20230601Direct Noe.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

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

IDAHO POWER COMPANY
DIRECT TESTIMONY OF
KELLEY NOE
NOE, DI 1
Idaho Power Company
Q. Please state your name and business address. 1
A. My name is Kelley Noe. My business address is 2
1221 West Idaho Street, Boise, Idaho. 3
Q. By whom are you employed and in what capacity? 4
A. I am employed by Idaho Power Company (“Idaho 5
Power” or “Company”) as a Regulatory Consultant. 6
Q. Please describe your educational background. 7
A. In May of 2004, I received a Bachelor of Business 8
Administration in Finance from Boise State University. I 9
have also attended electric utility ratemaking courses, 10
including “The Basics: Practical Regulatory Training for 11
the Electric Industry,” a course offered through New Mexico 12
State University’s Center for Public Utilities as well as 13
“Introduction to Rate Design and Cost of Service Concepts 14
and Techniques” presented by Electric Utilities 15
Consultants, Inc. 16
Q. Please describe your business experience with 17
Idaho Power Company. 18
A. In September 2006, I accepted a position at Idaho 19
Power as a Financial Analyst in the Finance Department. My 20
primary duties included performing credit reviews on 21
current and prospective transmission customers as well as 22
providing the financial support for Grid Operations, 23
Planning, and Operations Analysis and Development. In 24
October 2010, I accepted a Regulatory Analyst II position 25
NOE, DI 2
Idaho Power Company
within the Regulatory Affairs department of the Company. In 1
2015, I was promoted to Senior Regulatory Analyst, and in 2
2020 was promoted to my current position, Regulatory 3
Consultant. My duties as a Regulatory Consultant include 4
gathering, analyzing, and coordinating data from various 5
departments throughout the Company required for preparing 6
jurisdictional separation studies, developing complex cost-7
related studies, and the analysis of strategic regulatory 8
issues. 9
Q. What is the scope of your testimony in this 10
proceeding? 11
A. I am sponsoring testimony to summarize the 12
development of the system revenue requirement for purposes 13
of forecasting the Company’s rate base, revenues, and 14
expenses for the 2023 Test Year, as well as, quantifying 15
the Idaho Jurisdictional Revenue Requirement resulting from 16
the Jurisdictional Separation Study (“JSS”) for the twelve 17
months ending December 31, 2023. 18
Q. Have you prepared exhibits for this proceeding? 19
A. Yes. I am offering the following exhibits: 20
1. Exhibit No. 31, Major Plant Additions 21
Annualized for 2023 22
2. Exhibit No. 32, Depreciation & Amortization 23
Annualizing Adjustments 24
3. Exhibit No. 33, Summary of Payroll-Related 25
NOE, DI 3
Idaho Power Company
Annualizing Adjustments 1
4. Exhibit No. 34, Development of System 2
Revenue Requirement 3
5. Exhibit No. 35, Jurisdictional Separation 4
Study - Idaho Revenue Requirement. 5
Development of the System Revenue Requirement 6
Q. Could you briefly summarize how the Company 7
developed its 2023 Test Year? 8
A. Yes. As described in the Direct Testimonies and 9
Exhibits of Company Witnesses Ms. Paula Jeppsen and Mr. 10
Matthew Larkin, the development of the 2023 Test Year 11
begins with 2022 actual financial data (“2022 Actuals”). 12
The 2022 Actuals were adjusted to reflect currently 13
approved ratemaking adjustments and amounts previously 14
deferred related to wildfire mitigation (“WFM”) in 2022 to 15
arrive at 2022 adjusted actual financial information (“2022 16
Base”). The 2022 Base was then adjusted to reach 2023 17
forecasted financial levels (“2023 Unadjusted Test Year”). 18
After the 2023 Unadjusted Test Year figures were compiled, 19
they were provided to me as the starting point for the 20
development of the Company’s total 2023 Test Year figures 21
used in this filing. 22
Q. Were any additional adjustments made to the 2023 23
Unadjusted Test Year amounts to reach the Company’s total 24
2023 Test Year figures? 25
NOE, DI 4
Idaho Power Company
A. Yes. Exhibits 31 through 33 illustrate the 1
annualizing adjustments used to develop the total 2023 rate 2
base and net income figures used in the Company’s 2023 Test 3
Year. 4
Q. Please describe the role of annualizing 5
adjustments in this filing. 6
A. At Mr. Larkin’s direction, I performed several 7
