20230601Direct Larkin.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
MATTHEW T. LARKIN
LARKIN, 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 Matthew T. Larkin. My business 4
address is 1221 West Idaho Street, Boise, Idaho 83702. I am 5
employed by Idaho Power as the Revenue Requirement Senior 6
Manager in the Regulatory Affairs Department. 7
Q. Please describe your educational background. 8
A. I received a Bachelor of Business 9
Administration degree in Finance from the University of 10
Oregon in 2007. In 2008, I earned a Master of Business 11
Administration degree from the University of Oregon. I have 12
also attended electric utility ratemaking courses, 13
including the Electric Rates Advanced Course, offered by 14
the Edison Electric Institute, and Estimation of 15
Electricity Marginal Costs and Application to Pricing, 16
presented by National Economic Research Associates, Inc. 17
Q. Please describe your work experience with 18
Idaho Power. 19
A. I began my employment with Idaho Power as a 20
Regulatory Analyst in January 2009. As a Regulatory 21
Analyst, I provided support for the Company’s regulatory 22
activities, including compliance reporting, financial 23
analysis, and the development of revenue forecasts for 24
regulatory filings. 25
LARKIN, DI 2
Idaho Power Company
In January 2014, I was promoted to Senior Regulatory 1
Analyst where my responsibilities expanded to include the 2
development of complex cost-related studies and the 3
analysis of strategic regulatory issues. 4
Since becoming the Revenue Requirement Senior 5
Manager in March 2016, I have overseen the Company’s 6
regulatory activities related to revenue requirement, such 7
as power supply expense modeling, jurisdictional separation 8
studies, and Idaho Power’s Open Access Transmission Tariff 9
formula rate. 10
I. OVERVIEW 11
Q. What is the purpose of your testimony in this 12
proceeding? 13
A. The purpose of my testimony is to present the 14
forecast methodologies that were applied to the Company’s 15
2022 financial data to arrive at the 2023 forecasted 16
financial levels. Further, my testimony will describe the 17
instructions that I provided to Company Witnesses Ms. 18
Jessica G. Brady, Ms. Kelley Noe, and Ms. Paula Jeppsen 19
with regard to the normalizing, annualizing, and other 20
regulatory adjustments required to arrive at the 2023 test 21
year revenue requirement. 22
Q. How is your testimony organized? 23
A. My testimony begins with an overview of 24
direction I received from Vice President of Regulatory 25
LARKIN, DI 3
Idaho Power Company
Affairs Mr. Timothy E. Tatum regarding the development of 1
the Company’s 2023 Test Year (“2023 Test Year” or “Test 2
Year”). I then detail two specific adjustments to the 3
Company’s 2023 Test Year regarding the recovery of costs 4
related to Idaho Power’s defined benefit pension plan and 5
the recovery of non-fuel coal-related costs. Next, I 6
discuss the broader methodologies utilized by the Company 7
to forecast the remainder of the test year components. My 8
testimony concludes with a summary of the direction I gave 9
to other Company witnesses in developing the 2023 Test 10
Year, and a quantification of the Company’s requested Idaho 11
jurisdictional revenue requirement. 12
Q. Did you consult with Mr. Tatum, Vice President 13
of Regulatory Affairs, regarding the development of the 14
2023 Test Year? 15
A. Yes. The 2023 Test Year development 16
methodology presented in my testimony is a direct result of 17
numerous discussions with Mr. Tatum. 18
Q. Did Mr. Tatum provide you with any specific 19
instructions or guidance regarding the development of the 20
test year presented in this proceeding? 21
A. Yes. Mr. Tatum instructed me to develop a 22
2023 Test Year based on 2022 actual financial data in a 23
manner similar to that presented to the Idaho Public 24
Utilities Commission (“Commission”) in the Company’s last 25
LARKIN, DI 4
Idaho Power Company
general rate case, IPC-E-11-08 (“2011 Rate Case”). 1
However, Mr. Tatum instructed me to deviate from the 2
methodology used in the 2011 Rate Case in a number of 3
specific areas. 4
First, Mr. Tatum instructed me to set the recovery 5
of 2023 Test Year pension expense at approximately $35 6
million, an increase above the level currently reflected in 7
rates of $17 million. Second, Mr. Tatum directed me to 8
maintain the North Valmy Power Plant (“Valmy”) and the Jim 9
Bridger Power Plant (“Bridger”) non-fuel coal-related cost 10
recovery at current levels, with the exception of 11
collection related to previously deferred revenue 12
requirement amounts. Third, Mr. Tatum directed me to update 13
base net power supply expenses (“NPSE”) to be included in 14
base rates and tracked through the Power Cost Adjustment 15
(“PCA”) on a going forward basis. Fourth, Mr. Tatum 16
instructed me to hold non-labor operations and maintenance 17
(“O&M”) expense at 2022 levels with specific adjustments 18
for known and measurable changes. Fifth, Mr. Tatum 19
instructed me to hold test year levels of wildfire 20
mitigation costs to 2022 actual costs, and include 21
amortization into rates of previously deferred wildfire 22
mitigation costs, excluding deferred vegetation management 23
