and would have been
incurred regardless of new customer additions; and
• Incremental, growth-driven costs that reflect measurable increases in class coincident
peaks, annual energy usage, or other load attributes over a defined lookback period.
In jurisdictions where these tools are being considered, stakeholders have raised concerns that
applying traditional allocation methods may, in certain scenarios, distribute a portion of the
higher marginal cost of new additions to customer classes whose usage profiles did not
materially drive the need for new investments. Growth-sensitive COS techniques are designed
as mechanisms to more closely align incremental cost responsibility with the classes or drivers
associated with recent system expansion, without altering the treatment of embedded costs
that continue to serve the existing system.
These growth-sensitive approaches provide an additional lens that some jurisdictions have used
to evaluate whether incremental costs associated with emerging large loads should be
distinguished from costs that pre-dated such growth, particularly in environments where system
expansion is occurring at a scale or pace that differs from historical patterns.
At a high level, currently proposed growth-sensitive frameworks tend to follow three steps:
1. Distinguish capacity that refreshes the existing portfolio (replacement) from capacity
that is added for new load; only the latter is treated as growth for allocation purposes.
2. Align the growth portion with measured drivers: allocate the growth-related portion of a
resource asset using a growth-sensitive metric (for example, based on changes in class
coincident peaks and/or energy over a multi-year lookback), while embedded assets
continue on established allocators.
3. Use clear class definitions and administrable rules so the data feeding the allocator
reflects enforceable commitments, while retaining established coincident peak (CP)
methods for embedded (non-growth) portions where continuity is important.
The two case studies that follow (APS and PGE) summarize examples of how growth-sensitive
overlay frameworks have been described in recent proceedings. APS emphasizes a
reliability-based gate, Effective Load Carrying Capability ("ELCC"), to delineate growth from
replacement, a Modified A&P for owned-growth assets, and a base-fuel reconciliation to avoid
re-averaging variable growth costs. PGE applies a PGM overlay for transmission and fixed
generation that uses a change in coincident peak (ACP) metric over a defined lookback, while
maintaining embedded allocators for the non-growth portion and strengthening contracting
requirements so allocator inputs are credible. In both applications, embedded assets remain on
existing allocators and only the incremental layer is assigned to measured growth drivers.
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Idaho Power Company New Large Loads Considerations Memo
Ill. Case Study: APS
Overview
In Docket No. E-01345A-25-0105, Arizona Public Service (APS) proposes a Growth-Based
Allocation Overlay (GBAO) that sits atop its traditional cost-of-service allocators to assign the
growth-related portion of certain production costs to customer classes based on measured
growth drivers, including extra-high-load-factor (XHLF) customers such as data centers. Under
existing practice, APS allocates existing production plant using the Commission-approved
Average & Peak (A&P) method within ACC jurisdiction and recovers fuel and purchased-power
costs through the Power Supply Adjustor (PSA). APS retains those allocators for non-growth and
replacement portions of costs and applies the GBAO only to the growth-driven portion of(1)
new owned/tolled generation (via a modified A&P overlay tied to measured growth in energy
and 4-CP) and (2) new PPAs/fuel (via a growth-in-sales share), with a Base Fuel Direct
Assignment approach described as a mechanism to avoid re-averaging growth costs across
customers.
APS states that recent large, high load factor additions have increased system requirements and
that resources procured to serve incremental growth are higher cost than embedded resources
already reflected in rates. APS further describes the overlay as allocating growth-related costs in
proportion to each class's measured contribution to growth (energy and coincident peaks),
rather than applying embedded allocators to the entire increment. APS pairs this framework
with contract-minimum safeguards (to reflect committed load when ramping lags) and
mechanism alignment in the PSA and System Reliability Benefit (SRB) so growth-related costs
are not redistributed through adjustor designs.
