20230601Direct Brady.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
JESSICA G. BRADY
BRADY, 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 Jessica G. Brady. My business 4
address is 1221 West Idaho Street, Boise, Idaho 83702. I am 5
employed by Idaho Power as a Regulatory Analyst in the 6
Regulatory Affairs Department. 7
Q. Please describe your educational background. 8
A. In May 2016, I received a Bachelor of Science 9
degree in Economics and a Bachelor of Arts degree in 10
Spanish from the University of Idaho. I have also attended 11
“The Basics: Practical Regulatory Training for the Electric 12
Industry,” an electric utility ratemaking course offered 13
through New Mexico State University’s Center for Public 14
Utilities, and “Electric Utility Fundamentals & Insights,” 15
an electric utility course offered through the Western 16
Energy Institute. 17
Q. Please describe your work experience with 18
Idaho Power. 19
A. In September 2021, I accepted my current 20
position at Idaho Power as a Regulatory Analyst in the 21
Regulatory Affairs Department. As a Regulatory Analyst, I 22
am responsible for running the AURORA model (“AURORA”) to 23
calculate net power supply expenses (“NPSE”) for ratemaking 24
purposes, as well as the determination of the marginal cost 25
BRADY, DI 2
Idaho Power Company
of energy used in the Company’s marginal cost analyses. My 1
duties also include providing analytical support for other 2
regulatory activities within the Regulatory Affairs 3
Department. 4
Q. What is the purpose of your testimony in this 5
matter? 6
A. The purpose of my testimony is to discuss the 7
derivation of the Company’s 2023 retail revenue forecast 8
used for the 2023 test year, detail the proposed energy-9
related test year billing components, present the 10
quantification of 2023 normalized or “base level” net power 11
supply expenses (“2023 Base Level NPSE”) and inform the 12
Commission of the necessary reduction to the rates 13
contained in Schedule 55, Power Cost Adjustment (“PCA”) 14
resulting from the proposed 2023 Base Level NPSE update. 15
I. 2023 TEST YEAR RETAIL REVENUE DERIVATION 16
Q. What methodology was used to determine test 17
year retail revenues? 18
A. Generally speaking, the Company’s retail 19
revenue forecast is derived by applying current base rates 20
to forecasted test year billing components. These billing 21
components are derived by applying historical relationships 22
to the Company’s customer and kilowatt-hour (“kWh”) sales 23
forecast. 24
BRADY, DI 3
Idaho Power Company
Q. Was the 2023 test year retail sales revenue 1
forecast developed using the same methodology applied in 2
the Company’s last general rate case, Case No. IPC-E-11-08 3
(“2011 Rate Case”)? 4
A. Yes. The 2023 test year retail sales revenue 5
forecast was developed using the same methodology applied 6
in the 2011 Rate Case. 7
Q. Please describe the customer and kWh sales 8
forecast that serves as the basis for the 2023 test year 9
retail revenue forecast. 10
A. The 2023 test year customer and kWh sales 11
forecast consists of class customer counts and total kWh 12
sales estimates for each month of the test period. It is 13
prepared by the Company’s Load Research and Forecasting 14
Department and is further described in workpapers filed by 15
Company Witness Mr. Matthew Larkin. 16
Q. How were the 2023 test year kWh sales further 17
segmented into the class-specific energy-related billing 18
components? 19
A. The first step in deriving energy-related 20
billing components for the test year is to develop factors 21
based on the most current complete calendar year of 22
available historical data, which in this case is 2022. 23
These historical factors represent the percentage of total 24
kWh billed in each tier level of a class’s rate structure. 25
BRADY, DI 4
Idaho Power Company
To illustrate, Residential Service customers taking 1
service under Schedule 1 are billed according to a three-2
tiered structure with seasonal rate differentiation. Using 3
the historical month of June 2022 as an example, actual 4
tiered usage was recorded at the following levels for 5
Schedule 1 customers in the Idaho jurisdiction: 6
Table 1 7
2022 Actual Tiered Usage 8
9 Based on the data above, historical factors for 10
Schedule 1 customers for the month of June were calculated 11
as shown in Table 2. 12
// 13
// 14
15
16 Table 2 17