costs, over a seven-year amortization period. 24
LARKIN, DI 5
Idaho Power Company
Prior to discussing the broader methodology utilized 1
to develop the 2023 Test Year, I will first address the 2
Company’s methodologies related to pension and non-fuel 3
coal-related costs at Bridger and Valmy. 4
II. PENSION COST RECOVERY 5
Q. Please provide an overview of the regulatory 6
treatment for the Company’s defined benefit pension plan 7
expense in Idaho rate proceedings. 8
A. In Order No. 30333 issued in 2007, the 9
Commission authorized Idaho Power to account for its 10
defined benefit pension expense on a cash basis and to 11
defer and account for accrued Statement of Financial 12
Accounting Standards (“SFAS”) 87 / Accounting Standards 13
Codification (“ASC”) 715 pension expense as a regulatory 14
asset. Then in 2010, the Commission determined in Order No. 15
31003 that the previously authorized regulatory asset could 16
be considered a balancing account to track, on a cumulative 17
basis, the difference between the cash amounts contributed 18
to the pension plan and the amounts included in rates. 19
Additionally, the Commission determined that recovery of 20
deferred cash contributions and ASC 715 expense and the 21
associated amortization period were to be evaluated during 22
a revenue requirement proceeding. 23
Q. Do customers benefit under the current 24
regulatory treatment for pension expense? 25
LARKIN, DI 6
Idaho Power Company
A. Yes. The balancing account established by 1
Order No. 31003 provides for a greater level of cost 2
tracking that assures customers pay no more than the actual 3
cost as well as providing a better opportunity to match 4
costs with revenues. The balancing account is also an 5
effective tool to mitigate financial market volatility as 6
well as discount rate volatility. The balancing account 7
results in the Company addressing both market and discount 8
rate volatility while the customer impact of the volatility 9
is mitigated. The balancing account also provides the 10
Commission with the opportunity to determine an appropriate 11
amortization period for rate recovery. 12
Q. What is the Company’s current annual level of 13
pension expense recovery? 14
A. In Order No. 32248 issued in 2011 in Case No. 15
IPC-E-11-04, the Commission authorized recovery of 16
$17,153,713 per year. 17
Q. Aside from the current level of base rate 18
recovery, have there been any other reductions to the 19
balancing account? 20
A. Yes. Due to the Company’s revenue sharing 21
mechanism,1 from 2011 to 2014 the pension balancing account 22

1 Case No. IPC-E-09-30, Order No. 30978. This ADITC/Revenue Sharing
mechanism was subsequently extended, and percentages, thresholds, and accounting were modified by the Commission in Order Nos. 32424, 33149, and 34071.
LARKIN, DI 7
Idaho Power Company
was reduced by approximately $68 million, as earnings above 1
a 10.5 percent return on equity were used to offset future 2
rate increases associated with pension deferrals. 3
Q. What is the current balance in the pension 4
balancing account? 5
A. As of December 31, 2022, the balance was $221 6
million. 7
Q. What is the Company’s requested level of 8
pension expense recovery in the 2023 Test Year? 9
A. At Mr. Tatum’s direction, the Company is 10
requesting $35 million of pension amortization, reflecting 11
an approximate increase of $18 million compared to the 12
amount currently in rates. 13
Q. Is there a risk to customers of over-recovery 14
if assumptions regarding pension costs or funding levels 15
change? 16
A. No. The existing balancing account methodology 17
ensures that customers never pay more than actual pension 18
costs. If future contributions are less than $35 million 19
the balance in the account will be reduced sooner. If 20
contributions continue to be higher than the recovery of 21
$35 million, the pension balancing account will grow but 22
will not impact customers without future rate approvals, as 23
has been illustrated over the period since Idaho Power’s 24
last general rate case. 25
LARKIN, DI 8
Idaho Power Company
III. NON-FUEL COAL-RELATED COST RECOVERY 1
Q. How are non-fuel coal-related costs generally 2
recovered in rates? 3
A. On May 31, 2017, the Commission authorized the 4
Company in Order No. 33771 to establish a balancing 5
account, with the necessary regulatory accounting, to track 6
the incremental costs and benefits associated with the 7
accelerated Valmy end-of-life as part of the Valmy 8
levelized revenue requirement mechanism.2 Similarly, on June 9
1, 2022, the Commission authorized the Company in Order No. 10
35423 to establish a balancing account, with the necessary 11
regulatory accounting, to track the incremental costs and 12
benefits associated with the Company’s cessation of coal-13
fired operations at Bridger as part of the Bridger coal-14
related levelized revenue requirement mechanism.3 The 15
recovery of these amounts is embedded in the Company’s 16
currently-approved base rates. 17
Q. What direction did you receive from Mr. Tatum 18
with regard to the inclusion of non-fuel coal-related costs 19
in the 2023 Test Year? 20
A. Mr. Tatum directed me to maintain the Valmy 21
and Bridger non-fuel coal-related cost recovery at current 22