annualizing adjustments to amounts that are incurred within 8
the Test Year but need to be reflected for the full year on 9
an ongoing basis. 10
Q. Please describe the annualizing adjustments made 11
for “Major Plant Additions.” 12
A. “Major Plant Additions,” illustrated in Exhibit 13
No. 31, are defined as those investments exceeding $8 14
million that will close to the Company’s electric plant-in-15
service accounts during the calendar year 2023. A month-16
by-month forecast of 2023 electric plant-in-service and the 17
13-month average balances provided by Ms. Jeppsen form the 18
beginning point for the analysis. Annualizing adjustments 19
are applied only to the 2023 plant additions that qualify 20
as Major Plant Additions to establish the amount of 21
investment that would have been recorded had the plant been 22
in service throughout the entire year. 23
As reflected in Exhibit No. 31, the difference between 24
what had been forecast for these investments in the initial 25
NOE, DI 5
Idaho Power Company
analysis compared to the annualized forecast, as 1
illustrated in column 8 – Net Annualizing Adjustments, is 2
the $161,434,512 annualizing adjustment for the Company’s 3
electric plant-in-service investment in this filing. 4
Additional annualizing adjustments associated with Major 5
Plant Additions include $498,233 in property taxes (column 6
11 – Annual Composite Property Tax) and $75,269 in property 7
insurance (column 13 – Annual Insurance Expense). Because 8
none of the Major Plant Additions were attributable to load 9
growth not already accounted for within the load forecast 10
(see Summary on Exhibit No. 31), an imputed revenue 11
adjustment was not required. 12
Q. How did you determine the Depreciation & 13
Amortization Annualizing Adjustments? 14
A. Depreciation and amortization expenses presented 15
in Exhibit No. 32 are forecast on a month-by-month basis 16
during 2023 and summarized in the column entitled 17
“Forecasted Depreciation Expense” (column 4). The expenses 18
for December 2023 are multiplied by twelve to calculate the 19
“Annualized Depreciation Expense” (column 3). The 20
difference between these two columns equals the 21
“Annualizing Adjustment” (column 5) of $8,884,245 22
depreciation expense and $95,740 amortization expense. 23
Adjustments of $4,442,123 to Accumulated Depreciation and 24
$47,870 to Accumulated Amortization, illustrated as the 25
NOE, DI 6
Idaho Power Company
“Reserve Adjustment” (column 6), are conventionally 1
computed as half the expense amounts. 2
Q. Were there any additional labor-related 3
annualizing adjustments? 4
A. Yes. As set forth in Exhibit No. 33, Summary of 5
Payroll-Related Annualizing Adjustments, there are two 6
additional labor-related annualizing adjustments in this 7
filing totaling $9,561,383. 8
The first adjustment utilizes 2022 actual labor data 9
as a proxy to annualize 2023 payroll and reflects an entire 10
year of expense at that year-end level. Because the method 11
applied to forecast the 2023 Operations and Maintenance 12
(“O&M”) labor expense (detailed in the Direct Testimony of 13
Mr. Larkin) provided only a forecast of the annual 2023 O&M 14
labor expense, a December labor expense amount from which a 15
conventional annualizing labor adjustment could be 16
calculated was not known. Therefore, an annualizing 17
adjustment based upon actual 2022 labor was calculated and 18
used as a proxy to adjust the O&M labor total for the 2023 19
Test Year. After applying the Company’s O&M and benefit 20
loading percentages, the annualizing adjustment is 21
$3,683,272. 22
The second adjustment of $5,878,111 reflects the 23
projected 2024 salary structure adjustment of 3 percent. 24
This adjustment was applied to the annualized 2023 payroll 25
NOE, DI 7
Idaho Power Company
and has been adjusted by the Company’s O&M and benefit 1
loading percentages. 2
Q. How is Exhibit No. 34, Development of System 3
Revenue Requirement organized? 4
A. Exhibit No. 34 provides the development of the 5
adjusted total electric system rate base and net income for 6
the test year ending December 31, 2023. 7
The first set of data, displayed in column 3 “2022 8
Actual”, is the unadjusted 2022 actual results of 9
operations provided by Ms. Jeppsen. The adjustments 10
proposed by the Company for purposes of developing the 2023 11
adjusted total electric system combined rate base and net 12
income are shown in columns 4 (“2022 Actual Adjustments”), 13
