20230601Direct Goralski.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC SERVICE IN THE STATE OF IDAHO AND FOR
ASSOCIATED REGULATORY ACCOUNTING TREATMENT.
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CASE NO. IPC-E-23-11

IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
PAWEL P. GORALSKI
GORALSKI, DI 1
Idaho Power Company
Q. Please state your name, business address, and 1
present position with Idaho Power Company (“Idaho Power” or 2
“Company”). 3
A. My name is Pawel (“Paul”) P. Goralski. My 4
business address is 1221 West Idaho Street, Boise, Idaho 5
83702. I am employed by Idaho Power as a Regulatory 6
Consultant in the Regulatory Affairs Department. 7
Q. Please describe your educational background. 8
A. In May of 2007, I received a Bachelor of 9
Business Administration degree in Finance from Boise State 10
University in Boise, Idaho. I have also attended “The 11
Basics: Practical Regulatory Training for the Electric 12
Industry,” an electric utility ratemaking course offered 13
through the New Mexico State University’s Center for Public 14
Utilities, “Electric Utility Fundamentals and Insights,” an 15
electric utility course offered by Western Energy 16
Institute, and “Electric Rates Advanced Course,” an 17
electric utility ratemaking course offered through the 18
Edison Electric Institute. 19
Q. Please describe your work experience with 20
Idaho Power. 21
A. In 2017, I was hired as a Regulatory Analyst 22
in the Company’s Regulatory Affairs Department, and in 2020 23
I was promoted to my current position of Regulatory 24
GORALSKI, DI 2
Idaho Power Company
Consultant. My primary responsibilities include supporting 1
the Company’s class cost-of-service (“CCOS”) activities, 2
developing pricing for special contract customers and other 3
large load pricing analysis, supporting the Company’s 4
annual Fixed Cost Adjustment (“FCA”) calculation, and 5
serving as the Company witness in that matter. I have also 6
been its witness for the Company’s annual Demand-Side 7
Management (“DSM”) prudency filings. 8
Q. What is the purpose of your testimony in 9
this matter? 10
A. My testimony will address derivation of the 11
Company’s 2023 CCOS study and the resulting recommendations 12
for customer pricing components. Specifically, my testimony 13
covers the following six areas: 1) CCOS - overview, 14
proposed modifications to methodology, description, and 15
study results, 2) allocation of CCOS-informed revenue 16
requirement to customer classes, 3) computation of the 17
Sales Based Adjustment Rate (“SBAR”) consistent with the 18
methodology described in the Settlement Agreement in Case 19
No. IPC-E-15-15,1 4) update to FCA components as informed by 20
the 2023 CCOS study and related rate design proposals, 5) 21
Special Contract pricing and rate design, and, 6) Schedule 22

1 In the Matter of Idaho Power Company’s Application for Approval of Computational Modifications to the True-Up Portion of the Power Cost Adjustment, Case No. IPC-E-15-15 (filed April 28, 2015; Final Order No. 33307 issued May 28, 2015).
GORALSKI, DI 3
Idaho Power Company
20 – High-Density Load (“Schedule 20”) pricing and update 1
on Schedule 20 customers and interruption compensation. 2
I. CLASS COST-OF-SERVICE OVERVIEW 3
Q. Please describe in general terms the process 4
used to prepare the class cost-of-service study. 5
A. There are two general steps used in 6
preparing a class cost-of-service study. The first step is 7
to determine the total costs of providing electric service, 8
adjusted for normal weather and water conditions. These 9
costs have been provided to me by Company Witness Ms. 10
Kelley Noe on Exhibit No. 35. The next step is to establish 11
a methodology for the separation of those costs among 12
customer classes. 13
Q. What methodology is used to separate costs 14
among customer classes? 15
A. The methodology for separating costs among 16
classes consists of a three-step process generally referred 17
to as functionalization, classification, and allocation. In 18
all three steps, recognition is given to the way in which 19
the costs are incurred by relating these costs to the way 20
in which the utility is operated to provide electrical 21
service. 22
Q. Please explain the meaning of 23
functionalization. 24
GORALSKI, DI 4
Idaho Power Company
A. Costs must be functionalized; that is, 1
identified with utility operating functions. Operating 2
functions recognize the different roles played by the 3
various facilities in the electric utility system. In the 4
Company’s accounts, these various roles are already 5
recognized to some degree, particularly in the recording of 6
plant costs as production-, transmission-, or distribution-7
related. However, this functional breakdown is not 8
sufficiently detailed for cost-of-service purposes. 9
Individual plant items are examined and, where possible, 10
the associated investment costs are assigned to one or more 11
operating functions, such as substations, primary lines, 12
secondary lines, and meters. This level of 13
functionalization allows costs to be more equitably 14
allocated among classes of customers. 15
Q. Please explain the meaning of 16
classification. 17
A. In addition to functionalization, 18
classification refers to the identification of a cost as 19
being either customer-related, demand-related, or energy-20
related. These three cost components are used to reflect 21
the fact that an electric utility makes service available 22
to customers on a continuous basis, provides as much 23
service, or capacity, as the customer desires at any point 24
in time, and supplies energy, which provides the customer 25
GORALSKI, DI 5
Idaho Power Company
the ability to do useful work over an extended period of 1
time. These three concepts of availability, capacity, and 2
energy are related to the three components of cost 3
designated as customer, demand, and energy, respectively. 4
In order to classify a particular cost by component, 5
primary attention is given to whether the cost varies as a 6
result of changes in the number of customers, changes in 7
demand imposed by the customers, or changes in energy used 8
by the customers. 9
Q. What are some examples of customer-, demand- 10
and energy-related costs? 11
A. Examples of customer-related costs are the 12
plant investments and expenses that are associated with 13
meters and service drops, meter reading, billing and 14
collection, and customer information and services, as well 15
as a portion of the investment in the distribution system. 16
These investments and expenses are made and incurred based 17
on the number of customers, regardless of the amount of 18
energy used, and are, therefore, generally considered to be 19
fixed costs. Demand-related costs are the fixed costs 20
associated with investments in generation, transmission, 21
and a portion of the distribution plant and the associated 22
operation and maintenance expenses necessary to accommodate 23
the maximum demand imposed on the Company’s system. Energy-24
GORALSKI, DI 6
Idaho Power Company
related costs are generally the variable costs associated 1
with the operation of the generating plants, such as fuel. 2
Q. What did you use as your primary guide in 3
classifying costs as either customer-, demand-, or energy-4
related? 5
A. I used the Electric Utility Cost Allocation 6
Manual, published January 1992, by the National Association 7
of Regulatory Utility Commissioners as my primary guide to 8
the classification of customer-, demand-, and energy-9
related costs. 10
Q. Please explain the process of allocation. 11
A. The process of allocation is one of 12
apportioning the total jurisdictional cost among classes by 13
introducing allocation factors into the process. An 14
allocation factor is nothing more than an array of numbers 15
that specifies the class value or share of a total 16
jurisdictional quantity. 17
Once individual costs have been allocated to the 18
various classes of service, it is possible to total these 19
costs as allocated and arrive at a breakdown of utility 20
rate base and expenses by class. The results are stated in 21
a summary form to measure adequacy of revenues for each 22
class. The measure of adequacy is typically the rate of 23
return earned on rate base compared to the requested rate 24
of return. 25
GORALSKI, DI 7
Idaho Power Company
Q. Have you provided separate documentation 1
describing in detail the methodology used to prepare the 2
Company’s class cost-of-service study? 3
A. Yes. Exhibit No. 36, the Class Cost-of-4
Service Process Guide, describes in detail the methodology 5
used in the preparation of the Company’s class cost-of-6
service study. 7
II. PROPOSED MODIFICATIONS TO THE COMPANY’S COST-OF-8
SERVICE METHODOLOGY 9
Q. Is the Company proposing modifications to 10
the CCOS study methodology most recently approved by the 11
Idaho Public Utilities Commission (“Commission”) in the 12
2008 general rate case (“GRC”) and that was also utilized 13
in the 2011 GRC? 14
A. Yes. I am proposing two modifications to the 15
CCOS methodology most recently approved by the Commission. 16
However, much of the study’s methodology remains consistent 17
with the 2008 and 2011 GRC CCOS studies.2 18
Q. Please describe the primary elements that 19
remain consistent between the 2023 CCOS and the study 20
prepared for the 2011 GRC. 21