2 Case No. IPC-E-16-24, Order No. 33771.
3 Case No. IPC-E-21-17, Order No. 35423.
LARKIN, DI 9
Idaho Power Company
levels, with the exception of collection related to 1
previously deferred revenue requirement amounts. 2
Q. How did the Company achieve this directive? 3
A. This directive was achieved as reflected in 4
Ms. Jeppsen’s testimony and exhibits, through the removal 5
of these costs from 2022 actuals. As discussed by Ms. 6
Jeppsen, actual non-fuel coal-related costs at Bridger and 7
Valmy were adjusted out of actual costs in all pertinent 8
cost categories, including non-fuel O&M, electric plant-in-9
service, and property taxes. 10
Q. How is Idaho Power accounting for the existing 11
cost recovery through these coal mechanisms in its 12
presentment of the 2023 Test Year? 13
A. With regard to revenues, the Company’s 14
existing base rates already reflect the amount of current 15
recovery of these levelized amounts, therefore the 2023 16
Test Year retail revenues calculated by Ms. Brady and 17
provided to Ms. Noe reflect revenues the Company is 18
currently receiving related to these levelized revenue 19
requirements. With regard to costs, Idaho Power has 20
quantified the current level of authorized cost recovery 21
for both the Bridger coal-related and Valmy levelized 22
revenue requirement mechanisms. Because coal-related 23
Bridger and Valmy costs were removed from actual 2022 24
financials by Ms. Jeppsen, the Company has added the 25
LARKIN, DI 10
Idaho Power Company
currently authorized Idaho jurisdictional recovery levels 1
to the 2023 Test Year revenue requirement, as detailed in 2
the jurisdictional separation study (“JSS”) prepared by Ms. 3
Noe. As described in the Direct Testimony of Mr. Tatum, 4
these amounts also include the total incremental annual 5
Bridger-related cost recovery associated with previously 6
deferred revenue requirement amounts. 7
IV. TEST YEAR METHODS 8
Q. Will you briefly summarize how the Company 9
developed its 2023 Test Year? 10
A. Yes. The development of the 2023 Test Year 11
began with 2022 actual financial data (“2022 Actuals”). 12
2022 Actuals were compiled and adjusted by Ms. Jeppsen to 13
reflect standard ratemaking adjustments and to arrive at 14
2022 adjusted actual financial information (“2022 Base”). 15
The 2022 Base was then adjusted to reach 2023 forecasted 16
financial levels (“2023 Unadjusted Test Year”). Finally, 17
annualizing adjustments were made to the 2023 Unadjusted 18
Test Year to reach the Company’s 2023 Test Year. 19
Q. Which forecast methodologies were used to 20
adjust the 2022 Base to the 2023 Unadjusted Test Year? 21
A. There were two primary methods developed and 22
applied to the 2022 Base Year to forecast the 2023 23
Unadjusted Test Year. First, the Company used the unchanged 24
2022 Base Year financial data when the Company believed 25
LARKIN, DI 11
Idaho Power Company
that certain amounts would continue to remain at 2022 1
levels or if account balances were relatively small. 2
Alternatively, “Other Adjustments” were applied based upon 3
known or probable factors for 2023 that relate to a 4
particular account. Examples of these factors include, but 5
are not limited to, new billing and volume contract terms, 6
discontinued services, anticipated levels of economic 7
activity, and existing regulatory commission orders. 8
Q. Have you prepared exhibits that list all 9
accounts and identify the specific method used to forecast 10
the 2023 Unadjusted Test Year? 11
A. Yes. I directed the preparation of Exhibit No. 12
25 to present a summarized list of all accounts to which 13
the two previously discussed methods were applied. Each 14
methodology is described in more detail within the Forecast 15
Methodology Manual, provided as Exhibit No. 26, which was 16
also prepared at my direction. To develop the Forecast 17
Methodology Manual, the Company performed a review of each 18
group of accounts included within the test year. Based upon 19
specific knowledge and analysis of each account grouping, 20
the Company either used 2022 Actuals or applied an Other 21
Adjustment methodology to that account to represent an 22
appropriate level of anticipated spending. 23
LARKIN, DI 12
Idaho Power Company
Q. Have the data and the associated adjustments 1
made to your exhibits and supporting schedules been 2
calculated on a total system basis? 3
A. Yes. Ms. Noe will address the determination of 4
the Idaho jurisdictional test year values in her testimony. 5
Q. What are the major areas or groupings of 6
financial accounts addressed by the methodologies included 7
in the Forecast Methodology Manual (Exhibit No. 26)? 8
A. The major areas or groupings of financial 9
accounts addressed in Exhibit No. 26 include Other 10
Operating Revenues (Accounts 451, 454, and 456), Operation 11
and Maintenance Expenses (Accounts 500 through 935), 12
Depreciation and Amortization Expense (Accounts 403 and 13
404), and Electric Plant in Service (Account 101). A 14
detailed discussion of the individual accounts and methods 15
used is provided in Exhibit No. 26. 16
Q. Which methodology was used to forecast 2023 17
Other Operating Revenues (Accounts 447, 451, 454, and 456)? 18
A. Consistent with Mr. Tatum’s directive, Surplus 19
Sales Revenues (Account 447) were included in the Company’s 20
quantification of base NPSE as further detailed in Ms. 21
Brady’s testimony. The remaining Other Operating Revenues 22
(Accounts 451, 454, and 456) were kept at year-end 2022 23
Actuals, with the exception of six items: 1) miscellaneous 24
service revenues, 2) cogeneration and small power 25
LARKIN, DI 13
Idaho Power Company
production, 3) revenues from dark fiber rents, 4) payments 1
to water districts, 5) facilities charges, and 6) third-2
party transmission revenues. 3
Account 451 contains Miscellaneous Service Revenues, 4
and was forecast based on proposed changes to Schedule 66 5
(the Miscellaneous Charges tariff that governs these 6
offerings) that are further discussed in the Direct 7
Testimony of Company Witness Mr. Riley Maloney. 8
Cogeneration and small power production revenues were 9
determined by applying a five-year compound average growth 10
rate (“CAGR”), as the Company believes this method reflects 11