1 Totals in tables may not tie due to rounding.
Table 1 2022 Actual Tiered Usage
Usage Tier Billing Components
Summer, 0-800 kWh 105,736,225
Summer, 801-2000 kWh 26,415,166
Summer, Over 2000 kWh 3,257,841
Non-Summer, 0-800 kWh 168,424,645
Non-Summer, 801-2000 kWh 42,615,564
Non-Summer, Over 2000 kWh 6,376,771
Total Schedule 1 kWh Usage 352,826,2111
BRADY, DI 5
Idaho Power Company
Historical Weighting Factors 1
2 This process is used to develop historical factors 3
for all rate classes with tiered structures. Once a 4
complete set of monthly factors has been developed for each 5
applicable rate class, they are applied to monthly forecast 6
kWh totals to derive the energy-related billing component 7
forecast that aligns with each class’s current rate 8
structure. Continuing with the illustration of Schedule 1 9
customers, Table 3 demonstrates the final step in 10
determining test year energy-related billing components. 11
// 12
// 13
14
15
16
Table 3 17
Table 2 Historical Weighting Factors
Usage Tier
Summer, 0-800 kWh 30%
Summer, 801-2000 kWh 7%
Summer, Over 2000 kWh 1%
Non-Summer, 0-800 kWh 48%
Non-Summer, 801-2000 kWh 12%
Non-Summer, Over 2000 kWh 2%
Total Schedule 1 100%
BRADY, DI 6
Idaho Power Company
Billing Component Forcast 1
Q. How are demand-related billing components derived 2
based on the kWh sales forecast? 3
A. The demand-related billing components consist 4
of billing demand and basic load capacity (“BLC”) by month 5
for each rate class. Both billing demand and BLC totals are 6
forecasted by applying four-year average load factors to 7
each month in the kWh sales forecast. Historical data from 8
the most currently available four calendar years is used to 9
derive an average load factor by month for each rate class. 10
These average factors are then applied to monthly kWh sales 11
figures to determine total forecasted billing demand and 12
BLC by class for each month of the test period. Once 13
monthly totals have been developed, they are divided into 14
the appropriate tiered rate structure (if applicable) 15
Table 3 Billing Component Forecast
Usage Tier Weighting Factor
June 2023
Forecast (kWh)
Summer, 0-800 kWh 30% 108,107,252
Summer, 801-2000 kWh 7% 27,007,499
Summer, Over 2000 kWh 1% 3,330,895
Non-Summer, 0-800 kWh 48% 172,201,397
Non-Summer, 801-2000 kWh 12% 43,571,175
Non-Summer, Over 2000 kWh 2% 6,519,763
Total 100% 360,737,981
BRADY, DI 7
Idaho Power Company
utilizing historical factors in the same manner as kWh 1
charges. 2
Q. How are customer-related billing components 3
derived based on the customer count forecast? 4
A. The primary customer-related billing component 5
in the retail revenue forecast is the service charge. 6
Because the customer forecast reflects the expected number 7
of customers under active Utility Service Agreements 8
(“USAs”) at the end of each forecast month, forecast values 9
must be converted to reflect the expected number of service 10
charges received throughout the corresponding month. To 11
convert the USA forecast to an expected service charge 12
count, historical factors are developed reflecting the 13
relationship between the number of USAs at the end of each 14
historical month and the number of service charges received 15
during the corresponding month. These factors are then 16
applied to the monthly customer forecast to develop a 17
forecast of expected service charges by rate class for each 18
month of the test year. 19
Q. How are test year retail revenues calculated 20
once the billing component forecast has been derived? 21
A. Once the billing components have been 22
forecasted by rate class, the most currently approved base 23
rates are applied to the test year values to derive monthly 24
revenue estimates for each rate class. 25
BRADY, DI 8
Idaho Power Company
Q. Have you prepared any exhibits that detail the 1
calculations that were made to determine the Company’s 2023 2
test year retail revenues? 3
A. Yes. Exhibit No. 27 provides a summary of 4
forecasted 2023 test year retail revenues, and Exhibit No. 5
28 details the calculations that were made to determine 6
these revenues. Input data used in the forecast 7