Description of the Methodology
APS identifies the portion of newly added production resources that is growth-related and
separates it from replacement needs using an ELCC-based reduction: the ELCC of retiring
resources is netted against the ELCC of new additions, and only the remaining ELCC is treated as
growth and enters the overlay. Costs associated with maintenance, end-of-life replacements,
corrective work, and policy-driven resources are classified as non-growth and continue to be
allocated by standard A&P and existing mechanisms.
Two functional categories are described:
• Owned/Tolled Generation (Fixed Production): The growth portion is allocated using a
Modified A&P overlay based on each class's Test-Year growth in energy (average
component) and 4-CP (peak component), grossed up for losses. The overlay result is
then added to the class's traditional A&P share for existing resources. For SRB-recovered
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Idaho Power Company New Large Loads Considerations Memo
plant, APS applies the same four-group Modified A&P to keep growth costs aligned in
adjustors.
• PPAs/Fuel (Variable Power): APS assigns new growth PPAs in proportion to each group's
share of Test-Year MWh growth (Residential; Other General Service; E-34/E-35; XHLF).
APS then implements a Base Fuel Direct Assignment approach: it computes a
base-fuel-without-growth rate and adds a class-specific direct-assignment adder so that
total base fuel by class equals the system average while preventing PSA re-averaging of
growth costs. The adder is updated annually in the PSA filing.
To align inputs with committed load, APS describes using contract minimum quantities for large
HLF customers if actual ramp lags and synchronizing SRB/PSA designs with the overlay so
growth-related costs are not later redistributed through uniform volumetric charges.
Illustrative Example
The following example shows how the growth overlay produces class-specific allocations for the
growth-related portion of fixed generation costs using APS's methodology.
Step 1—ELCC Reduction to Isolate the Growth Portion
A new block of fixed-generation capacity is added while legacy units retire during the same
window. Using ELCC, the retiring ELCC is netted against the new additions' ELCC. The result is
converted to a reduction percentage and applied to the total dollars of new plant to remove
the replacement share; only the growth share advances to the growth overlay.
Table 1. ELCC Reduction and Cost Split(Hypothetical)
Line Description Value
1 ELCC of new fixed-generation additions (MW) 300
2 ELCC of retiring resources (MW) 120
3 ELCC Reduction Factor (= L2 - L1) 40.0%
4 Total cost of new fixed-generation ($) $200.OM
5 Replacement cost (= L4 x L3) $80.OM
6 Growth-related cost (= L4 - L5) $120.OM
40% of the new capacity(by ELCC) is replacement and remains with standard A&P; 60% is
growth and becomes the $120.OM pool to be allocated by the growth overlay.
Step 2—Measure Test-Year Growth in Energy and 4-CP
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Idaho Power Company New Large Loads Considerations Memo
The growth overlay uses measured Test-Year growth by class in energy (average component)
and 4-CP (peak component), each expressed against system growth for that measure.
Table 2. Measured Test-Year Growth
Measure A System A Residential A Commercial A Industrial
Energy (GWh) 2,000 600 400 1,000
4-CP (MW) 200 48 42 110
Step 3—Convert to Shares and Form the Modified A&P Overlay
Each class's growth share is computed for energy and 4-CP, then combined in an A&P-style
blend. Here, a 50/50 weighting is used purely for illustration (other reasonable A&P weightings
could be applied).
Table 3. Growth Shares and A&P Allocation
Class Avg Share (Energy) Peak Share (4-CP) Blended (50/50)
Residential 600/2,000 = 30.0% 48/200 = 24.0% 27.0%
Commercial 400/2,000 = 20.0% 42/200 = 21.0% 20.5%
Industrial 1,000/2,000 = 50.0% 1101200 = 55.0% 52.5%
Step 4—Allocate the Growth Dollars (Fixed Generation, Growth Portion Only)
Apply the blended growth shares to the $120.OM growth pool from Step 1.
Table 4.Allocation of Growth-Related Fixed-Generation Dollars(Hypothetical)
Class Blended Share Allocation of$120.OM
Residential 27.0% $32.40M
Commercial 20.5% $24.60M
Industrial 52.5% $63.00M
These allocations represent only the growth slice of new fixed-generation costs. In the
complete production study, each class's replacement and embedded system costs remain on
standard A&P and are added to the amounts above to form the final production allocation.