a reasonable expectation for the 2023 timeframe. Revenues 12
from dark fiber rents will cease in February 2023, 13
therefore they were removed as a forecast adjustment. 14
Payments from water districts were calculated based on a 15
five-year average, as these payments fluctuate based on 16
demand for water and availability. Expected facilities 17
charge revenues were based on the Company’s proposed 18
facilities charge rate filed in this case applied to 19
expected applicable investment in the 2023 Test Year, as 20
further addressed by Mr. Maloney. Network services and 21
other long-term firm and point-to-point transmission 22
revenues were projected based on information more 23
reflective of current circumstances and an anticipated Open 24
Access Transmission Tariff rate update in October 2023. 25
LARKIN, DI 14
Idaho Power Company
Q. Which methodology was used to forecast 2023 1
O&M Expenses (Accounts 500 through 935)? 2
A. Based on the instructions I received from Mr. 3
Tatum, the general process to determine 2023 Test Year O&M 4
began with the separation of the majority of O&M components 5
into two elements: labor and non-labor. Each element was 6
then forecast separately and allocated to the individual 7
Federal Energy Regulatory Commission (“FERC”) accounts. 8
Based upon the instructions I received from Mr. 9
Tatum, there were several O&M accounts that were determined 10
separately from this process. First, the base NPSE accounts 11
tracked through the PCA were updated by Ms. Brady primarily 12
utilizing the AURORA model. The PCA expense accounts 13
include Fuel Expense (Accounts 501 and 547), Water for 14
Power Expense (Account 536.003), Purchased Power Expense 15
(Account 555), and Transmission of Electricity by Others 16
(Account 565). 17
The Idaho Energy Efficiency Rider Expense (Account 18
908) was removed in its entirety from the 2023 Test Year, 19
while the labor component was added back to this account, 20
as discussed in the Direct Testimony of Mr. Tatum. 21
Incentive Expense (included in Account 920) was 22
forecasted for 2023 to include only the normalized 23
incentive components that are attributable to Customer 24
Satisfaction and Reliability, consistent with the method 25
LARKIN, DI 15
Idaho Power Company
approved in Case No. IPC-E-08-10 (“2008 Rate Case”), Order 1
No. 30722, and filed in the Company’s 2011 Rate Case. 2
Incentive expense represents the “at-risk” portion of 3
employees’ total compensation package. 4
Pension Expense (Account 926) for the Idaho 5
jurisdiction was increased to reflect $35 million in annual 6
collection, as discussed previously in my testimony. 7
Regulatory Commission Expenses (Account 928) were 8
adjusted to include known changes in amortizations for 9
recovery of Commission-ordered intervenor funding. 10
Q. What methodology was used to forecast 2023 O&M 11
labor expense? 12
A. The 2023 labor expense was forecasted by 13
applying historical monthly labor cost relationships to the 14
first two calendar months of 2023 actual labor costs. More 15
specifically, the 2023 O&M labor forecast was developed by 16
first calculating the three-year historical average of 17
February year-to-date actual O&M labor costs as a 18
percentage of the total year actual O&M labor costs. The 19
resulting percentage was determined to be 16.0 percent. 20
This percentage was then applied to the actual February 21
2023 year-to-date O&M labor to estimate the total 2023 O&M 22
labor costs. The February amount was first reduced by 23
pension expense and incentive expense. The resulting 2023 24
labor projection of $188.8 million was then allocated to 25
LARKIN, DI 16
Idaho Power Company
the applicable FERC accounts based on 2022 actual labor 1
charges to those same accounts. 2
This method is similar to that utilized by 3
Commission Staff (“Staff”) in the 2008 Rate Case to 4
validate the Company’s labor forecast as additional actual 5
labor cost data became available throughout the test 6
period, and mirrors the Company’s filed approach in the 7
2011 Rate Case. A more detailed discussion of the labor-8
related O&M adjustment is provided in Exhibit No. 26, pages 9
5 and 6. 10
Q. Did Idaho Power make any adjustments to 11
expected labor costs related to the Energy Efficiency Rider 12
(“Rider”)? 13
A. Yes. As described in the Direct Testimony of 14
Mr. Tatum, in this case Idaho Power is proposing to 15
transfer approximately $3.5 million in Rider-funded labor 16
costs into base rates. As discussed later in my testimony, 17
the movement of these labor costs from the Rider to base 18
rate recovery is one of two rate neutral transfer 19
adjustments the Company is proposing in this case. 20
Q. What methodology was used to forecast 2023 21
non-labor O&M expenses? 22
A. 2023 non-labor O&M expenses, excluding the 23
accounts mentioned above, were projected to be equal to the 24
2022 actual expense level with adjustments only for 25
LARKIN, DI 17
Idaho Power Company
relatively large known changes. At my direction, the O&M 1
expenses were reviewed by subject matter experts to 2
identify and adjust those areas, based on specific 3
knowledge, where expense levels are expected to be 4
materially different than those included in the 2022 Base. 5
The review identified specific increases or decreases to 6
the 2022 non-labor actual levels in the following 7
categories: 8
• Idaho Fish and Game’s Projected Hatchery Expense 9
Increases 10
• Fleet Adjustment 11
• Water for Power Adjustment 12
• Langley and Bennett Mountain Plant Maintenance 13
• Western Resource Adequacy Program (“WRAP”)4 Costs 14
• Uncollectible / Bad Debt Expense 15
• Solar Payback Calculator 16
Actual 2022 non-labor O&M, excluding these items 17
listed for known changes, equaled $157.6 million. 18
Following the adjustments for significant known changes, 19
non-labor O&M is projected to increase by $339,424, to 20
$157.9 million. This reflects a non-labor O&M amount for 21
the 2023 Test Year that has increased by less than 0.25 22
percent. A more detailed discussion of the non-labor O&M 23

4 The WRAP and its associated benefits are currently the subject of an open case before the Commission (Case No. IPC-E-23-08).