6 (“Forecast Adjustments”), and 8 (“Annualizing 14
Adjustment”), with the total system adjusted test year rate 15
base, expenses, and revenues summarized in column 9. The 16
proposed adjustments and resulting base amounts are set 17
forth in columns 4 through 8 and result in the 2023 test 18
year data set in column 9, described more fully as follows: 19
(1) Column 4, titled “2022 Actual Adjustments”, 20
was provided by Ms. Jeppsen and Company Witness Ms. Jessica 21
Brady. It reflects currently approved regulatory 22
adjustments that should be applied to the 2022 actual 23
results prior to applying methods to adjust to 2023 levels, 24
as well as adjustments to reflect WFM related expenses 25
NOE, DI 8
Idaho Power Company
deferred in 2022 thus resetting 2022 actual WFM-related O&M 1
to what it would have been absent the deferral; 2
(2) Column 5, titled “2022 Base” is the adjusted 3
base to which the methods to create a 2023 test year were 4
applied; 5
(3) Column 6, titled “Forecast Adjustments”, 6
reflects the results of the various methods from the 7
Forecast Methodology Manual sponsored by Mr. Larkin and 8
detailed in his testimony, that were used to adjust totals 9
from the 2022 Base to a 2023 Unadjusted Test Year. 10
(4) Column 7, titled “2023 Unadjusted Test Year”, 11
includes the resulting dataset once the standard regulatory 12
adjustments and various methods were applied; 13
(5) Column 8, titled “Annualizing Adjustment”, 14
includes standard annualizing adjustments, to reflect 15
changes that occur within the test year, but need to be 16
incorporated for the full year on an ongoing basis. All 17
annualizing adjustments included in this filing were 18
discussed earlier in my testimony. 19
(6) Column 9, titled “2023 Test Year”, is the 20
resulting dataset for the 2023 test year (twelve months 21
ending December 31, 2023). 22
Q. How did you develop the total combined rate base 23
for the 2023 Test Year? 24
A. Page two of Exhibit No. 34 summarizes the 25
NOE, DI 9
Idaho Power Company
development of rate base components for the 2023 Test Year. 1
The total combined rate base, based on actual, unadjusted 2
2022 results was $3,870,331,388 (column 3, line 67). After 3
adjustments, the total combined rate base for the 2023 Test 4
Year increases to $4,092,522,974 (column 9, line 67). 5
Q. Have you prepared any exhibits that detail the 6
total system net income? 7
A. Yes. Page two of Exhibit No. 34 also includes the 8
development of the total system net income for the twelve 9
months ending December 31, 2023. Operating revenues are 10
summarized on line 73. Total operating expenses are 11
summarized on line 84. 12
Idaho Jurisdictional Revenue Requirement 13
Q. Have you prepared an exhibit that sets forth the 14
Idaho jurisdictional revenue deficiency? 15
A. Yes. I prepared Exhibit No. 35 titled 16
“Jurisdictional Separation Study – Idaho Revenue 17
Requirement” consisting of 36 pages. 18
Q. Please describe what is included in the 19
Jurisdictional Separation Study report. 20
A. Exhibit No. 35 is the complete Jurisdictional 21
Separation Study report detailing the allocation of each 22
component of rate base, operating revenues, and expenses by 23
Federal Energy Regulatory Commission (“FERC”) account 24
resulting in the Idaho jurisdictional revenue deficiency. 25
NOE, DI 10
Idaho Power Company
The JSS is organized as follows: 1
• Summary of Results 2
• Table 1 - Electric Plant in Service; 3
• Table 2 - Accumulated Provision for 4
Depreciation (and Amortization); 5
• Table 3 - Additions & Deductions to Rate Base; 6
• Table 4 - Operating Revenues; 7
• Table 5 - Operation & Maintenance Expenses; 8
• Table 6 - Depreciation & Amortization Expense; 9
• Table 7 - Taxes Other Than Income Taxes; 10
• Table 8 - Regulatory Debits & Credits; 11
• Table 9 - Income Taxes; 12
• Table 10 - Calculation of Federal Income Tax; 13
• Table 11 – Oregon State Income Tax; 14
• Table 12 – Idaho State Income Tax and Other 15
State Income Tax; 16
• Table 13 - Development of Labor Related 17
Allocator; 18
• Table 14 - Allocation Factors; 19
• Table 15 - Allocation Factors-Ratios. 20
Q. Please discuss the methodology used to 21
jurisdictionally separate costs in the preparation of this 22
study. 23
A. A three-step process was used to separate costs 24
NOE, DI 11
Idaho Power Company
among jurisdictions. The three steps are 1
functionalization, classification, and allocation of costs. 2