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Idaho Power Company New Large Loads Considerations Memo
IV. Case study: PGE
Overview
In UM 2377, Portland General Electric (PGE) proposes a Peak Growth Modifier (PGM) as an
overlay to its traditional coincident-peak (CP) allocation methods for transmission and fixed
generation costs. Under existing practice, PGE allocates the full revenue requirement for these
functions using 12-CP for transmission and 4-CP for fixed generation. PGE retains those
allocators for the non-growth portion of costs applies the PGM only to the growth-related
portion of transmission and fixed generation revenue requirement.
PGE states that recent new large-load additions have contributed to increases in system
coincident peaks. Under the proposal, the growth-related portion of transmission and fixed
generation costs would be allocated in proportion to each class's measured contribution to
system peak growth over a defined lookback period. PGE describes this approach as intended to
align the cost allocation of growth-related costs with measured growth contributions while
retaining existing allocators for embedded (non-growth) portions of cost.
PGE also describes structural provisions intended to support the PGM and to align allocator
inputs with committed load rather than speculative requests, including:
• A dedicated Schedule 96 class so that large-load growth is separately observable in CP
and PGM calculations.
• Rule I provisions, such as minimum generation and transmission demand requirements,
system-capacity deposits with defined refund conditions tied to customer performance,
exceedance penalties, and exit/make-whole provisions; and
• An Energy Growth Modifier (EGM) so that increases in net variable power costs (NVPC)
attributable to load growth are assigned to the classes driving that growth and not
re-averaged across customers through volumetric rates.
PGE indicates that these provisions are intended to support the use of growth measures in the
PGM and to reduce the influence of uncommitted load signals on allocator inputs.
Description of the Methodology
For each of the two functional categories—Transmission and Fixed Generation — PGE identifies
the portion of recently added plant whose primary driver is system peak growth. Examples
include load-driven transmission upgrades, new or expanded substations for load pockets,
grid-enhancing technologies used to increase transfer capability, and new or upgraded
generation or storage resources needed for resource adequacy associated with higher peaks.
Costs associated with maintenance, end-of-life replacements, corrective work, and
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Idaho Power Company New Large Loads Considerations Memo
policy-driven resources are classified as non-growth and continue to be allocated by standard
CP methods.
Only costs in the growth category enter the PGM cost pool for each function. To calculate class
contributions to system peak growth, PGE uses a backward-looking period that initially spans
three years and proposes to expand this window annually until it becomes a rolling ten-year
period. As described by PGE, when the window reaches ten years, older assets fall outside of
the growth window and the remaining undepreciated balance of those assets reverts to
allocation by the standard CP method.
For each customer class, PGE computes the change in its contribution to12-CP for transmission,
and 4-CP for fixed generation over the lookback window. The change in class CP is compared to
the change in system CP over the same period. For each function (transmission 12-CP; fixed
generation 4-CP), each class's share of the growth-related revenue requirement is calculated as:
PGMShareClass(F) = OCPCLass(F)
ACPsystem(F)
The resulting shares are applied only to the growth portion of the functional revenue
requirement; the non-growth portion continues to be allocated using standard 12-CP or 4-CP
allocators. Under this structure, PGE describes the PGM as relying on measured growth
contributions rather than direct assignment of networked assets.
Illustrative Example
The following example shows how the PGM produces class-specific allocations for
growth-related transmission and fixed generation costs.
Step 1:Identify Growth-Related Revenue Requirement
Assume the following growth-related revenue requirement (RR) for assets placed in service
during the lookback:
• Transmission growth Revenue Requirement: $60 million
• Fixed Generation growth Revenue Requirement: $90 million
Step 2:Measure Coincident-Peak Growth over the Lookback
Assume the following measured changes:
Table 5. Customer Change in Coincident Peak(Hypothetical)
Function ASystem CP AResidential OCommercial 111ndustrial
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Idaho Power Company New Large Loads Considerations Memo
Transmission (12-CP) 200 MW 48 MW 42 MW 110 MW
Fixed Generation (4-CP) 220 MW 62 MW 36 MW 122 MW
These values reflect how much each class contributed to peak growth over the lookback period.