LARKIN, DI 18
Idaho Power Company
adjustments is provided in Exhibit No. 26, pages 6 through 1
16. 2
Q. Is there any specific regulatory accounting 3
treatment that the Company is seeking related to the list 4
of known and measurable adjustments you just identified? 5
A. Yes. The Company requests specific regulatory 6
accounting authority related to the known and measurable 7
adjustment item “Langley and Bennett Mountain Plant 8
Maintenance.” As can be seen on pages 7 and 8 of Exhibit 9
No. 26, Langley and Bennett Mountain Plant Maintenance —10
Account 554 was decreased from the 2022 Base by $3,423,030. 11
For this non-labor component, this account was projected to 12
be equal to the 5-year average. The 2022 base included 13
cyclical plant maintenance related to Langley and Bennett 14
Mountain major overhaul and inspections that do not occur 15
on an annual basis. 16
Consistent with the accounting authority previously 17
granted in Order No. 32426,5 the Company requests the 18
Commission authorize the deferral and amortization of 19
annual differences between actual costs and the annual 20
recovery amount authorized in this case to allow for a 21

5 Order No. 32426 issued in Case No. IPC-E-11-08 approved a settlement stipulation containing the following ¶ 6(b) Amortization provision: “The Signing Parties agree to a deferral of $299,546 in expenses
associated with the Bennett Mountain combustor inspection with a four-year period beginning on the date that the Company’s new base rates become effective.”
LARKIN, DI 19
Idaho Power Company
proper matching of cost and revenue for this periodic cost. 1
The Company further recommends this treatment be allowed 2
until new rates become effective in a future general rate 3
case or are otherwise modified by the Commission. 4
Q. What accounting will the Company use to track 5
the annual differences between actual costs and the annual 6
authorized recovery amount? 7
A. Idaho Power will defer the difference between 8
actual costs and the annual recovery amount to Account 9
182.3 Other Regulatory Assets with an offsetting entry to 10
Account 554 Maintenance of Miscellaneous Other Power 11
Generation Plant. 12
Q. What methodology was used to forecast 2023 13
Depreciation and Amortization Expense (Accounts 403 and 14
404)? 15
A. The 2023 depreciation expense, amortization 16
expense, and related reserve accounts were calculated based 17
on the monthly estimated 2023 plant balances. Depreciation 18
rates authorized by Commission Order No. 35272 were used 19
for the entire 2023 Test Year. The determination of the 20
Depreciation and Amortization Expense adjustments is 21
detailed in Exhibit No. 26, pages 16 and 17. 22
Q. Which methodology was used to forecast 2023 23
Electric Plant in Service (Account 101)? 24
LARKIN, DI 20
Idaho Power Company
A. Electric Plant in Service (“EPIS”) is a 1
function of multiple components, including actual year-end 2
2022 EPIS and construction work in progress (“CWIP”) 3
balances, estimated 2023 spending, expected 2023 closings 4
of CWIP, and estimated retirements. Therefore, it was 5
necessary to use several methodologies to develop the 2023 6
Unadjusted Test Year EPIS balances, which are detailed in 7
Exhibit No. 26, pages 21 through 22. 8
To project 2023 construction expenditures and 2023 9
closings of CWIP to EPIS, at Mr. Tatum’s instruction, the 10
Company first bifurcated into two separate and distinct 11
parts, those projects in excess of $8 million and those 12
under $8 million. 13
Projects in excess of $8 million were reviewed by 14
the individual project managers, who estimated the costs to 15
complete and the in-service date of each project. The 16
investment in projects under $8 million (excluding 17
vehicles) closing to EPIS as a group, were forecast based 18
on the five-year average of the percent of similar-sized 19
projects to the previous year’s CWIP balance multiplied by 20
the year-end 2022 CWIP balance. 21
Q. Which methodology was used to forecast AFUDC 22
associated with Hells Canyon relicensing CWIP? 23
A. While AFUDC continues to increase relating to 24
the Hells Canyon relicensing efforts, the Company is 25
LARKIN, DI 21
Idaho Power Company
requesting recovery of the same amount ($6,815,472) 1
previously included in the 2011 Rate Case and subsequently 2
approved in Order No. 32426. This adjustment is explained 3
in greater detail in Exhibit No. 26, page 20. 4
V. ADDITIONAL ADJUSTMENTS 5
Q. In Ms. Jeppsen’s testimony, she describes the 6
various adjustments that were made to 2022 Actuals to 7
arrive at the 2022 Base Year. Do these same adjustments 8
need to be made in 2023? 9
A. No. These adjustments are standard ratemaking 10
adjustments based on prior Commission orders and are 11
adjustments to charges included in the 2022 Actuals. By 12
removing them from 2022 Actuals prior to applying the 13
various methodologies to arrive at the Company’s proposed 14
2023 Unadjusted Test Year, the same adjustments are already 15
accounted for. 16
Q. What were your instructions to Ms. Brady with 17
regard to the determination of the test year retail sales 18
revenues? 19
A. I instructed Ms. Brady to determine the 2023 20
Test Year retail sales revenues using the same methodology 21
approved by the Commission in the 2008 Rate Case, Order No. 22
30722, and applied in the Company’s 2011 Rate Case. That 23
is, my instructions were to develop the test year retail 24
sales revenues based upon forecasted billing determinants 25
LARKIN, DI 22
Idaho Power Company