calculations can be found in my workpapers. As can be seen 8
on page 3 of Exhibit No. 27, the Company’s 2023 Idaho 9
jurisdictional retail sales revenues are forecast to be 10
$1.12 billion. 11
Q. How is the portion of Micron Technology’s 12
(“Micron”) forecast kWh sales that will be met by Black 13
Mesa Solar treated in the 2023 test year retail revenues? 14
A. As described in the Direct Testimony of Mr. 15
Matthew Larkin, as part of the new Special Contract with 16
Micron, Black Mesa Solar’s generation will be paid for 17
completely by Micron. To account for this, the revenue from 18
the portion of Micron’s load that will be met by Black Mesa 19
Solar is not included in the 2023 retail revenue forecast. 20
The treatment of the revenue associated with the portion of 21
Micron’s load met by Black Mesa Solar is discussed further 22
in the Direct Testimony of Mr. Paul Goralski. 23
BRADY, DI 9
Idaho Power Company
II. 2023 ENERGY-RELATED BILLING COMPONENTS – PROPOSED RATE 1
STRUCTURE 2
Q. Please describe the energy-related billing 3
components under the Company’s proposed rate structure 4
(“proposed billing components”). 5
A. As described in the Direct Testimony of Ms. 6
Connie Aschenbrenner, the Company’s proposed rate structure 7
includes modifying the months considered to be “summer” and 8
“non-summer”, as well as the time-of-use periods for 9
certain time variant rate classes. The proposed billing 10
components represent the total forecast kWh billed in each 11
tier within each rate class, under the new proposed rate 12
structure. 13
Q. How were the proposed billing components 14
calculated? 15
A. The proposed billing components were 16
calculated using the same methodology as the billing 17
components calculated for the derivation of the 2023 test 18
year retail revenues. However, instead of using 2022 19
billing data to derive historical factors, 2022 kWh usage 20
data, divided into tiers based on the proposed rate 21
structure for each rate class, was used. 22
Q. How was the 2022 kWh usage data collected and 23
divided into the proposed tiers? 24
BRADY, DI 10
Idaho Power Company
A. The process for collecting 2022 kWh usage data 1
is described in workpapers filed by Mr. Larkin. 2
Q. Have you prepared an exhibit that details the 3
Company’s 2023 proposed billing determinants? 4
A. Yes. Exhibit No. 29 provides a summary of the 5
2023 proposed billing determinants. 6
III. 2023 BASE NET POWER SUPPLY EXPENSES 7
Q. How is this section of your testimony 8
organized? 9
A. First, I provide an overview of the 10
Commission-approved method for quantifying base level NPSE. 11
Next, I describe the update to base level NPSE that 12
occurred in 2013 (“2013 Base Level NPSE”). Lastly, I 13
describe the quantification of the Company’s 2023 Base 14
Level NPSE. 15
Q. How has the Commission historically reviewed 16
and approved Idaho Power’s quantification of normal base 17
NPSE? 18
A. Due to the high variability of power supply 19
expenses, the Commission has historically approved a 20
normalized power supply expense value for setting base 21
rates. The Company has utilized the AURORA model to provide 22
the Commission with a snapshot of “normal” expectations for 23
base NPSE for a given test year. 24
BRADY, DI 11
Idaho Power Company
Q. Please define the term “base NPSE” as the 1
Company and Commission have used the term historically. 2
A. The Company and Commission have historically 3
defined the term “base NPSE” as the sum of fuel expenses 4
(Federal Energy Regulatory Commission [“FERC”] Accounts 501 5
and 547) and purchased power expenses (FERC Account 555), 6
including purchases from qualifying facilities under the 7
Public Utility Regulatory Policies Act of 1978 (“PURPA”) 8
and power purchase agreements (“PPA”), minus surplus sales 9
revenues (FERC Account 447). The AURORA model is used to 10
quantify base NPSE components related to fuel and surplus 11
sales, while PURPA and PPA expenses are quantified outside 12
of AURORA; however, energy from these projects is modeled 13
as must-take in the AURORA simulation. 14
Q. Does the Company include any other categories 15
of expense or revenue in the base level NPSE used for PCA 16