In all three steps, recognition was given to the way in 3
which costs are incurred by relating these costs to utility 4
operations. 5
Q. Would you please briefly explain what each of the 6
three steps (functionalization, classification, and 7
allocation) entails? 8
A. Functionalized costs are identified with utility 9
operating functions such as generation, transmission, and 10
distribution. Individual plant items are examined and, 11
where possible, the associated investment costs are 12
assigned to one or more operating functions. Classification 13
groups the functionalized costs into three categories: 14
demand-related, energy-related, and customer-related. 15
Once the Company’s total system costs are classified 16
and assigned to the appropriate function, they are 17
allocated among jurisdictions. 18
The process of allocation is one of apportioning the 19
total system cost among jurisdictions by introducing 20
allocation factors into the process. An allocation factor 21
is an array of numbers which specifies the jurisdictional 22
value as a share or percent of the total system quantity. 23
For example, in the case of energy-related costs, the 24
allocation factor is annual jurisdictional energy use, 25
NOE, DI 12
Idaho Power Company
adjusted for losses, divided by the total system energy 1
use. 2
Once individual accounts have been allocated to the 3
various jurisdictions, it is possible to summarize these 4
into total utility rate base and net income by 5
jurisdiction. The results are stated in a summary form to 6
measure adequacy of revenues for the jurisdiction under 7
consideration. The measure of adequacy is typically the 8
rate of return earned on rate base, which is compared to 9
the requested rate of return. 10
Q. Is the methodology used to separate costs by 11
jurisdiction and calculate the Idaho jurisdictional revenue 12
requirement in the present case primarily the same 13
methodology utilized in the Company’s last general rate 14
case, Case No. IPC-E-11-08? 15
A. Yes. 16
Q. How have the various functional plant and cost 17
items been allocated? 18
A. The average of the twelve monthly coincident peak 19
demands was used to allocate the demand-related costs. 20
This allocation method has been used by the Company for at 21
least two decades in all of its filings requiring a 22
jurisdictional separation study. This allocation method 23
was adopted by this Commission and also accepted by the 24
Public Utility Commission of Oregon. The demand-related 25
NOE, DI 13
Idaho Power Company
allocation factors used in the study are designated as D10, 1
D11, D12 and D60. The respective values used in these 2
demand allocation factors are shown at line numbers 1048 3
through 1051 of Exhibit No. 35. 4
Q. How were the energy-related expenses allocated 5
among jurisdictions? 6
A. Energy-related expenses were allocated based on 7
normalized jurisdictional kilowatt-hour sales and adjusted 8
for losses to establish energy requirements at the 9
generation level. The energy-related allocation factors 10
used in the study are designated as E10 and E99. The 11
respective values used in these energy allocation factors 12
are shown on lines 1054 and 1055 of Exhibit No. 35. 13
Q. What was the method by which you allocated 14
customer-related costs? 15
A. The principal customer-related expenses which 16
required allocation, were meter reading (FERC Account 902) 17
and customer accounting and billing (FERC Account 903). 18
These accounts were allocated based upon a review of actual 19
costs to read meters and prepare monthly bills or 20
statements. 21
Q. What method was used to allocate certain labor-22
related administrative and general expenses? 23
A. In accordance with FERC-approved procedures, 24
administrative and general expenses were allocated in 25
NOE, DI 14
Idaho Power Company
accordance with functionalized wages and salaries. These 1
labor-related allocation factors are shown on lines 848 2
through 1043 of Exhibit No. 35. 3
Q. Please describe the derivation of the 2023 total 4
system allocation factors used in this case. 5
A. The allocation factors in the 2023 JSS were based 6
on either the 2022 year-end data or 2023 forecast data. 7
The capacity or demand–related allocation factors (D10, 8
D11, D12 and D60) were created using the 2022 demand ratios 9
from the load research analysis applied to the 2023 test 10