2 In the Matter of the Application of Idaho Power Company for Authority
to Increase its Rates and Charges for Electric Service to its Customers
in the State of Idaho, Case No. IPC-E-11-08, Larkin DI (filed June 1, 2011).
In the Matter of the Application of Idaho Power Company for Authority to Increase its Rates and Charges for Electric Service, Case No. IPC-E-08-10, Tatum DI (filed June 27, 2008).
GORALSKI, DI 8
Idaho Power Company
A. Generally, the 2023 CCOS remains consistent 1
with the 2011 CCOS study, including, but not limited to: 2
• Demand-classified base-load serving generation 3
plant is allocated based on a monthly system 4
coincidence peak (“12CP”) allocator; 5
• The Company’s hydro and coal-fueled generation 6
plants are functionalized as base-load serving 7
generation resources, while the Danskin and 8
Bennett Mountain natural gas-fueled generation 9
plants are functionalized as peak-load serving 10
generation resources; 11
• Transmission plant is 100 percent demand-12
classified and allocated based on a 12CP, 13
marginal-cost weighted allocator; 14
• Energy-related cost allocators continue to be 15
derived based on an averaging approach 16
inclusive of marginal-cost weighting; 17
• The Company’s 12CP values, and each class’s 18
share of that value, is adjusted to add back 19
the impact of Demand Response, that is, system 20
load is representative of load as if no Demand 21
Response events had been called; and 22
• Classification of distribution plant between 23
demand and customer is based on a three-year 24
load duration curve. 25
GORALSKI, DI 9
Idaho Power Company
Q. Please describe the first modification made 1
to CCOS methodology. 2
A. As described by Company Witness Ms. 3
Aschenbrenner, analysis completed in support of the 4
Company’s upcoming 2023 Integrated Resource Plan indicates 5
there is a probability that high-risk hours occur into the 6
month of September. As a result, I recommend allocation of 7
peak-load serving resources be based on a summer period 8
June through September 4CP allocator, updated from the June 9
through August 3CP allocator utilized in the 2011 CCOS. The 10
four-month summer season better aligns with current and 11
future high-risk hours and the need to rely on peak-load 12
serving resources to meet those high-risk hours. 13
Q. Did the CCOS modification to extend the 14
summer season to include September impact all customer 15
classes? 16
A. No. Idaho Power’s Irrigation class service 17
schedule, Schedule 24, has previously utilized a different 18
seasonal definition than other rate schedules. While all 19
other Idaho Power rate schedules with seasonal rates have 20
previously defined the summer season as June through 21
August, the Irrigation customer class has historically 22
received a portion of cost allocation and rates based on a 23
summer period definition including September. The proposed 24
CCOS modification for summer-season baseload serving 25
GORALSKI, DI 10
Idaho Power Company
generation resources to be allocated on a June through 1
September period aligns cost allocation for the summer 2
season for all customer classes. 3
Q. Please describe the second recommended CCOS 4
modification. 5
A. In past studies, classification of Idaho 6
Power’s cost of generation - with respect to base-load 7
serving generation plant rate base, expenses, and power 8
supply expenses - has included both energy and demand 9
classification based on a jurisdictional load factor. That 10
is, if the Idaho jurisdictional load factor was 55 percent, 11
55 percent of baseload generation plant was classified as 12
energy, with amounts exceeding the jurisdictional load 13
factor classified as demand-related. 14
Idaho Power proposes to change classification 15
methodology such that energy and demand classification 16
follow a more “accounting-like” fixed cost versus variable 17
cost approach. All base-load serving generation fixed 18
accounting costs would be 100 percent demand classified, 19
and all variable expenses, such as fuel and purchased power 20
expenses, would be 100 percent energy classified. 21
Q. How does this impact the classification of 22
generation and power supply by FERC account? 23
A. Please see Table 1 for a comparison of main 24
FERC account classification under the recommended 25
GORALSKI, DI 11
Idaho Power Company
methodology and the Company’s previous methodology. Peak-1
load generation plant continues to be 100 percent demand-2
classified and fuel expense continues to be 100 percent 3
energy classified. For base-load serving generation plant: 4
hydro, steam, and natural-gas fueled, 100 percent of 5
generation plant is demand-classified. Power supply 6
expense, including account 555.0 purchased power, and 555.1 7
– PURPA are 100 percent energy classified. It should be 8
noted that while Table 1 is not a comprehensive list of 9
impacted FERC accounts (there are also impacts to composite 10
allocators that include the FERC accounts below), the list 11
identifies the primary accounts that drive changes in cost 12
assignment. 13
Table 1 14
Primary Production & Power Supply Expense FERC Account 15 Classification Comparison 16
FERC Prior Recommended
501 Steam Plant - Fuel 100% Energy 100% Energy
547 Other Generation - Diesel 100% Energy 100% Energy
547 Other Generation - Other Fuel 100% Energy 100% Energy
555.1 Purchased Power - Demand Response Incentives 100% Demand 100% Demand
17
Q. Why is the Company proposing this change in 18
classifying costs? 19
GORALSKI, DI 12
Idaho Power Company
A. Idaho Power has used, and the Commission has 1
approved, the use of a jurisdictional load factor to 2
classify base-load generation expense since the early 3
1980s. As explained by Ms. Aschenbrenner, the Company seeks 4
to modernize rate design to better align cost-causation 5
with fixed and variable components of Idaho Power’s cost 6
structures. Because the results of classification are used 7
to inform rate design, I am proposing a method to align 8
with the Company’s rate design objectives. 9
Q. What additional changes are incorporated in 10
the 2023 CCOS study? 11
A. There are several cost categories that are 12
new to the CCOS study since the Company’s 2011 GRC. The 13
more recent cost categories are described in detail in Mr. 14
Larkin’s testimony, and are allocated in the CCOS study in 15
the following manner: 16
• Other Production – Langley: base-load serving 17
generation; 100 percent demand-classified; 18
• 120 megawatt (“MW”) battery storage: base-load 19
generation; 100 percent demand-classified; 20
• Jackpot Power Purchase Agreement (“PPA”): 3 100 21
percent energy classified; 22

3 The Jackpot PPA is described in the Direct Testimony of Company Witness Ms. Jessica Brady.
GORALSKI, DI 13
Idaho Power Company
• Energy Imbalance Market expenses: follows 1
transmission plant allocation as the ability for 2
Idaho Power to access the market is determined by 3
transmission capacity; 4
• Western Resource Adequacy Program: also follows 5
transmission plant allocation for FERC account 6
561 – Transmission – Load Dispatching; 7
• Wildfire mitigation: wildfire mitigation supports 8
the Company’s overall electrical system and is 9
allocated based on a composite allocator for 10
generation, transmission, and distribution plant. 11
Q. Are there any other major changes to the 12
2023 CCOS study from the CCOS filed in the 2011 GRC? 13
A. Yes, the 2023 CCOS study separately 14
allocates costs to the on-site generation class for 15
Residential, Schedule 6, and Small-General service, 16
Schedule 8, as independent rate classes for cost 17
assignment. The Commission approved the creation of 18
Schedule 6 and 8 in 2018.4 These load statistics were 19
developed by the Company’s Load Research and Forecasting 20
Department and are described in workpapers filed by Mr. 21
Larkin. 22

4 In the Matter of the Application of Idaho Power Company for Authority to Establish New Schedules for Residential and Small General Service Customers with On-Site Generation, Case No. IPC-E-17-13, Order No. 34046 (May 9, 2018).
GORALSKI, DI 14
Idaho Power Company
Q. How are the clean energy aspects of Micron’s 1
Special Contract accounted for in the CCOS? 2
A. As described in Mr. Larkin’s testimony, 3
because costs and revenues from Micron’s payment for the 4
Black Mesa PPA are offsetting, they are excluded from the 5
Idaho jurisdictional revenue requirement, and are also 6
excluded from CCOS. While costs and revenues were excluded 7
from CCOS, derivation of the energy-allocator for Micron 8
was adjusted to exclude energy met by the Black Mesa 9
resource. That is, the energy service Micron requires from 10
Idaho Power is reduced by the forecast generation of the 11
Black Mesa PPA, consistent with the Special Contract 12
billing construct. This modification ensures Micron 13
receives its fair, allocable share of power supply expense 14
for the portion of load met by Idaho Power. 15
III. COST-OF-SERVICE STUDY DESCRIPTION 16
Q. Have you prepared a table that summarizes 17
the basis by which each of the major functionalized cost 18
categories has been classified and subsequently allocated 19
to customer classes under the CCOS? 20
A. Yes. The Table 2 summarizes the basis by 21
which each of the major functionalized cost categories is 22
classified and subsequently allocated to customer classes 23
under the CCOS:24
GORALSKI, DI 15
Idaho Power Company
Table 2 1
CCOS Classification and Functionalization Summary 2 Cost Category Classification Basis
Generation Plant
Demand
Other Production (Langley & Peaking Units) Demand
Transmission Plant
Distribution Plant Other Expenses
Demand
Cost Category Allocation Basis
Generation Demand