Step 3: Calculate Growth Shares
Transmission (12-CP):
• Residential: 48 - 200 = 24.0%
• Commercial: 42 _ 200 = 21.0%
• Industrial: 110- 200 = 55.0%
Fixed Generation (4-CP):
• Residential: 62 - 220 = 28.2%
• Commercial: 36 - 220 = 16.4%
• Industrial: 122 _ 220 = 55.5%
Step 4:Allocate the Growth-Related Revenue Requirement
Apply the growth shares to each function's PGM pool:
Transmission Growth RR (Pool = $60M):
• Residential: 24.0% = $14.40M
• Commercial: 21.0% = $12.60M
• Industrial: 55.0% = $33.00M
Fixed Generation Growth RR (Pool = $90M):
• Residential: 28.2% = $25.38M
• Commercial: 16.4% = $14.76M
• Industrial: 55.5% = $49.86M
These allocations represent only the growth-related portion of transmission and generation
costs. In full cost-of-service results, these PGM allocations would be added to each class's share
of the non-growth revenue requirement allocated under standard CP methods.
Idaho Power's Current Approach for NLL.
Idaho Power addresses new large load requests through a framework that begins with how
customers enter service under the applicable tariffs and, for loads at or above 20 megawatts,
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Idaho Power Company New Large Loads Considerations Memo
through Commission-approved special contracts. Customers with demand at or above one
megawatt may qualify for large-power service under Schedule 19 based on demand measured
over multiple billing periods, while customers with aggregate requirements above 20
megawatts receive service through special contract arrangements. These thresholds and service
pathways reflect the Company's practice of using standard tariff schedules for large-power
customers up to defined limits and using special contracts for larger, discrete loads with
project-specific characteristics.
When Idaho Power receives a request from a large prospective customer, Idaho Power
evaluates whether existing facilities can accommodate the requested demand at the required
voltage level. Where existing facilities are not sufficient, Idaho Power conducts engineering and
planning studies to identify substation, distribution, and transmission upgrades needed to
interconnect the load. These studies typically define the scope of work, cost estimates, and an
anticipated construction timeline. If the customer elects to proceed, Idaho Power may enter
into a Construction Agreement and, where applicable, a Procurement Agreement that specifies
responsibilities of each party and the customer's funding obligations for facilities that would
not otherwise be built absent the request. These up-front contributions (often referred to as
CIAC) are used to address customer-specific interconnection facilities and to support
procurement of long-lead equipment where needed.
While these agreements address customer-specific delivery facilities, generation and
networked transmission resources are planned and operated on a system basis. Idaho Power
incorporates large-load additions into its planning process once a customer demonstrates firm
intent—for example, through executed and funded agreements and a defined contract demand
schedule. Under this approach, resource planning evaluates system needs on an integrated
basis and does not typically assign new resources to an individual customer.
For customers exceeding the twenty-megawatt threshold, Idaho Power negotiates a
Commission-approved special contract (Energy Services Agreement) that establishes pricing
provisions and other terms relevant to the customer's expected load ramp and operating
characteristics. These contracts commonly include contract demand schedules and minimum
billing demand provisions (take-or-pay) that define billed quantities independent of short-term
variations in actual usage. Special contracts also include credit support provisions that address
default and payment risk, including requirements to demonstrate creditworthiness or provide
collateral (e.g., guaranty, letter of credit, or cash support) tied to contractual obligations, along
with provisions addressing early termination and related payment obligations.