year energy. The energy-related allocation factors were the 11
2023 test year load at generation level (E10) and at 12
customer level (E99). This data is prepared by the 13
Company’s Load Research and Forecasting Department and is 14
further described in workpapers filed by Mr. Larkin. 15
Q. Briefly describe the manner in which you 16
allocated electric plant-in-service as shown in Table 1 of 17
Exhibit No. 35. 18
A. Both production and transmission plant were 19
allocated to each jurisdiction based on the average of the 20
twelve-monthly coincident peaks. Distribution plant, 21
unless otherwise noted, was directly allocated to Idaho 22
based on 2022 actual jurisdictional data. 23
Q. Please describe the manner in which you allocated 24
general electric plant-in-service. 25
NOE, DI 15
Idaho Power Company
A. General plant was allocated on the same basis as 1
the sum of the allocated investments in production, 2
transmission, and distribution plant. 3
Q. How have you allocated the accumulated provision 4
for depreciation and amortization of other utility plant? 5
A. Accumulated provision for depreciation and 6
amortization totals, as shown on Table 2 of Exhibit No. 35, 7
were allocated based on the related plant account as 8
allocated in Table 1. 9
Q. How did you allocate other additions to or 10
deductions from rate base? 11
A. Table 3 of Exhibit No. 35 details the allocation 12
of all other additions to or deductions from rate base. 13
Deductions from rate base include customer advances for 14
construction that were directly assigned to customers by 15
jurisdiction, and the accumulated deferred income taxes 16
that were allocated by plant, customer advances for 17
construction, and labor. Additions to rate base include: 18
(1) materials and supplies which were functionalized and 19
allocated by the respective plant allocators, (2) fuel 20
inventory that was allocated on the basis of energy, (3) 21
components of Idaho Energy Resources Co. (“IERCo”) the 22
Company’s fuel subsidiary, which were allocated based on 23
energy, and (4) Commission-ordered deferred investment was 24
either directly assigned to a specific jurisdiction or 25
NOE, DI 16
Idaho Power Company
allocated based on demand. 1
All rate base items, with the exception of other 2
deferred programs, reflect a 13-month average of ending 3
balances or average of year-end balances. 4
Q. How did you assign the firm operating revenues to 5
each jurisdiction? 6
A. Table 4 of Exhibit No. 35 contains the firm 7
operating revenues directly assigned to each jurisdiction 8
for the test year (twelve months ending December 31, 2023). 9
Opportunity sales and financial losses are also credited to 10
each jurisdiction in proportion to generation-level energy 11
use. 12
Other operating revenues were either allocated among 13
jurisdictions in a manner that offset related allocations 14
of rate base or, where a particular revenue item could be 15
associated with a specific jurisdiction, directly assigned. 16
Lastly, at the direction of Mr. Larkin I included the 17
transfer adjustments for both the Power Cost Adjustment 18
(“PCA”) mechanism and the Energy Efficiency rider labor in 19
this table to more accurately reflect the net impact to 20
customers in the revenue requirement calculation. The 21
Direct Testimony of Mr. Pawel Goralski details the 22
quantification of the revenue transfer from the PCA, and 23
Mr. Larkin details the quantification of the Energy 24
Efficiency rider offset. 25
NOE, DI 17
Idaho Power Company
Q. How are operation and maintenance expenses 1
allocated to each jurisdiction? 2
A. The allocation of each O&M expense is detailed on 3
Table 5 of Exhibit No. 35. In general, the basis for each 4
allocation is identifiable with the source code listed on 5
Exhibit No. 35. Demands are identified by a source code 6
beginning with a “D” prefix, energy use is identified by a 7
source code beginning with an “E” prefix, related plant is 8
identified by a line number source code, and customer-9
weighted allocation factors begin with a “CW” prefix. 10
Q. In what manner are supervision and engineering 11
expenses treated throughout the allocation of operation and 12
maintenance expenses? 13
A. For the applicable expense account in each 14
functional group, the labor component was separately 15
allocated in accordance with the detail provided on Table 16
13 of Exhibit No. 35. The total of allocated labor in each 17