Other Production (Langley)

Units)
Demand
12CP without Marginal Generation Cost Weighting
4CP without Marginal Generation Cost Weighting
4CP without Marginal
Generation Energy Energy Cost Weighting (averaged w/ un-weighted
Transmission 12CP with Marginal
Transmission Cost Weighting
Distribution 1NCP / No. of Customers /
Direct Assignment
3
Q. Please identify the exhibits that comprise 4
the cost-of-service study. 5
GORALSKI, DI 16
Idaho Power Company
A. The cost-of-service study is comprised of 1
the following exhibits: 2
1. Exhibit No. 37, Functionalization and 3
Classification of Costs; 4
2. Exhibit No. 38, Summary of Functionalized 5
Costs; 6
3. Exhibit No. 39, Allocation to Classes; 7
4. Exhibit No. 40, Summary of Class Allocations; 8
5. Exhibit No. 41, Transfer Adjustment; 9
6. Exhibit No. 42, Revenue Requirement Summary; 10
7. Exhibit No. 43, Class Cost-of-Service Unit 11
Costs; 12
8. Exhibit No. 44, Marginal Cost Study 13
9. Exhibit No. 45, Development of Weighted Demand 14
and Energy Allocators; 15
10. Exhibit No. 46, Revenue Requirement 16
Adjustments. 17
Q. Please describe Exhibit No. 37. 18
A. Exhibit No. 37 contains 145 pages and 19
consists of 11 Cost Functionalization and Classification 20
Tables. The functionalization and classification of each 21
component of rate base, operating revenue, and expense are 22
treated in detail in these tables. The tables are shown in 23
the following sequence: 24
• Table 1 - Electric Plant in Service; 25
GORALSKI, DI 17
Idaho Power Company
• Table 2 - Accumulated Provision for 1 Depreciation; 2 3
• Table 3 - Additions and Deletions to Rate 4
Base; 5 6
• Table 4 - Operating Revenues; 7
• Table 5 - Operation and Maintenance 8 Expenses; 9 10
• Table 6 - Depreciation and Amortization 11 Expense; 12 13
• Table 7 - Taxes Other Than Income Taxes; 14
• Table 8 - Regulatory Debits/Credits; 15
• Table 9 - Income Taxes; 16
• Table 10 - Development of Labor-Related 17 Allocator; and 18 19
• Table 11 - Functionalization Allocators. 20
Q. What is the significance of the column header 21
“Allocator” on Exhibit No. 37? 22
A. This column identifies, by symbol, the basis 23
for each allocation. For example, for Accounts 310 through 24
316, Steam Production, shown at line 20 on page 1, the 25
constant “PI-S” is used to allocate the total investment in 26
steam production plant to the production function and to 27
the demand cost classifications. The resultant 28
functionalization of costs may itself serve as a basis for 29
subsequent allocations. This use is illustrated at line 119 30
on page 21 where the accumulated depreciation for steam 31
GORALSKI, DI 18
Idaho Power Company
production plant is allocated according to the same 1
allocator “PI-S” used at line 20. 2
Q. Please describe Exhibit No. 38. 3
A. Exhibit No. 38 summarizes in row format the 4
functionalized costs for each component of rate base and 5
expenses shown across the columns on Exhibit No. 37. 6
Q. Please describe Exhibit No. 39. 7
A. Exhibit No. 39 details the allocation of the 8
summarized costs shown on Exhibit No. 38 to each customer 9
class, including the Special Contract customers. The 10
exhibit also includes a summary of results showing the 11
actual rate of return earned for each customer class and 12
Special Contract customer. The exhibit includes the 13
following tables: 14
• Table 1 - Plant in Service; 15
• Table 2 - Accumulated Reserve for 16 Depreciation; 17 18
• Table 3 - Amortization Reserve; 19
• Table 4 – Substation Contributions in Aid 20
of Construction; 21
• Table 5 - Customer Advances for 22 Construction; 23 24
• Table 6 - Accumulated Deferred Income 25
Taxes; 26 27
• Table 7 - Acquisition Adjustment; 28
• Table 8 - Working Capital; 29
GORALSKI, DI 19
Idaho Power Company
• Table 9 - Deferred Programs; 1
• Table 10 - Subsidiary Rate Base; 2
• Table 11 - Plant Held for Future Use; 3
• Table 12 - Other Revenues; 4
• Table 13 - Operation & Maintenance 5
Expenses; 6 7
• Table 14 - Depreciation Expense; 8
• Table 15 - Amortization of Limited Term 9 Plant; 10
11
• Table 16 - Taxes Other Than Income; 12
• Table 17 - Regulatory Debits/Credits; 13
• Table 18 - Provisions for Deferred Income 14 Taxes; 15
16
• Table 19 - Investment Tax Credit 17 Adjustment; 18 19
• Table 20 - Construction Work In Progress; 20
• Table 21 - State Income Taxes; 21
• Table 22 - Federal Income Taxes; and 22
• Table 23 - Allocation Factor Summary. 23
Q. Does the Class Cost-of-Service Process Guide, 24
Exhibit No. 36, detail the manner in which you allocated 25
the summarized costs shown on Exhibit No. 38 to each class 26
of service as shown on Tables 1 through 22 of Exhibit No. 27
39? 28
A. Yes. Exhibit No. 36, the Class Cost-of-Service 29
Process Guide, details the majority of the allocation 30
GORALSKI, DI 20
Idaho Power Company
methodology that was applied to produce the results shown 1
on Tables 1 through 22 of Exhibit No. 39. 2
Q. What additional allocation methodology was 3
included in the CCOS to produce the summarized costs shown 4
on Exhibit No. 42? 5
A. As described by Mr. Larkin, the Jurisdictional 6
Separation Study includes three additional revenue 7
requirement line items: 1) Bridger revenue requirement, 2) 8
Valmy revenue requirement, and 3) revenue requirement 9
offset for battery projects to be installed in 2023. 10
Revenue requirements for those three items were allocated 11
to customer classes consistent with other base-load serving 12
generation plant. Please see Exhibit No. 46 Revenue 13
Requirement Adjustments for each class’s calculated 14
allocable share. The result of that class allocation for 15
the three revenue requirement items is listed by customer 16
class on row 45 of Exhibit No. 42 Revenue Requirement 17
Summary. 18
A second allocation was included to spread to 19
customer classes the transfer adjustment described by Mr. 20
Larkin. The total value of the Energy Efficiency Rider 21
labor adjustment and update to Power Cost Adjustment 22
(“PCA”)-related items were allocated to customer classes in 23
the same manner as they would be incurred. Exhibit No. 41, 24
GORALSKI, DI 21
Idaho Power Company
Transfer Adjustment, computes the base revenue transfer for 1
each customer class. 2
Q. Does Exhibit No. 39 include a listing of the 3
allocation factors used to allocate to classes the various 4
costs shown on Tables 1 through 22? 5
A. Yes. Table 23 of Exhibit No. 39 includes a 6
listing of each allocation factor. 7
Q. Have you included information regarding the 8
derivation of the Company’s updated marginal costs with 9
your testimony? 10
A. Yes. I have included a copy of the Company’s 11
2023 Marginal Cost Analysis Study as Exhibit No. 44. 12
Q. Have the marginal costs been used to develop 13
the Company’s revenue requirement? 14
A. No. The marginal costs have been used solely 15
for purposes of developing allocation factors and not for 16
purposes of developing the Company’s revenue requirement. 17
Q. Have you prepared an exhibit that details the 18
derivation of the demand and energy allocation factors used 19
in the cost-of-service study? 20
A. Yes. Exhibit No. 45 details the derivation of 21
the allocation factors D10S, D10NS, D10P, D13, E10S, and 22
E10NS used in the CCOS.23
GORALSKI, DI 22
Idaho Power Company
IV. COST-OF-SERVICE STUDY RESULTS 1
Q. Please describe Exhibit No. 42. 2
A. Exhibit No. 42 is the revenue requirement 3
summary based on the results of the proposed CCOS study. 4
The section headed “Revenue Requirement for Rate Design” 5
details the sales revenue required from each customer class 6
and special contract customer. The sales revenue required 7
includes return on rate base, total operating expenses, and 8
incremental taxes computed using the net-to-gross 9
multiplier of 1.347 provided by Ms. Noe. 10
Q. Have you prepared an exhibit quantifying the 11
impact from the recommended CCOS modifications? 12
A. Yes, Exhibit No. 47 to my testimony includes 13
the results of the 2023 CCOS study and the three 14
supplemental CCOS studies. The exhibit is presented with 15
the first section representing a CCOS study consistent with 16
the 2011 GRC methodology; the two subsequent sections 17
independently list the incremental change to revenue 18
requirement by class from that respective modification. 19
Finally, the combined impact of the modifications and the 20
2023 CCOS class revenue requirement results are listed in 21
the fourth section. 22
Q. Please summarize the major impacts to 23
customer classes from the recommendations. 24
GORALSKI, DI 23
Idaho Power Company
A. The greatest impact is to the Irrigation 1
customer class, which is primarily driven by shifting to a 2
four-month summer season for all customer classes, and 3
results in a reduction in revenue deficiency of $3.7 4
million (as compared to the 2011 GRC methodology) from this 5
modification. However, while each class experiences a 6
slight change to revenue requirement from the two proposed 7