under normal weather and precipitation assumptions. As Ms. 1
Brady will cover in greater detail in her testimony, the 2
2023 Test Year billing determinants were developed based on 3
the Company’s energy sales and customer count forecasts 4
prepared for this case. To derive the demand-related 5
billing determinants, historical demand-to-energy 6
relationships were applied to the energy sales forecast. 7
The forecasted billing determinants were then applied to 8
the rates in effect at the time of the filing to determine 9
the 2023 Test Year retail sales revenues. 10
Q. Was the customer, sales, and load forecast 11
prepared at your direction? 12
A. Yes. The customer, sales, and load forecast 13
for the 2023 Test Year was prepared at my direction. This 14
forecast was utilized to determine the billing components 15
for the 2023 retail sales revenue forecast, as well as the 16
allocation factors utilized by Ms. Noe and Mr. Goralski as 17
well. 18
Q. Did you direct Ms. Brady to make any 19
adjustments to the 2023 retail sales revenues relative to 20
the methodology utilized in the 2011 Rate Case? 21
A. Yes. Due to the Commission’s approval of a 22
revised special contract for electric service (“Special 23
Contract”) with Micron Technologies (“Micron”) on March 9, 24
LARKIN, DI 23
Idaho Power Company
2022,6 I directed Ms. Brady to exclude the component of 1
Micron’s retail revenues that will be offset by generation 2
from the Black Mesa Solar Facility (“Black Mesa”). 3
Q. Can you describe the mechanics of Micron’s 4
revised Special Contract and how it pertains to the 2023 5
retail sales revenue calculation? 6
A. Per the terms of the revised Special Contact, 7
a portion of Micron’s retail sales will be offset by 8
generation from Black Mesa. Functionally, that means Micron 9
will pay Idaho Power for 100 percent of the output from 10
Black Mesa, which will offset the retail energy rates 11
Micron would otherwise pay. Consequently, the portion of 12
Micron’s sales offset by Black Mesa must be separately 13
calculated from other retail revenues to ensure these 14
contract components are appropriately accounted for 15
throughout the various steps in the rate development 16
process. 17
Q. Did you have any additional instructions for 18
Ms. Brady? 19
A. Yes. In addition to the development of 2023 20
Test Year retail revenues, Ms. Brady is also the Company’s 21
expert with regard to the modeling of base NPSE. As 22
mentioned earlier in my testimony, Mr. Tatum directed me to 23
update the PCA expense accounts to expected 2023 normalized 24

6 Case No. IPC-E-22-06, Order Nos. 35482, 35607 and 35735.
LARKIN, DI 24
Idaho Power Company
levels. Consistent with this directive, Ms. Brady updated 1
base NPSE as provided in Exhibit No. 30 to her testimony. 2
Q. When was base NPSE last updated in customer 3
rates? 4
A. Idaho Power last updated base NPSE in customer 5
rates through Order No. 33000 issued in Case No. IPC-E-13-6
20, which became effective June 1, 2014 (“2013 NPSE 7
Update”). 8
Q. Did you direct Ms. Brady to make any 9
methodological changes to the determination of base NPSE 10
relative to the method utilized in the 2013 NPSE Update? 11
A. Yes. Due to the aforementioned Black Mesa 12
component of Micron’s revised Special Contract, I directed 13
Ms. Brady to include the generation from the Black Mesa 14
project in the Company’s resource stack, but exclude the 15
corresponding costs from Account 555, as these costs will 16
be directly paid for by Micron. Further, due to changes in 17
conditions since the filing of the 2011 Rate Case, I also 18
directed Ms. Brady to modify the treatment of Account 19
447.050, which reflects revenues received due to third-20
party transmission wheeling losses. Lastly, given current 21
and expected changes in the Company’s resource stack, I 22
directed Ms. Brady to include in the 2023 Test Year the 23
availability of gas-fired generation at Bridger units 1 and 24
2. 25
LARKIN, DI 25
Idaho Power Company
Q. What methodology adjustment was made related 1
to Account 447.050, revenues from wheeling losses? 2
A. Account 447.050 reflects financial payments 3
made to Idaho Power as compensation for the Company 4
generating electricity to offset transmission losses to 5
third parties wheeling through Idaho Power’s transmission 6
system. In past determinations of base NPSE, Idaho Power 7
did not include 447.050 revenues in these quantifications, 8
nor did it include any costs associated with the additional 9
generation required to serve third party losses. In the 10
current case, however, Idaho Power is proposing to include 11
in its base NPSE determination both the cost of serving 12
third party losses as well as the offsetting revenues 13
received through Account 447.050. Therefore, Idaho Power 14
added 36 average megawatts (“aMW”) to its load forecast 15
utilized for AURORA modeling purposes to account for this 16
load service requirement, and Ms. Brady determined an 17
offsetting revenue amount to include in Account 447.050. 18
Q. Why is Idaho Power proposing to make this 19
methodological change? 20
A. Theoretically, the inclusion or exclusion of 21
Account 447.050 and the corresponding cost to serve third 22
party losses would ultimately yield the same result; the 23
exclusion of these components would have no impact on 24
revenue requirement because they would be entirely removed 25
LARKIN, DI 26
Idaho Power Company
from the quantification, while the inclusion of these 1
components would net to zero. 2
Additionally, when the 2013 NPSE Update was 3