computations? 17
A. Yes. In addition to the expense and revenue 18
categories described above, the base level NPSE included in 19
the Company’s PCA computations also includes financial 20
payments made by Idaho Power to offset transmission losses 21
associated with market purchases (FERC Account 555), third-22
party transmission expense required to bring market 23
purchases to the Company’s border (FERC Account 565), water 24
BRADY, DI 12
Idaho Power Company
for power expense (FERC Account 536), and demand response 1
(“DR”) incentives (FERC Account 555). 2
Q. Is the Company proposing to include any new 3
categories of expense or revenue in the base level NPSE 4
used for PCA computations? 5
A. Yes. At the direction of Mr. Larkin, I have 6
included an additional component, FERC Account 447.050, 7
transmission loss revenue, in the 2023 Base Level NPSE. 8
According to the FERC’s Uniform System of Accounts, these 9
amounts are recorded to Account 447. 10
Q. What does the transmission loss revenue 11
component of Account 447 represent? 12
A. As further discussed in Mr. Larkin’s 13
testimony, transmission loss revenue in FERC Account 447 14
reflects revenues received by Idaho Power from third 15
parties to compensate the Company for physically generating 16
electricity to offset losses associated with wheeling 17
energy through Idaho Power’s transmission system. 18
Q. How does the Company arrive at a “normalized” 19
look at base NPSE for ratemaking purposes? 20
A. In order to “normalize” base NPSE, the Company 21
uses AURORA to model various water conditions using current 22
loads and current resources. At this time, 37 water 23
conditions have been evaluated to develop an average or 24
normalized NPSE. This general methodology was adopted by 25
BRADY, DI 13
Idaho Power Company
the Commission in 1981 and has been used in general rate 1
proceedings ever since. 2
Q. What is the currently approved base level 3
NPSE amount? 4
A. The currently approved 2013 Base Level NPSE 5
is $305,684,869. It is comprised of the following 6
components: 7
Table 4 8
2013 Bale Level NPSE 9
Table 4 2013 Base Level NPSE
95% Accounts (with 95% recovery in PCA)
100% Accounts (with 100% recovery in PCA)
10
Q. When was the currently approved base level 11
NPSE established and approved by the Commission? 12
A. The 2013 Base Level NPSE was established on 13
March 21, 2014, by Order No. 33000 issued in Case No. IPC-14
E-13-20. 15
BRADY, DI 14
Idaho Power Company
Q. Since the establishment of the 2013 Base Level 1
NPSE, has the Company made any modifications to the AURORA 2
model that was used to develop the 2023 Base Level NPSE? 3
A. Yes. In order to quantify the 2023 Base Level 4
NPSE, the Company utilized a new AURORA version and 5
database, which reflects updated inputs for the entire 6
Western Electricity Coordinating Counsel (“WECC”) 7
footprint. This database was also used in the development 8
of the Company’s 2021 Integrated Resource Plan (“IRP”), 9
which was acknowledged by the Commission on November 18, 10
2022, in Order No. 35603 issued in Case No. IPC-E-21-43. 11
The Company also updated the database to include resource 12
changes, current fuel prices, heat rates, forced outage 13
rates, maintenance schedules, and plant capacities. 14
Q. Were any adjustments made to the resources 15
included in the 2023 AURORA Model? 16
A. Yes. Idaho Power updated expected generation 17
from PURPA projects based on current or expected contracts. 18
Additionally, the 2023 AURORA model includes the removal of 19
two resources, Boardman Coal and North Valmy Unit 1, and 20
the addition of six resources. The six resources are listed 21
below.22
BRADY, DI 15
Idaho Power Company
New Resources included in the 2023 AURORA Model 1
1. Bridger Gas 2
2. Jackpot Solar PPA 3 3. Black Mesa Solar PPA 4
4. Black Mesa Battery 5 5. 80-Megawatt (“MW”) Grid Battery 6 6. Demand Response 7
Q. Please describe the Bridger Gas resource, 8
including how it was modeled for the development of the 9
2023 Base Level NPSE. 10
A. The Company’s 2021 IRP Action Plan includes 11
the conversion of Bridger units 1 and 2 from coal to 12