changes, the greatest percentage total impact is a 2.65 8
percent reduction in revenue deficiency for the Irrigation 9
class, nearly all due to the four-month summer season, with 10
almost all other classes experiencing less than 1 percent 11
impact to revenue requirement from the proposed methodology 12
changes. 13
Q. Please summarize the results of the class 14
cost-of-service study that are detailed on Exhibit No. 42. 15
A. The results shown on Exhibit No. 42 indicate 16
that the Residential (“Schedule 1”), Residential On-Site 17
Generation (“Schedule 6”), Small General Service (“Schedule 18
7”), Small General Service On-Site Generation (“Schedule 19
8”) Irrigation Service (“Schedule 24”), and Traffic Control 20
Lighting Service (“Schedule 42”) should have an increase in 21
rates that is greater than the overall average increase 22
requested by the Company. In addition, the results indicate 23
that Large General Service – Primary & Transmission 24
(“Schedules 9P and 9T”), Dusk to Dawn Lighting (“Schedule 25
GORALSKI, DI 24
Idaho Power Company
15”), Municipal Street Lighting (“Schedule 41”), and 1
Special Contract customer J. R. Simplot Company Pocatello, 2
Idaho (“Simplot Pocatello”) (“Schedule 29”) should have a 3
decrease in rates from the current level. 4
V. REVENUE REQUIREMENT ALLOCATION 5
Q. What is the Company’s general ratemaking 6
philosophy on determining class-specific revenue 7
requirement and the resulting customer rates? 8
A. The Company’s primary approach to ratemaking 9
in the last several GRCs has been to establish rates that 10
reflect costs as accurately as possible. Accordingly, the 11
Company’s ratemaking proposals usually advocate movement 12
toward cost-of-service results, which assign costs to those 13
customer classes that cause the Company to incur the costs. 14
Q. Are there other objectives that may be 15
considered in the ratemaking process? 16
A. Yes. The Commission may consider a number of 17
other objectives, such as rate stability, in the 18
determination of rates. 19
Q. How did you approach the determination of 20
the revenue requirement for each customer class? 21
A. As I described above, a pure cost-of-service 22
revenue requirement spread would result in larger increases 23
for certain classes relative to the overall average 24
increase. In order to mitigate the magnitude of the maximum 25
GORALSKI, DI 25
Idaho Power Company
rate increase any class would experience, the Company is 1
proposing to cap the percentage increase to any customer 2
class at one and one-half times the overall average 3
requested increase, or 12.91 percent (8.61 percent X 1.5 = 4
12.91 percent). As proposed, Large General Service – 5
Primary & Secondary, Dusk to Dawn Lighting, Municipal 6
Street Lighting and the Simplot Pocatello Special Contract 7
receive neither a decrease nor an increase in rates. 8
Q. Did you discuss the results of the CCOS 9
study internally before deciding to apply the 12.91 percent 10
caps to the specified customer classes? 11
A. Yes. I discussed the results of the CCOS and 12
potential rate spread scenarios with Company Witness Mr. 13
Timothy Tatum, who is responsible for the overall 14
preparation of this case. My revenue allocation is the 15
result of those discussions. 16
Q. Was the revenue allocation process affected 17
by the clean energy aspects of Micron’s Special Contract? 18
A. No. Micron’s revenue targets were developed 19
for the portion of service Idaho Power provides. 20
Q. Does the overall 12.91 percent cap also 21
apply to new customer classes Schedule 6 and 8? 22
A. Not explicitly. However, consistent with the 23
direction provided by Ms. Aschenbrenner, the Residential 24
and Residential On-Site Generation customer classes were 25
GORALSKI, DI 26
Idaho Power Company
combined prior to determining the revenue target. The same 1
occurred for Small General Service and its On-Site 2
Generation counterpart. As further discussed in the Direct 3
Testimony of Company Witness Mr. Grant Anderson and Company 4
Witness Mr. Zack Thompson, respectively, rate design was 5
developed such that Schedule 1 and Schedule 6 share the 6
same service charge and energy rates, with that also being 7
the case for Schedule 7 and Schedule 8. 8
Q. Do you have an exhibit that details the 9
class revenue requirement determination? 10
A. Yes. Exhibit No. 48 is a five-page exhibit 11
that steps through the revenue requirement allocation 12
process from the CCOS results to the ultimate proposal for 13
each customer class. Page 1 of Exhibit No. 48 presents the 14
proformed normalized test year sales and revenues and 15
transfer adjustment by customer class. Page 2 details the 16
results from the CCOS study and illustrates the revenue 17
changes that would be made to each customer class to obtain 18
the CCOS results. Page 3 shows the revenue shortfall that 19
resulted by applying the 12.91 percent cap to combined 20
Small General Service classes, Irrigation, and Traffic 21
Control Lighting, and no decrease to Large General Service 22
– Primary & Secondary, Dusk to Dawn Lighting, Municipal 23
Street Lighting, or Simplot Pocatello Special Contract. 24
Page 5 shows the final proposed increase to customer 25
GORALSKI, DI 27
Idaho Power Company
classes that resulted from spreading the revenue shortfall 1
created by the 12.91 percent cap, no increase or decrease 2
to Large General Service – Primary & Secondary, Dusk to 3
Dawn Lighting, Municipal Street Lighting, or Simplot 4
Pocatello Special Contract. The results from page 5 were 5
utilized in determining the individual rates for the 6
Company’s general tariff and special contract customers. 7
Q. Did you also provide the results of the CCOS 8
to the Company’s rate design witnesses for use in the 9
Company’s rate design proposals along with the revenue 10
targets from Exhibit No. 48? 11
A. Yes. I provided the CCOS unit costs, 12
detailed on Exhibit No. 43, to Mr. Anderson, Mr. Thompson, 13
and Company Witness Mr. Riley Maloney for use in 14
determining the rates for their respective service 15
schedules. 16
Q. Please describe Exhibit No. 43. 17
A. Exhibit No. 43 shows the unit cost for each 18
function for metered service schedules as determined 19
through the CCOS study. The billing units shown in the 20
column labeled “(F)” reflect the billing demands, 21
normalized billing energy, basic load capacity, and number 22
of billings. 23
Q. Are you proposing any other changes to cost 24
recovery? 25
GORALSKI, DI 28
Idaho Power Company
A. Yes, As discussed by Mr. Tatum, the Company 1
is proposing to reduce the Energy Efficiency Rider 2
(“Rider”) collection percentage to 2.25 percent from 3.10 3
percent. Exhibit No. 41 includes derivation of the proposed 4
2.25 percent Rider collection percentage, with Rider 5
collection projected to be $31.6 million, just slightly 6
above the current funding level when also considering the 7
$3.5 million of labor-related cost that will be collected 8
in base rates. 9
VI. SALES BASED ADJUSTMENT RATE 10
Q. Please describe in general terms the purpose 11
of the SBAR? 12
A. The SBAR is a part of the PCA mechanism that 13
is intended to eliminate recovery of power supply expenses 14
associated with load growth resulting from changing weather 15
conditions, a growing customer base, or changing customer 16
use patterns. 17
Q. Please describe the SBAR methodology 18
approved by the Commission in Order No. 33307. 19
A. Commission Order No. 33307 directs the 20
Company to calculate the SBAR based on the energy 21
classified portion of embedded production revenue 22
requirement as established in the CCOS. The final SBAR is 23
calculated by dividing this portion of revenue requirement 24
by the Idaho kilowatt-hour (“kWh”) sales for the test year. 25
GORALSKI, DI 29
Idaho Power Company
1
Q. Are any additional modifications to 2
calculate the SBAR necessary as part of the 2023 CCOS 3
determination? 4
A. Yes. The Commission’s Order adopted 5
Commission Staff’s (“Staff”) recommendations for the PCA 6
treatment of the renewable portion of Micron’s billing 7
construct, 5 which accepted the proposed treatment described 8
in Ms. Aschenbrenner’s testimony filed in Case No. IPC-E-9
22-06:6 10
Further, any energy requirements met by the 11 Renewable Resource will not be included in the PCA 12
sales based adjustment (SBA) and will not be used 13 in the derivation of the future PCA rates. All 14
Supplemental Energy supplied to Micron will be 15 included in the PCA, SBA and used for PCA rate 16 derivation purposes. 17
18 Accordingly, the Black Mesa PPA power supply expense 19
is excluded as part of the SBAR energy-related generation 20
function revenue requirement, and the portion of Micron’s 21
energy that Black Mesa meets under the Special Contract 22
billing construct is also excluded from test year retail 23
sales. 24
Q. What is the resulting SBAR? 25
A. By applying the methodology established by 26