performed, third party wheeling customers had the option to 4
account for wheeling losses in two ways: 1) financially – 5
meaning the customer would pay Idaho Power to generate the 6
additional energy to account for the losses, or 2) 7
physically – meaning the customer would generate or acquire 8
additional physical energy to account for the losses 9
themselves, resulting in no additional payment to Idaho 10
Power. However, with the advent of the energy imbalance 11
market (“EIM”), nearly all wheeling customers now settle 12
their losses financially, meaning they pay Idaho Power to 13
generate the physical energy to account for wheeling losses 14
through the Company’s system. Because of this, the Company 15
is proposing to modify the base NPSE methodology to include 16
both the cost to serve third-party wheeling losses and the 17
offsetting revenues received by the Company. 18
Q. Given this change, is the Company proposing 19
that Account 447.050 would be included in the PCA as well? 20
A. Yes. Under the Company’s proposal, Account 21
447.050 would become part of base NPSE utilized in PCA 22
calculations as of the effective date of rates resulting 23
from this case. 24
LARKIN, DI 27
Idaho Power Company
Q. What direction did you give Ms. Brady with 1
regard to the Company’s resource stack? 2
A. The timing of Idaho Power’s 2023 Test Year 3
corresponds with changes in the Company’s resource stack, 4
resulting in the need for an adjustment to assumed resource 5
availability. Under current operations, the Jim Bridger 6
Power Plant consists of four coal-fired units. However, the 7
Company will cease coal-fired operations at units 1 and 2 8
at year-end 2023, converting these units to natural gas, 9
with an expected online date of summer 2024. Because of 10
this timing, I directed Ms. Brady to model the availability 11
of two gas units and two coal units at Bridger, which 12
better aligns with expectations on a going forward basis. 13
Because the Company’s requested effective date in 14
this case is January 1, 2024, and because the PCA will 15
capture differences between actual NPSE and base NPSE on a 16
going forward basis until base NPSE are reset in a future 17
proceeding, Idaho Power believes the modeling of gas-fired 18
generation at Bridger units 1 and 2 is preferable to the 19
modeling of four coal-fired units at Bridger, which would 20
be immediately outdated as of the day rates go into effect. 21
Q. Are there any additional adjustments that need 22
to be made to properly determine the 2023 Test Year? 23
LARKIN, DI 28
Idaho Power Company
A. Yes. It is necessary for the Company to make 1
additional annualizing and known and measurable 2
adjustments. 3
Q. Which other annualizing adjustments were made 4
under your direction to the 2023 Test Year? 5
A. I instructed Ms. Noe to make annualizing 6
adjustments to certain expense and rate base items to 7
reflect them as though they have been in existence for the 8
entire 2023 Test Year; that is, at year-end 2023 levels. 9
These include operating payroll, depreciation expense and 10
reserve, and plant placed in service during 2023 in excess 11
of $8 million with the associated estimated property taxes 12
and insurance premiums. Such adjustments are appropriate to 13
reflect conditions that will be in effect at the time rates 14
are placed in effect. Ms. Noe provides additional detail 15
regarding the annualizing adjustments in her testimony. 16
Q. Has an exhibit been prepared that details each 17
of the adjustments that were made to move from the 2022 18
Actuals to the 2023 Test Year? 19
A. Yes. Ms. Noe’s Exhibit No. 34 summarizes the 20
adjustments that were made to each FERC Account to: 1) move 21
from the 2022 Actuals to the 2022 Base, 2) move from the 22
2022 Base to the 2023 Unadjusted Test Year, and 3) move 23
from the 2023 Unadjusted Test Year to the 2023 Test Year. 24
LARKIN, DI 29
Idaho Power Company
Q. How did you direct Ms. Noe to reflect the 1
costs and revenues associated with Black Mesa and the 2
Micron Special Contract? 3
A. Due to the offsetting nature of these costs 4
and revenues, I directed Ms. Noe to exclude both components 5
from the Idaho jurisdictional revenue requirement. 6
Q. Did you direct Ms. Noe to make any additional 7
adjustments prior to quantifying the Company’s requested 8
revenue requirement in this case? 9
A. Yes. As previously discussed, in order to 10
determine an accurate revenue requirement change, Ms. Noe 11
had to first include the currently authorized recovery for 12
non-fuel coal-related costs. I directed Ms. Noe to include 13
the requested Bridger and Valmy levelized revenue 14
requirements as separate lines in the JSS. Further, as 15
discussed in Mr. Tatum’s testimony, Idaho Power is 16
proposing to offset the revenue requirement increase 17
stemming from the battery projects to be installed in 2023 18
through the acceleration of accumulated deferred investment 19
tax credits (“ADITC”). I directed Ms. Noe to incorporate 20
this proposed rate mitigation into the quantification of 21
the Company’s request as well. Lastly, I directed Ms. Noe 22
to reflect two transfer adjustments in the body of the JSS. 23
Q. What is meant by transfer adjustment? 24
LARKIN, DI 30
Idaho Power Company
A. Two of the Company’s proposed updates in this 1
case will have corresponding offsetting impacts on other 2
rate mechanisms, thus reducing the net increase to customer 3
bills. The term “transfer adjustment” is in reference to 4
the fact that the recovery of these components of revenue 5