natural gas by summer 2024. As discussed further in Mr. 13
Larkin’s testimony, I was directed to model Bridger units 1 14
and 2 as natural gas units online for the entire 2023 test 15
year in order to more closely align 2023 Base Level NPSE 16
with the time period in which rates will take effect. 17
Q. How were Jackpot Solar and Black Mesa Solar 18
modeled for the development of the 2023 Base Level NPSE? 19
A. Jackpot Solar, which came online December 20
2022, is a 120-MW alternating current solar photovoltaic 21
generation facility. It is a 20-year PPA with Jackpot 22
Holdings, LLC. 23
Black Mesa Solar is a 40-MW alternating current 24
solar photovoltaic facility that is scheduled to come 25
online June 2023. As described previously in my testimony, 26
and further detailed in Mr. Larkin’s testimony, Black Mesa 27
Solar is a PPA that was negotiated in conjunction with a 28
BRADY, DI 16
Idaho Power Company
new Special Contract with Micron Technology. The Micron 1
Special Contract states that Idaho Power will procure 2
renewable resources to assist Micron in meeting a portion 3
of its annual energy requirements with energy generated by 4
those resources. While Black Mesa Solar will be connected 5
to the Company’s system and will not serve Micron directly, 6
Micron will pay for 100 percent of the output through its 7
Special Contract. As a result, the cost of the PPA is 8
excluded from the 2023 Base Level NPSE. 9
The Company modeled both Jackpot Solar and Black 10
Mesa Solar’s generation in AURORA by applying the projects’ 11
forecast hourly shape to the monthly forecasted generation 12
amounts. In addition, Black Mesa Solar was modeled as an 13
annualized online resource for the entire test year, in 14
line with the Company’s typical practice for resources 15
expected to come online during the test year. 16
Q. How were the two new battery resources modeled 17
for the development of the 2023 Base Level NPSE? 18
A. The two new battery resources include a 40-MW 19
battery at Black Mesa Solar and an 80-MW grid battery. The 20
Black Mesa Battery is scheduled to come online September 21
2023 and the 80-MW grid battery is scheduled to come online 22
June 2023. Similar to Bridger Gas and Black Mesa Solar, 23
both batteries were modeled as annualized online resources 24
for the entire test year. 25
BRADY, DI 17
Idaho Power Company
The 80-MW grid battery is modeled to be charged from 1
the entire grid, while the Black Mesa Battery is modeled to 2
only be charged from Black Mesa Solar. 3
Q. How was demand response modeled for the 4
development of the 2023 Base Level NPSE? 5
A. Demand response was modeled according to the 6
parameters of its three programs: A/C Cool Credit, Flex 7
Peak Program, and Irrigation Peak Rewards. Based on actual 8
2022 participation, Idaho Power assumed the programs would 9
provide a total of 320 MW of peak capacity from June 1 – 10
September 15. 11
Q. Have there been any changes to the way PURPA 12
is modeled compared to the way it was modeled in the 2013 13
Base Level NPSE? 14
A. Yes. In the 2013 normalized NPSE 15
determinations, the Company segmented PURPA generation into 16
two categories, “PURPA Wind” and all “other PURPA”. PURPA 17
Wind was modeled by applying the 2012 hourly actual 18
historical PURPA Wind generation shape to the monthly 19
forecasted generation amounts. All other PURPA resources 20
were modeled on a monthly basis. 21
For the 2023 Base Level NPSE, the Company segmented 22
PURPA into three categories, “PURPA Wind”, “PURPA Solar”, 23
and all “other PURPA”. PURPA Wind was modeled by applying a 24
5-year average (2018 – 2022) hourly actual generation shape 25
BRADY, DI 18
Idaho Power Company
to the total nameplate capacity of the combined PURPA wind 1
projects. PURPA Solar was modeled by applying the 2022 2
actual hourly shape to the total monthly forecasted 3
generation amounts. All other PURPA resources were modeled 4
on a monthly basis, as hourly fluctuations do not occur to 5
as great an extent for those resource types. The Company 6
views the modification to be an improvement that more 7
accurately reflects the variable nature of solar into the 8