5 In the Matter of Idaho Power Company’s Application for Approval of a Replacement Special Contract with Micron Technology, Inc. and a Power
Purchase Agreement with Black Mesa Energy, LLC., Case No. IPC-E-22-06, Order No. 35482 (August 1, 2022); Staff Comments pg. 18.
6 Case No. IPC-E-22-06, Aschenbrenner DI, pg. 20.
GORALSKI, DI 30
Idaho Power Company
Commission Order No. 33307 in Case No. IPC-E-15-15, and for 1
the Micron clean energy component of their Special Contract 2
components by Order No. 35482, the SBAR should be increased 3
from the requested level of $26.72 in Case No. IPC-E-15-15 4
to $31.29 per megawatt-hour. 5
Q. Have you prepared an exhibit that details 6
the derivation of the revised SBAR? 7
A. Yes. Exhibit No. 49, details the derivation 8
of the $31.29 SBAR amount. 9
VII. FIXED COST ADJUSTMENT RATES 10
Q. Please describe the FCA mechanism. 11
A. The FCA is a rate mechanism that is designed 12
to remove the financial disincentive to utility acquisition 13
of demand-side management resources. The mechanism 14
accomplishes this goal by severing the link between energy 15
sales and the recovery of fixed costs. The FCA applies to 16
customer classes that only include energy and service 17
charges in their retail billing components, Residential 18
Service (Schedules 1, 3, 5, and 6) and Small General 19
Service (Schedule 7, and 8). The annual FCA amount is 20
determined according to the following formula: 21
FCA = (CUST X FCC) – (ACTUAL X FCE) 22
Where: 23
FCA = Fixed Cost Adjustment; 24
CUST = Actual number of customers, by class; 25
GORALSKI, DI 31
Idaho Power Company
FCC = Fixed Cost per Customer, by class; 1
ACTUAL = Actual Billed kWh Energy Sales, by 2
class; and 3
FCE = Fixed Cost per Energy, by class. 4
Q. What values are required to calculate the 5
FCA amount annually? 6
A. As outlined in the above formula, for each 7
class (Residential Service and Small General Service), the 8
actual number of customers (“CUST”), the fixed cost per 9
customer (“FCC”), actual energy (“ACTUAL”), and the Fixed 10
Cost per Energy (“FCE”) are required to determine the FCA 11
amount. Two of these variables (CUST and ACTUAL) are 12
determined at the end of each year based upon the Company’s 13
actual billing records. The other two variables (FCC and 14
FCE) are updated each time the Company files a GRC and are 15
based on the results of the CCOS study. 16
Q. Since granting permanency for the FCA 17
mechanism in Order No. 32505 in 2012,7 has the Commission 18
authorized any additional changes? 19
A. Yes. First, the Commission approved a 20
Settlement Stipulation in 2015 that replaced the use of 21
weather-normalized data with actual sales in determination 22

7 In the Matter of the Application of Idaho Power Company for Authority to Convert Schedule 54 – Fixed Cost Adjustment – from a Pilot Schedule to an Ongoing Schedule, Case No. IPC-E-11-19, Order No. 32505 (March 30, 2012).
GORALSKI, DI 32
Idaho Power Company
of the FCA deferral.8 Second, in 2021 the Commission 1
approved separate, and reduced fixed cost tracking for 2
customers considered “new,” defined in the Order to be 3
customers added after January 1, 2022.9 The Commission’s 4
rationale stated that the modification “eliminates fixed 5
cost recovery due to new customer growth for investments 6
best determined in a general rate case.”10 7
Q. Beginning with the 2024 FCA deferral, who 8
will be considered a “new” customer? 9
A. The FCC and FCE rates will be reset based on 10
outcomes of this GRC, as such, “new” customers will also be 11
reset to be those customers added starting January 1, 2024, 12
when proposed GRC rates go into effect. 13
Q. Are you proposing any additional 14
modifications to the FCA as part of this proceeding? 15
A. Yes, I am proposing two additional 16
modifications. First, because Schedule 6 and Schedule 8 are 17
now separate rate classes in the CCOS study with individual 18
cost assignment and independent class statistics, I 19
recommend separate determination of use per customer 20
(“UPC”), FCC, and FCE for these customer classes. 21