requirement is already reflected in customer rates, and the 6
Company’s request in this case merely reflects the transfer 7
of this recovery to base rates rather than a true increase 8
to customer bills. 9
Q. What comprises the transfer adjustments? 10
A. The transfer adjustments are comprised of the 11
aforementioned Rider labor adjustment and an update to PCA-12
related items. 13
Q. Please describe the transfer adjustment 14
related to the Rider. 15
A. The Rider labor adjustment is simply the 16
movement of labor-related costs out of the Rider and into 17
base rates. As discussed by Mr. Tatum, the Company is 18
proposing a corresponding reduction in the Rider 19
percentage, thus resulting in no material impact to 20
customer bills. 21
Q. What comprises the PCA-related transfer 22
adjustment? 23
A. The PCA transfer adjustment is comprised of 24
two subcomponents: 1) the reduction to the PCA due to an 25
LARKIN, DI 31
Idaho Power Company
update to base NPSE, and 2) removal of EIM-related revenue 1
requirement from PCA recovery. 2
Q. How will the PCA be reduced as a result of the 3
base NPSE update? 4
A. A primary component of PCA rates contained in 5
Schedule 55 is the difference between base NPSE and the 6
forecast of NPSE for the PCA year. Therefore, when base 7
NPSE are updated— and in this case, increased— the 8
difference between base NPSE and the forecast established 9
in the PCA is reduced, necessitating a reduction in 10
Schedule 55 PCA rates. Consequently, the increase in NPSE 11
proposed to be included in base rates is mostly offset by a 12
corresponding reduction in the PCA rate. The only net 13
impact to customers stems from the difference between full 14
recovery in base rates of base NPSE, as compared to 95 15
percent recovery of deviations between base NPSE and 16
forecast NPSE for certain accounts through the PCA. Ms. 17
Brady quantifies this component of the PCA transfer 18
adjustment in her testimony. 19
Q. Please explain the component of the PCA-20
related transfer adjustment stemming from EIM costs. 21
A. In accordance with Order No. 33706, which 22
approved Idaho Power’s entrance into the EIM, the Company 23
currently collects actual EIM-related costs through the PCA 24
balancing adjustment. Order No. 34100 authorized Idaho 25
LARKIN, DI 32
Idaho Power Company
Power to recover its actual EIM-related costs on a 1
backward-looking basis, as benefits in the form of reduced 2
NPSE also flow through the PCA balancing adjustment via 3
actual realized NPSE. This method of cost recovery was 4
intended to capture these costs until they could be 5
included in the Company’s base rates as Idaho Power is 6
proposing in this case. Therefore, to recognize that the 7
Company’s 2023 Test Year includes EIM-related costs that 8
are currently collected through the balancing adjustment, 9
Idaho Power has included a transfer adjustment in its 10
quantification of the 2023 revenue requirement computation. 11
Q. What is the total amount of the transfer 12
adjustments reflected in the presentment of the Company’s 13
2023 revenue requirement computation? 14
A. The three transfer adjustments are listed in 15
the following table on an Idaho jurisdictional basis: 16
Table 1: Transfer Adjustments by Component 17
Component Amount
Total $176,843,507 18
Q. What direction did you provide Ms. Noe with 19
regard to the inclusion of the transfer adjustments? 20
A. To recognize that these costs are already 21
reflected in customer rates, I directed Ms. Noe to include 22
LARKIN, DI 33
Idaho Power Company
these transfer adjustments in 2023 Test Year operating 1
revenues. 2
Q. According to Ms. Noe’s analysis using the 2023 3
Test Year and incorporating the adjustments she made at 4
your direction, what is the Company’s revenue requirement 5
on an Idaho jurisdictional basis? 6
A. Using the 2023 Test Year financial 7
information, Ms. Noe has calculated the Company’s revenue 8
requirement to be $1,404.3 million on an Idaho 9
jurisdictional basis. Ms. Noe calculated the Company’s 10
annual revenue deficiency, the amount that the test year 11
revenue requirement exceeds the test year retail sales 12
revenue, to be $111.3 million on an Idaho jurisdictional 13
basis, which would result in an overall average increase to 14
customer rates of 8.61 percent. 15
Q. Is it appropriate for the Commission to 16
determine the Company’s Idaho-jurisdictional revenue 17
requirement to be $1,404.3 million, its revenue deficiency 18
to be $111.3 million, and therefore, approve an overall 19
8.61 percent increase to customer rates? 20
A. Yes. The $1,404.3 million figure is a 21
reasonable determination of the Company’s annual Idaho- 22
jurisdictional revenue requirement. The $111.3 million 23
quantification of revenue deficiency is also reasonable. 24
It is in the best interest of the Company and its customers 25
LARKIN, DI 34
Idaho Power Company
for the Commission to approve a rate increase to provide an 1
8.61 percent increase to the Company’s Idaho jurisdictional 2
revenues. 3
Q. Does this conclude your direct testimony in 4
this case? 5
A. Yes, it does. 6
// 7
// 8
//9
LARKIN, DI 35
Idaho Power Company
DECLARATION OF MATTHEW T. LARKIN 1
I, Matthew T. Larkin, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Matthew T. Larkin. I am employed 4
by Idaho Power Company as the Revenue Requirement Senior 5
Manager. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony and Exhibit Nos. 25 through 26 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 MATTHEW T. LARKIN 19
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