functional group became the basis for the allocation of 18
supervision and engineering expense. Total allocated labor 19
expense served the additional purpose of allocating 20
employee pension and other labor-related taxes and 21
expenses. Table 13 of Exhibit No. 35 details the 22
development of all the labor-related allocation factors 23
used in this study. 24
Q. How have you allocated depreciation expense and 25
NOE, DI 18
Idaho Power Company
amortization of limited term plant? 1
A. The allocation of depreciation expense and 2
amortization of limited term plant is set forth in Table 6 3
of Exhibit No. 35. These expenses were identified by type 4
of production plant or by primary plant account for other 5
functional plant groups and allocated consistent with the 6
related plant account. 7
Q. How did you approach the allocation of taxes 8
other than income taxes? 9
A. As set forth in Table 7 of Exhibit No. 35, taxes 10
other than income taxes were treated individually and 11
allocated in a manner consistent with the bases by which 12
the respective taxes are assessed. 13
Q. How did you address the amortization of 14
regulatory debits and credits? 15
A. Table 8 of Exhibit No. 35 details the 16
amortization of regulatory debits and credits and were 17
directly assigned to the appropriate jurisdiction. 18
Q. Does the JSS report detail how deferred income 19
taxes and investment tax credit adjustments were allocated? 20
A. Yes. The expenses shown on Table 9 of Exhibit No. 21
35 consist of deferred income taxes and the investment tax 22
credit adjustments, which were allocated based on the 23
Company’s plant investment and net income before tax 24
adjustments. State and federal income tax liabilities are 25
NOE, DI 19
Idaho Power Company
also summarized on Table 9. The income taxes shown on 1
Tables 10 through 12 were obtained from the Company’s Tax 2
Department. 3
Q. How were federal and state income taxes, shown on 4
Tables 10 through 12 of Exhibit No. 35, allocated in the 5
JSS? 6
A. The respective tax bases were developed, and 7
taxes were calculated directly for each jurisdiction. 8
Operating income before taxes represents adjusted operating 9
revenues less all adjusted operating expenses treated 10
heretofore with the exception of deferred income taxes and 11
investment tax credits. Adjusted interest expense was 12
allocated by the combined rate base to develop net 13
operating income before taxes. As discussed earlier in 14
this testimony, subsequent additions to or deductions from 15
the respective tax bases were allocated to each 16
jurisdiction by aligning it with its causation or 17
fundamental association. In this manner, taxable income 18
for each jurisdiction was developed and the appropriate tax 19
rate was applied. Final tax amounts result after the 20
allocation of adjustments and tax credits. All details 21
relating to the calculation of federal, Oregon, Idaho, and 22
other state income taxes are found on Tables 10, 11, and 23
12. 24
Q. What is the purpose of Tables 13 through 15 of 25
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Idaho Power Company
Exhibit No. 35? 1
A. Tables 13 through 15 of Exhibit No. 35 list the 2
principal allocation factors used in the JSS and the 3
respective jurisdictional values for each allocation 4
factor. Table 15 lists the ratios of the principal 5
allocation factors included in Table 14. 6
Q. How was the Idaho jurisdictional revenue 7
deficiency developed? 8
A. The summary of JSS results is presented on pages 9
one and two of Exhibit No. 35. The development of the Idaho 10
jurisdictional revenue deficiency is presented in the 11
column entitled “Idaho Retail” on page one of Exhibit No. 12
35. As discussed further in Mr. Larkin’s testimony, due to 13
the approved balancing account mechanisms for recovery of 14
coal-related costs at the Jim Bridger Power Plant 15
(“Bridger”) and North Valmy Power Plant (“Valmy”), a true 16
revenue deficiency cannot be computed until the levelized 17
revenue requirement associated with these mechanisms is 18
accounted for in the calculation. While the approved 19
revenue collection is embedded in the Firm Jurisdictional 20
Sales contained on line 9 of the JSS, the corresponding 21
costs were removed from the determination of the Company’s 22
non-levelized revenue requirement as described by Mr. 23
Larkin. Therefore, JSS summary information contained on 24