8 In the Matter of the Commission’s Inquiry into Idaho Power Company’s Fixed Cost Adjustment Mechanism, Case No. IPC-E-14-17, Order No. 33295 (May 6, 2015).
9 Idaho Power Company’s Application for Modification of the Fixed Power Cost Adjustment, Case No. IPC-E-21-39, Order No. 35273 (Dec. 28, 2021).
10 Order No. 35273, pg. 4.
GORALSKI, DI 33
Idaho Power Company
Next, I am proposing separate determination for the 1
UPC and FCE applied to customers taking service under the 2
Proposed Schedule 5, Residential Service Time-of-Use Plan 3
(“Schedule 5”). Cost assignment for Residential customers 4
is completed on a composite group including Schedule 1, 3, 5
and 5 customers and the FCC is calculated based on class 6
statistics from this composite group. However, UPC for 7
Schedule 5 is approximately 50 percent higher than the 8
average Residential Service (Schedule 1) standard service 9
customer. To appropriately track actual sales against a UPC 10
basis, a class-specific UPC basis should be utilized. 11
For the FCE, derivation independent from composite 12
Residential FCE rates should be utilized because of the 13
proposed Schedule 5 rate design. As detailed in Mr. 14
Anderson’s testimony, the Company is pursuing an update to 15
Schedule 5 time-of-use rates such that on- and off-peak 16
energy rates maintain a four-to-one price differential in 17
the summer season, and 1.5-to-one price differential in the 18
non-summer season. That is, the summer on-peak energy rate 19
will be four times the summer off-peak energy rate, and the 20
non-summer on-peak energy rate will be 1.5 times the non-21
summer off-peak energy rate. Neither differential aligns 22
with CCOS-informed rates, thus the FCE for Schedule 5 23
incorporates a matching four-to-one differential for 24
summer, and 1.5-to-one differential for non-summer 25
GORALSKI, DI 34
Idaho Power Company
consumption, such that changes to Schedule 5 energy 1
consumption in response to price signals between on- and 2
off-peak periods recognize the embedded level of fixed 3
costs in each time period. Schedule 5 customers who shift 4
use from the on-peak period to the off-peak period do not 5
receive an under- or over-collection of fixed costs between 6
energy rates and the FCA mechanism because the FCE includes 7
a four-to-one, and 1.5-to-one differential, respectively. 8
Q. Is the Company proposing changes to how 9
annual FCA rates that recover the FCA deferral are set and 10
applied to customer classes? 11
A. No. Annually, the FCA deferral will be 12
tracked for five customer segments: Schedule 1 & 3, 13
Schedule 5, Schedule 6, Schedule 7, and Schedule 8. The 14
determination of annual FCA rates combines the Residential 15
and Small General Service customer segments first, and sets 16
the percentage change on an overall basis, not on a class-17
segment basis. FCA rates will continue to be set only at 18
the total Residential (Schedule 1, 3, 5, and 6) segment, 19
and Small General Service (Schedule 7, and 8) segment. 20
Q. Have you updated the FCC and FCE rates as 21
part of this GRC proceeding? 22
A. Yes. I have updated the new and existing 23
customer FCC and the FCE rates using the functionalized and 24
classified revenue requirement from the 2023 CCOS, and 25
GORALSKI, DI 35
Idaho Power Company
proposed Service Charge collection effective January 1, 1
2024. The updated FCC and FCE rates have been included in 2
the revised Schedule 54, Fixed Cost Adjustment. 3
Q. Please describe the process used to 4
determine the FCC and FCE rates for the FCA mechanism, 5
which have been submitted as part of this GRC proceeding. 6
A. The FCC and FCE rates submitted as part of 7
this GRC proceeding are based upon the 2023 test year. 8
These rates most accurately represent the Company’s current 9
fixed costs. Exhibit No. 50, Tables I, II, III, IV, and the 10
Schedule 5 FCE derivation detail the computational process 11
that was used to determine these class-specific fixed-cost 12
amounts. 13
The first step in this process is a determination of 14
the 2023 test year fixed cost recovery embedded in the 15
energy charges for Residential Service and Small General 16
Service customers. As can be seen on Exhibit No. 50, Table 17
III, column J, for Residential Service, $367,032,962 of 18
fixed costs are to be recovered from residential customers 19
through energy charges, and $8,715,991 for Residential On-20
Site Generation customers. For Small General Service, 21
$8,266,319 of fixed costs are to be recovered from the 22
energy charges, and $27,218 for Small General Service On-23
Site Generation customers. 24
Q. Do these fixed cost amounts for the 25
GORALSKI, DI 36
Idaho Power Company
Residential class include more than their actual class cost 1
of service? 2
A. Yes. There is a difference between the class 3
cost of service numbers and the amount of requested revenue 4
requirement. This difference is a result of the cross-class 5
subsidies that are currently present in the Company’s rate 6
structure. The total cross-class subsidies, as well as the 7
fixed cost portion of those subsidies, are identified on 8
Exhibit No. 50, Table II. 9
Q. Why is it important to include these fixed 10
cost subsidies for the Residential class? 11
A. When fixed costs are recovered through a 12
volumetric rate, the effects of any energy efficiency 13
program that reduces energy consumption result in lost 14
recovery of those fixed costs. In the case of the 15
Residential classes, the reduction of energy consumption 16
through energy efficiency not only prevents the Company 17
from recovering the fixed costs associated with those 18
classes, but in addition, prevents the fixed cost recovery 19
of the other inter-class subsidies that are embedded in 20
Residential energy rates. 21
Q. How are the class-specific fixed cost 22
amounts established in the initial step used to derive the 23
updated FCC rates? 24
A. The determination of the FCC rate utilizes 25
GORALSKI, DI 37
Idaho Power Company
the annual average number of customers for the Residential 1
customer class and Small General Service customer class. 2
As can be seen on Exhibit No. 50, Table III, column A, the 3
2023 average number of customers are 492,481 for the 4
Residential customer class, 13,288 for the Residential On-5
Site Generation class, 30,401 for the Small General Service 6
customer class, and 88 for the Small General Service On-7
Site Generation class. 8
With these two principal base level values, the FCC 9
rate can be determined. The annual fixed costs recovered 10
through the energy charges divided by the 2023 average 11
number of customers results in an annual fixed cost 12
recovery per customer, or the FCC rate, shown on Exhibit 13
No. 50, Table III, column K. For the Residential class, the 14
annual fixed cost recovery per customer is $745.27 15
($367,032,692 / 492,481), and $655.94 for the Residential 16
On-Site Generation class ($8,715,991 / 13,288). For the 17
Small General Service class, the annual fixed cost recovery 18
per customer is $271.91 ($8,266,319 / 30,401), and $311.07 19
for the Small General Service On-Site Generation class 20
($27,218 / 88). 21
For new customers, those added starting January 1, 22
2024, the Fixed Cost per Customer – Distribution (“FCC-23
DIST”) only includes distribution function fixed costs. The 24
table below lists the corresponding FCC-DIST for each of 25
GORALSKI, DI 38
Idaho Power Company
the FCA classes. 1
Table 3 2
New Customer FCC-DIST 3
Customer Group
Total Distribution & Customer Fixed 2023 Avg.
Residential 125,476,059 492,481 $254.78
Residential On-Site Generation 3,620,717 13,288 $272.49
Small General Service 3,257,318 30,401 $107.15
Small General Service On-Site
Generation 12,337 88 $140.99 4
Q. How are the class-specific fixed cost 5
amounts established in the initial step used to derive the 6
updated FCE values? 7
A. The determination of the FCE rate utilizes 8
the Residential and Small General Service weather-9
normalized energy consumption for the 2023 test year. As 10
can be seen on Exhibit No. 50, Table III, column B, the 11
2023 weather-normalized annual energy consumption for the 12
Residential customer class is 5,425,559,433 kWh, 13
122,912,496 kWh for Residential On-Site Generation 14
customers, 138,285,160 kWh for the Small General Service 15
class, and 370,708 kWh for the Small General Service On-16
Site Generation class. 17
The annual fixed cost recovered through the energy 18
charges divided by the normalized energy results in an 19
annual fixed cost recovery per kWh, or the FCE rate, shown 20
on Exhibit No. 50, Table III, column L. Matching FCC-DIST 21
determination for new customers, the FCE-DIST determination 22
GORALSKI, DI 39
Idaho Power Company
for new customers added starting January 1, 2024, only 1
includes distribution-related fixed costs. Existing 2
customer FCE and new customer FCE-DIST are listed in Table 3
No. 4 for each of the FCA classes. Derivation of FCE-DIST 4
is shown on Exhibit No. 50, Table IV. 5
Table 4 6 FCE and FCE-DIST 7
Customer Group
Total Fixed Cost Revenue from
Residential (Schedule 1, and 3) 367,032,962 5,425,559,433 $0.067649
Residential On-Site Generation 8,715,991 122,912,496 $0.070912
Small General Service 8,266,319 138,285,160 $0.059777
Small General Service On-Site
Generation 27,218 370,708 $0.073423
Fixed Cost Revenue from
Residential (Schedule 1, and 3) 125,476,059 5,425,559,433 $0.023127
Residential On-Site Generation 3,620,717 122,912,496 $0.029458
Small General Service 3,257,318 138,285,160 $0.023555
Small General Service On-Site
Generation 12,337 370,708 $0.033278 8
Q. Please describe Schedule 5 FCE and FCE-DIST 9
derivation. 10
A. The kWh sales forecast for Schedule 5 11
customers is multiplied by the Residential FCE to determine 12
the actual fixed cost collection through the energy charge 13
in the forecast. That resulting value is removed from the 14
amount of energy sales revenue forecast for Schedule 5, 15
with the amount remaining considered to be the energy cost 16
in energy revenue. Energy cost in energy revenue is 17
seasonalized based on CCOS-informed summer/non-summer 18
GORALSKI, DI 40
Idaho Power Company
energy cost ratio. Finally, the energy cost in energy 1
revenue for that season is allocated to the on-peak and 2
off-peak period based on the time-of-use billing 3
determinants, with the per-energy unit cost retaining a 4
four-to-one differential in the summer, and 1.5-to-one 5
differential in the non-summer season. The proposed energy 6
rates from Mr. Anderson’s workpapers are reduced for the 7
corresponding per-energy unit seasonal energy cost in 8
energy revenue to calculate a matching differential 9
Schedule 5 FCE rate. The process is replicated for the FCE-10
DIST for new Schedule 5 customers. Page 5 of Exhibit No. 50 11
is the workpaper supporting derivation of Schedule 5 FCE 12
and FCE-DIST rates. 13
Q. How do the FCC and FCE computed in this 14
filing compare to the FCC and FCE established in the 15
Company’s last general rate case, IPC-E-11-08? 16
A. Both the FCC and FCE rates are greater than 17
those currently in effect, which were established using the 18
functionalized classified revenue requirement data in the 19
Company’s last filed general rate case, Case No. IPC-E-11-20
08. The Company has made significant investments in its 21
infrastructure since that time, and the newly calculated 22
FCC and FCE rates reflect those fixed costs that are being 23
recovered through the Residential and Small General Service 24
energy charges. 25
GORALSKI, DI 41
Idaho Power Company
VIII. SPECIAL CONTRACT CUSTOMERS 1
Q. Please provide an overview of the Company’s 2
Special Contract customers and how rate design was 3
developed. 4
A. There are six Special Contract customers and 5
associated rate design proposals included in my testimony. 6
First, I will review rate design proposals for Idaho 7
Power’s three long-standing Special Contract customers, 8
Micron, Simplot Pocatello (Schedule 29), and the United 9
States Department of Energy (“DOE”). Second, I will discuss 10
development of rates for J. R. Simplot Company Caldwell, 11
Idaho (“Simplot Caldwell”) (Schedule 32), whose 2015 12
Special Contract became active at the end of April 2023 13
when it exceeded the 20 MW threshold for it to become 14
effective. Finally, I will describe CCOS methodology and 15
rate design for future Special Contract customers Brisbie, 16
LLC (“Brisbie”) and Lamb Weston. 17
Q. What are the Company’s rate design proposals 18
for the long-standing Special Contract customers, Micron, 19
Simplot Pocatello, and the DOE? 20
A. The Company is proposing to maintain the 21
current rate structures for the active Special Contract 22
customers Micron, Simplot Pocatello, and DOE, but move the 23
rate design components toward CCOS-informed amounts when 24
increasing forecast collections to recover the revenue 25
GORALSKI, DI 42
Idaho Power Company
requirement shown on Exhibit No. 48. This includes 1
reestablishing the Contract Demand charge for Micron and 2
Simplot Pocatello based on the same methodology the Company 3
recently included in the Brisbie11 and Lamb Weston 4
contracts. 5
Q. Please describe the derivation of Micron’s 6
and Simplot’s Pocatello Contract Demand rates. 7
A. Consistent with the method most-recently 8
reviewed by the Commission as a reasonable basis for 9
Contract Demand rates approved for Brisbie, and proposed 10
for new Special Contract customer Lamb Weston, I propose 11
Micron and Simplot Pocatello’s Contract Demand rate is 12
based on costs derived from the Company’s Open Access 13
Transmission Tariff (“OATT”) rate effective October 1, 14
2022. The OATT-based Contract Demand reflects the 15
reservation cost that any other customer would pay on Idaho 16
Power’s system. To account for collection of costs by the 17
Contract Demand charge, the Billing Demand rate is adjusted 18
to collect any remaining fixed costs not collected through 19
the Contract Demand charge. 20
Q. What other rate design elements for Micron, 21
Simplot Pocatello, and DOE are proposed to be updated based 22
on CCOS results? 23