Finally, embedded cost allocation for large loads is typically reflected through the general rate
case process once relevant facilities are in service and the associated costs and revenues are
included in the test year. Under Commission-approved allocation factors, the large load
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Idaho Power Company New Large Loads Considerations Memo
customer is allocated its share of embedded system production, transmission, and distribution
costs, in addition to customer-specific facilities addressed through direct assignment and up-
front funding arrangements.
VI. Potential Implications for Future GRCs
As new large loads become a more prominent feature of the system, future general rate cases
may devote increased attention to how class revenue responsibility reflects which customer
classes drive capacity additions and incremental energy procurement during periods of rapid
growth. Where load growth is concentrated rather than diffuse, parties may contend that
embedded allocation outcomes can obscure the extent to which incremental costs are
associated with a subset of customers whose usage expands more rapidly or is more coincident
with the hours that drive investment. In that context, the record may include additional
evidence on class load characteristics, observed coincidence with system conditions, and
documented growth patterns to support Commission evaluation of whether and how recent
growth should be reflected within the established cost-of-service framework.
Within that evidentiary baseline, parties may present growth-based allocation views that
distinguish a replacement (non-growth) portion from a growth-driven portion and align only
the latter with measured changes in class energy and coincident peaks over a defined lookback
period. Where such views are advanced, the record would typically describe the objective
criteria used to distinguish growth from replacement, specify the measurement window for
class growth, and explain how any growth portion is integrated with established allocators for
the non-growth share. The implication is evidentiary rather than prescriptive: these analyses
may help illustrate how class responsibility changes under a growth-sensitive lens and allow the
Commission to evaluate those movements against core standards such as cost causation,
cost-follows-benefit, and avoidance of undue discrimination.
Transmission treatment may also receive increased examination alongside production.
Stakeholders have suggested that transmission can contribute not only to peak adequacy but
also to energy enablement (e.g., access to markets and diversity exchanges), suggesting that
transmission benefits may be described in both capacity and energy dimensions. Where these
perspectives are raised, parties may seek to develop factual showings regarding when and why
transmission is required, which usage patterns contribute to that need, and how benefits flow
by class. Any resulting discussion of transmission classification or allocation would remain
within the Commission's discretion, but a more developed record on transmission could
influence how costs are assigned in circumstances where NLL growth affects both peak and
energy conditions.
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Idaho Power Company New Large Loads Considerations Memo
Contractual commitments can also shape the inputs that underlie allocators and test-year
conditions. As very large customers enter into agreements with features such as contract
demand schedules, minimum billing provisions (take-or-pay), notice and resizing provisions,
credit support, and termination protections, parties may point to these terms as indicators of
committed load that inform planning. Where present, such commitments may help clarify the
demand the utility plans for and reduce the potential that short-term differences between
forecast and realized usage shift costs to other classes; where they are less certain, parties may
emphasize evidence grounded in observed utilization and coincidence. In all cases, these
commitments do not determine the allocator; rather, they may stabilize or inform the
evidentiary baseline on which any allocator rests.
These considerations also interact with Idaho's long-standing distinction between
customer-specific facilities and networked system assets. Direct assignment and up-front
funding (CIAC) for site-specific delivery infrastructure are intended to keep those costs outside
embedded allocators, limiting their effect on class revenue responsibility. By contrast,
networked generation and transmission that provide benefits to all customers are typically
recovered through embedded cost-of-service allocation. Where parties dispute where that
boundary should be drawn for a given project, future records may place greater emphasis on
functional and operational evidence describing how facilities operate on the grid and where
their benefits accrue.
Finally, the Commission has indicated its interest in ensuring that the appropriate cost of
service for NLL customers is determined in a manner that does not adversely affect other
classes. That objective does not preordain any particular allocation outcome. Rather, it suggests
that future GRC records may increasingly present analyses that make two elements explicit: (1)
the evidentiary baseline regarding growth patterns, class coincidence, and transmission's
potential roles in capacity and energy; and (2) the extent to which growth-based allocation
views, direct assignment of customer-specific facilities, and enforceable contractual
commitments clarify which customers drive investment and how costs are attributed under
established regulatory standards.
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