lines 6 through 38 will understate required revenues 25
NOE, DI 21
Idaho Power Company
because it only reflects currently approved revenues 1
related to non-fuel coal recovery, not the corresponding 2
currently approved costs. 3
Q. How was the Idaho jurisdictional revenue 4
requirement calculated before adjusting for Bridger and 5
Valmy? 6
A. The pre-adjusted Idaho consolidated operating 7
income of $287,151,546 (line 26) resulted in a return on 8
rate base of 7.34 percent (line 27). Based upon the 9
Company’s request for an overall rate of return of 7.702 10
percent provided by Company Witness Mr. Brian Buckham, the 11
Company’s Idaho jurisdictional net income should be 12
$301,346,128, as shown on line 32. The resulting earnings 13
deficiency is $14,194,582, as shown on line 33. Inclusion 14
of Hells Canyon Relicensing Construction Work in Progress 15
allowed in the Company’s most recent rate case (Case No. 16
IPC-E-11-08) of $6,537,444, as shown on line 34, increases 17
the earnings deficiency to $20,732,026, as shown on line 18
35. Once again, as discussed previously, this figure is 19
understated and must be adjusted because it includes 20
Bridger and Valmy coal-related revenue recovery without 21
reflecting the corresponding costs. 22
Q. What net-to-gross or incremental income tax 23
factor did you use in developing the Idaho jurisdictional 24
revenue deficiency? 25
NOE, DI 22
Idaho Power Company
A. The composite incremental tax multiplier of 1.347 1
is the assimilation of the federal effective tax rate, an 2
Idaho composite tax rate, an Oregon composite tax rate, and 3
an additional state composite tax rate. This value, as 4
shown on line 37 of Exhibit No. 35, was provided by the 5
Company’s Tax Department and is included in my workpapers. 6
Q. Why were the Valmy and Bridger revenue 7
requirements added to the Idaho Jurisdictional revenue 8
deficiency calculation contained on lines 40 and 41 of the 9
JSS? 10
A. To determine the true revenue deficiency, at Mr. 11
Larkin’s direction the levelized revenue requirements for 12
Valmy and Bridger were added to the Idaho Jurisdictional 13
revenue requirement calculation on lines 40 and 41, 14
respectively. The addition of these amounts appropriately 15
includes the costs authorized for recovery through these 16
mechanisms to align with the currently approved retail 17
rates embedded in the 2023 Test Year retail revenue 18
forecast. In addition, as discussed in Mr. Larkin’s 19
testimony, the Company is requesting recovery of the full 20
annual levelized revenue requirement approved in Case No. 21
IPC-E-21-17 and amortization of previously deferred 22
levelized revenue requirement amount. 23
Q. Were any other adjustments included in the 24
revenue requirement calculation? 25
NOE, DI 23
Idaho Power Company
A. Yes, at the direction of Company Witness Mr. 1
Timothy Tatum, I calculated the Idaho jurisdictional 2
revenue requirement of the 120 MW of battery storage that 3
is scheduled to come online in 2023 and included that 4
result as a reduction to the Idaho jurisdictional revenue 5
requirement in an effort to mitigate the increase to 6
customers (“Battery Mitigation”) by adding the investment 7
tax credits to the current accumulated deferred investment 8
tax credit (“ADITC”) mechanism and adjusting the yearly 9
cap. The impact of this mitigation option is reflected on 10
line 42 of the JSS and is discussed fully in the testimony 11
of Mr. Tatum. 12
Q. What is the resulting Idaho jurisdictional 13
revenue deficiency including the Battery Mitigation? 14
A. The result of the Jurisdictional Separation 15
Study, as shown on page one, line 43 of Exhibit No. 35, 16
indicates a total revenue deficiency of $111.3 million for 17
the Idaho retail jurisdiction. This represents a required 18
8.61 percent increase in normalized Idaho jurisdictional 19
revenues. 20
Q. Does this conclude your testimony? 21
A. Yes, it does. 22
// 23
// 24
// 25
NOE, DI 24
Idaho Power Company
DECLARATION OF KELLEY NOE 1
I, Kelley Noe, declare under penalty of perjury 2
under the laws of the state of Idaho: 3
1. My name is Kelley Noe. I am employed by 4
Idaho Power Company as 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. 31-35 in this 8
matter. 9
3. To the best of my knowledge, my pre-filed 10
direct testimony and exhibit 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
Kelley Noe 19 20
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