11 In the Matter of Idaho Power’s Application for Approval of Special Contract and Tariff Schedule 33 to Provide Electric Service to Brisbie,
LLC’s Data Center Facility, Case No. IPC-E-21-42, Goralski DI, p. 13.
GORALSKI, DI 43
Idaho Power Company
A. I propose that the energy rate for Micron, 1
Simplot Pocatello, and DOE match the CCOS-informed energy 2
rate. This proposed change aligns rate design with cost 3
causation by recovering only variable costs through the 4
energy charge. 5
Q. Have you included rate design workpapers for 6
Micron, Simplot Pocatello, and DOE? 7
A. Yes, Exhibit No. 51 includes rate design 8
workpapers for all six Special Contract customers, current 9
and future. 10
Q. Please describe the Simplot Caldwell Special 11
Contract pricing and CCOS analysis. 12
A. As noted earlier, in late April 2023 Simplot 13
Caldwell crossed the 20 MW customer load threshold to 14
activate their Special Contract. Idaho Power endeavors that 15
the GRC test year uses the best information available to 16
the Company at the time of development. For Simplot 17
Caldwell, while their Special Contract was approved in 18
2015, prior to April, Simplot Caldwell had not previously 19
exceeded the threshold to begin taking service under their 20
Special Contract rates. Because historical customer usage 21
has remained slightly below their forecast usage and they 22
remained a Schedule 19 customer since approval of the 23
Special Contract, Idaho Power included Simplot Caldwell as 24
part of the Schedule 19 customer class in the 2023 GRC test 25
GORALSKI, DI 44
Idaho Power Company
year load forecast, consistent with customer load until 1
late April 2023. 2
For Simplot Caldwell, I completed pricing analysis 3
by first removing their Schedule 19 load statistics from 4
the CCOS study, and then added back their customer-provided 5
Special Contract forecast load as an individual customer to 6
complete cost assignment. This is similar to the approach 7
Idaho Power has utilized when pricing new Special Contract 8
customers between GRC, which is in alignment with the 9
Commission's direction provided in Case No. IPC-E-13-23.12 10
Q. Was additional consideration required as 11
part of developing Simplot Caldwell’s proposed rate design? 12
A. Yes. It’s important to distinguish the rates 13
and revenue collection forecast for Simplot Caldwell in the 14
2023 GRC test year, which are based on Schedule 19 rates 15
and a lower, historical usage profile, versus the higher 16
load forecast assumptions for cost assignment as a Special 17
Contract. In the CCOS analysis, the historical basis 18
Simplot Caldwell collections under Schedule 19 are 19
approximately $6.7 million, while the revenue requirement 20
based on their higher, Special Contract load forecast is 21

12 In the Matter of the Application of Idaho Power Company for Approval
of a Special Contract with J.R. Simplot Company, Case No. IPC-E-13-23, Order No. 33038 at 12 (May 19, 2014) (". . . we find that a rate utilizing cost-of-service as a starting point for negotiation is consistent with prior Commission Orders and is fair, just and reasonable.")
GORALSKI, DI 45
Idaho Power Company
$9.97 million. However, because Simplot Caldwell has 1
existing Schedule 32 rates, rate design was evaluated by 2
using current Schedule 32 rates applied to the higher, 3
Simplot Caldwell load forecast used in the completion of 4
the Special Contract CCOS cost assignment. 5
Q. What is the resulting revenue requirement 6
change and proposed rate design for Simplot Caldwell? 7
A. I propose to increase Simplot Caldwell’s 8
revenue requirement by $6,518 to bring them up to CCOS 9
results, as revenue collection under existing Schedule 32 10
rates and the forecast Special Contract load are nearly 11
aligned with Simplot Caldwell’s cost assignment. Consistent 12
with rate design proposed for Micron and Simplot Pocatello, 13
I propose to update Simplot Caldwell’s Contract Demand rate 14
to be OATT-based, and for the energy rate to match CCOS. 15
Q. How was pricing developed for future Special 16
Contract customer Lamb Weston, which is an Idaho Power 17
tariff Schedule 19P customer today? 18
A. Idaho Power recently filed an application to 19
enter into a Special Contract with Lamb Weston in 20
recognition of their forecast load exceeding 20 MW in July 21
2023.13 However, Lamb Weston’s current load is less than 20 22
MW, and the 2023 CCOS test year data includes Lamb Weston 23

13 In the Matter of Idaho Power’s Application for Approval of Special Contract and Tariff Schedule 34 to Provide Electric Service to Lamb
Weston, Inc., Case No. IPC-E-23-18, filed May 23, 2023.
GORALSKI, DI 46
Idaho Power Company
as part of Schedule 19 load statistics, consistent with the 1
level of service they currently receive from Idaho Power. 2
Similar to Simplot Caldwell, I completed pricing 3
analysis by first removing Lamb Weston’s Schedule 19 load 4
statistics from the CCOS study, and then added back their 5
future, customer-provided Special Contract steady-state 6
forecast load as an individual customer to complete cost 7
assignment. 8
Q. Why didn’t the Company include Lamb Weston 9
as a Special Contract customer in the GRC test year to 10
develop rates? 11
A. Lamb Weston is in the process of a plant 12
expansion at its facility in American Falls and is forecast 13
to exceed the Schedule 19 service eligibility threshold in 14
the second half of 2023 but not complete expansion until 15
mid-2024. Due to uncertainty associated with the exact 16
timing of that expansion, it is appropriate to include Lamb 17
Weston’s forecast Special Contract system utilization in a 18
future GRC test year once that usage has been achieved. 19
If Lamb Weston was removed from the Schedule 19 test 20
year load statistics but remained a Schedule 19 customer 21
after the GRC, the total Schedule 19 class would be under-22
assigned costs, which would instead be allocated to all 23
other Idaho Power customer classes. There is inherent 24
regulatory lag when pricing new, proposed Special Contract 25
GORALSKI, DI 47
Idaho Power Company
customers and the future point in time when all customer 1
rates are re-balanced. The process Idaho Power followed to 2
price Lamb Weston’s Special Contract rates incorporates the 3
best-known, historical information for this customer at the 4
time of GRC filing. 5
Q. Please describe Lamb Weston’s rate design 6
components. 7
A. As described in more detail in the Company’s 8
recent filing for Commission approval of the Lamb Weston 9
Special Contract, Case No. IPC-E-23-18, Lamb Weston’s 10
Special Contract rates incorporate a two-block, embedded 11
and marginal-cost-based pricing structure. Block 1 12
represents the first 20 MW of Lamb Weston’s load and is 13
priced at Schedule 19 – Primary retail rates, and Lamb 14
Weston’ load exceeding 20 MW is priced on an embedded cost 15
basis for capacity and marginal cost basis for energy. 16
Because block 1 references Schedule 19 rates, I propose 17
mirroring the rates proposed by Mr. Anderson for Schedule 18
19. The marginal energy cost portion of Lamb Weston’s 19
second block is based on an annual power supply cost 20
forecast consistent with the PCA test year, with proposed 21
marginal cost rate updates to occur at an annual interval 22
in the spring with updated effective marginal energy rate 23
each June 1st. My rate design focuses on the block 2 demand 24
charge, which is the sole component that is determined by 25
GORALSKI, DI 48
Idaho Power Company
CCOS for Lamb Weston as a class of one. 1
Q. What is the resulting proposed block 2 2
Billing Demand Charge for Lamb Weston? 3
A. Lamb Weston’s block 2 Billing Demand is 4
proposed to be $23.80 per kW. This represents recovery of 5
Lamb Weston’s CCOS revenue requirement, which will not be 6
recovered under either block 1 rate components or the 7
Contract Demand charge. 8
Q. How was pricing for Brisbie developed for 9
their Special Contract rates? 10
A. Brisbie is forecast to come online beyond 11
the test year period and as a result, no 2023 CCOS customer 12
class adjustment was necessary to remove test year load for 13
Brisbie. Similar to the methodology described in my 14
testimony in the case to establish the current Brisbie, 15
Schedule 33 rates,14 for the loads that fall under the 16
embedded portion of Brisbie’s second block, Brisbie 17
received their load ratio share of embedded capacity costs 18
for a 30 MW steady-state operation assumption. 19
Brisbie’s block 1 rates are fully-embedded and based 20
on Schedule 19 – Transmission retail rates, which have been 21
updated to match the proposed rates for Schedule 19 22

14 In the Matter of Idaho Power’s Application for Approval of Special
Contract and Tariff Schedule 33 to Provide Electric Service to Brisbie, LLC’s Data Center Facility, Case No. IPC-E-21-42, Goralski DI, p. 21-42.
GORALSKI, DI 49
Idaho Power Company
provided by Mr. Anderson. Following the terms of the 1
Brisbie Special Contract, the Contract Demand Charge, and 2
Daily Excess Demand Charge have been updated based on the 3
OATT rates in effect October 1, 2022. The remainder of 4
Brisbie’s block 2 rates are contractually established in 5
the Brisbie Special Contract and follow an update schedule 6
independent of updates to the Company’s CCOS study. 7
Q. What is the resulting proposed block 2 8
Billing Demand Charge for Brisbie? 9
A. Brisbie’s block 2 Billing Demand is proposed 10
to be $22.07 per kW. This represents recovery of Brisbie’s 11
CCOS revenue requirement which will not be recovered under 12
either block 1 rate components or the Contract Demand 13
charge. 14
IX. SCHEDULE 20 PRICING 15
Q. Does the Company currently have any Schedule 16
20 customers, or are any included in the 2023 test year? 17
A. No. While Idaho Power continues to respond 18
to prospective customers that are exploring service under 19
Schedule 20, there are no active customers taking service 20
under Schedule 20, thus none were included in the 2023 test 21
year. 22
Q. Please provide an update on any Schedule 20-23
related active Commission proceedings. 24
A. As directed by the Commission, on December 25
GORALSKI, DI 50
Idaho Power Company
28, 2022, Idaho Power filed an Application recommending two 1
proposals for the Commission’s consideration on what, if 2
any, compensation for mandatory interruption should be 3
applicable to Schedule 20 customers.15 The case is currently 4
ongoing with a deadline for Staff and public comments of 5
June 7, 2023, and a June 21, 2023, Company Reply Comment 6
deadline. 7
Q. Is the Company proposing any changes to 8
Schedule 20 rates as part of this GRC? 9
A. Yes. While the Company believes embedded 10
rate components should remain based on underlying Schedule 11
9 and 19 rates as designed until sufficient Schedule 20 12
customers have joined Idaho Power’s system to complete 13
class-specific cost assignment, Idaho Power recommends 14
updating the marginal energy component basis of Schedule 15
20, and aligning to the time-of-use periods with those 16
proposed for Schedule 9 and 19. 17
As recommended by Staff,16 and adopted by the 18
Commission,17 the Company agreed18 that evaluation and 19
comparison of methods other than DSM Avoided Cost Averages 20

15 In the Matter of Idaho Power’s Application for Authority to Establish Compensation for the Mandatory Interruption Requirement of Schedule 20
– Speculative High-Density Load, Case No. IPC-E-22-30.
16 In the Matter of the Application of Idaho Power Company for Authority
to Establish a New Schedule to Serve Speculative High-Density Load
Customers, Case No. 21-37, Staff Comments, p. 6.
17 Case No. IPC-E-21-37, Order 35428, p. 7.
18 Case No. IPC-E-21-37, Idaho Power Reply Comments, p. 5.
GORALSKI, DI 51
Idaho Power Company
for setting the Schedule 20 energy rates should be 1
completed prior to filing the Company’s next (this) GRC. An 2
evaluation is critical to ensure that referenced marginal 3
prices best reflect costs the Company is actually incurring 4
and are recovered through the PCA, which would not be 5
collectable from Schedule 20 as the PCA rate does not apply 6
to Schedule 20 energy sales priced at a marginal rate. 7
Idaho Power met with Staff on January 20, 2023, and 8
again on February 2, 2023, to discuss the results of Idaho 9
Power’s evaluation and to solicit Staff’s feedback. 10
Subsequent to the two discussions, Staff provided a memo, 11
included as Exhibit No. 52, outlining five general criteria 12
that should be considered when developing marginal cost-13
based customer energy rates: 14
• The resources used in a model for determining 15
marginal cost should be based on the resources 16
that are highly likely to exist during the rate 17
period. 18
• The amount of incremental load used to 19
determine the marginal cost rate should reflect 20
the amount of incremental load for the portion 21
of load that will be priced at marginal cost. 22
• The marginal cost rates should have enough 23
granularity to reflect time difference (e.g. 24
seasonality, time of day) value of Marginal 25
GORALSKI, DI 52
Idaho Power Company
Cost within the Company’s system to provide 1
accurate price signals. 2
• If the marginal cost rates are based on a 3
forecast, due to the lack of marginal costs 4
being trued-up in the PCA, they should be 5
updated often enough that they reflect current 6
conditions or find a way to true up the 7
marginal cost to actual marginal cost. 8
• If market costs are used, cost of transmission 9
transaction and wheeling costs should be 10
included. 11
Q. What marginal cost basis does Idaho Power 12
propose for Schedule 20’s energy rates? 13
A. In replacement of the current DSM Avoided 14
Cost Average-based marginal rates, the Company proposes to 15
use an AURORA-based method. This achieves several of the 16
criteria noted in Staff’s memo including granularity to 17
reflect time differences, costs based on resources likely 18
to exist during the rate period, and more frequent updates 19
to reflect more current market conditions than DSM Avoided 20
Cost Averages. 21
The marginal cost of energy is determined from the 22
simulated hourly operation of the Company’s power supply 23
system over forecast hydro conditions. Net power supply 24
expenses are first quantified using the Company’s expected 25
GORALSKI, DI 53
Idaho Power Company
load for the test year, then an incremental load increase 1
is added to determine the resulting increase in power 2
supply expenses and generation. The difference in monthly 3
power supply expenses between the initial and subsequent 4
simulation is divided by the difference in generation to 5
produce a marginal cost per kWh. 6
Q. What are the resulting marginal energy 7
rates, and at what interval does the Company propose to 8
make updates? 9
A. The proposed seasonal, time-of-use marginal 10
rates are as follows: 11
TABLE 6 12 Proposed Seasonal – Time of use Marginal Rates 13
SONP ($/kWh) $ 0.068108
SMP ($/kWh) $ 0.095308
SOFP ($/kWh) $ 0.050374
NSONP ($/kWh) $ 0.048629
NSMP ($/kWh) $ 0.068321
NSOFP ($/kWh) $ 0.057180
14
The Company proposes Schedule 20 energy rates be updated 15
annually on June 1 using a forward test year consisting of 16
the 12-month period April through the subsequent March, 17
consistent with power cost spring filings. 18
Q. Does this conclude your direct testimony in 19
this case? 20
A. Yes, it does. 21
// 22
GORALSKI, DI 54
Idaho Power Company
DECLARATION OF PAWEL P. GORALSKI 1
I, Pawel P. Goralski, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Pawel P. Goralski. I am employed 4
by Idaho Power Company as a Regulatory Consultant in the 5
Regulatory Affairs Department. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony and Exhibit Nos. 36 through 52 8
in this matter. 9
3. To the best of my knowledge, my pre-filed 10
direct testimony and exhibits are true and accurate. 11
I hereby declare that the above statement is true to 12
the best of my knowledge and belief, and that I understand 13
it is made for use as evidence before the Idaho Public 14
Utilities Commission and is subject to penalty for perjury. 15
SIGNED this 1st day of June 2023, at Boise, Idaho. 16
17 Signed: _________________________ 18 PAWEL P. GORALSKI 19
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