hourly dispatch modeling in AURORA. 9
Q. What other AURORA inputs were modified for the 10
development of the 2023 Base Level NPSE? 11
A. The Company included annualized forecast 12
generation from its Oregon Community Solar Program, which 13
is scheduled to come online November 2023. In addition, the 14
Company included 11 MW of distribution-connected battery 15
storage. 16
Q. Have you prepared an exhibit that presents the 17
normalization of variable power supply expenses consistent 18
with the changes you have described in your testimony? 19
A. Yes. Exhibit No. 30 shows the results 20
containing the 37-year average variable power supply 21
generation sources and expenses. 22
Q. Please summarize the sources and disposition 23
of energy shown on Exhibit No. 30. 24
BRADY, DI 19
Idaho Power Company
A. Hydro generation supplies 8.3 million 1
megawatt-hours (“MWh”), approximately 47 percent (8.3 2
million MWh / 17.8 million MWh = 47 percent) of the 3
generation mix. Thermal generation supplies 4.1 million MWh 4
(Bridger Coal 1.8, Bridger Gas 0.1, Valmy 0.2, Langley 5
Gulch 1.7, Danskin 0.2, Bennett Mountain 0.1), 6
approximately 23 percent (4.1 million MWh / 17.8 million 7
MWh = 23 percent) of the generation mix. Purchases of power 8
are made up of short-term and long-term market purchases, 9
as well as PURPA generation. Short-term market purchases 10
supply 1.4 million MWh, approximately 8 percent of the 11
generation mix. Long-term market purchases, or PPAs, supply 12
0.96 million MWh, approximately 5 percent of the generation 13
mix. PURPA purchases reflect normalized and annualized 14
generation levels and account for 3.0 million MWh, 15
approximately 17 percent of the generation mix. Total 16
purchases amount to 5.3 million MWh (1.4 million MWh + 0.96 17
million MWh + 3.0 million MWh = 5.3 million MWh) or 18
approximately 30 percent of the generation mix. Of the 19
17.8 million MWh generated by the system, 17.0 million MWh 20
are utilized for system loads while 0.8 million MWh are 21
sold as surplus sales. 22
Q. Please summarize the expenses associated with 23
each resource shown on Exhibit No. 30. 24
BRADY, DI 20
Idaho Power Company
A. Hydro generation has no assumed fuel expense. 1
Coal expenses of $65.5 million are comprised of Bridger at 2
$57.1 million and Valmy at $8.4 million. Gas expenses of 3
$119.7 million are comprised of Langley Gulch at $78.7 4
million, Bridger Gas at $6.1 million, Danskin at $13.8 5
million, and Bennett Mountain at $6.8 million. The fixed 6
capacity charge for gas transportation for all of the gas 7
plants is $14.3 million. Purchased power expenses 8
(including transmission losses, excluding PURPA) amount to 9
$99.5 million, and surplus sales revenue (including 10
transmission losses) is ($29.0) million. Transmission 11
losses will be discussed in more detail later in my 12
testimony. 13
Q. How have natural gas prices changed between 14
the time of quantification of the 2013 Base Level NPSE and 15
the 2023 Base Level NPSE quantification? 16
A. For the 2013 Base Level NPSE, natural gas 17
prices were assumed to be $3.62 per million British thermal 18
units (“MMBtu”) for Henry Hub and $3.68 per MMBtu for 19
natural gas delivered to the Company’s plants. For the 2023 20
Base Level NPSE, they are forecasted to be $3.36 per MMBtu 21
for Henry Hub, $4.28 per MMBtu for natural gas delivered to 22
Bridger, and $4.70 per MMBtu for natural gas delivered to 23
Langley, Bennett Mountain, and Danskin. 24
BRADY, DI 21
Idaho Power Company
Q. In general, how has base level NPSE and 1
generation changed from 2013 to 2023? 2
A. As described earlier in my testimony, since 3
2013 there have been several changes to Idaho Power’s 4
resource mix. These changes were incorporated into the 2023 5
AURORA model and are reflected in the calculated 2023 Base 6
Level NPSE. 7
Due to the decrease in coal capacity from the 8
removal of Boardman and North Valmy Unit 1, as well as the 9
conversion of Bridger units 1 and 2 to natural gas, 10
expenses related to coal generation have decreased 40 11
percent from 2013. In addition, due to the increased 12
reliance on natural gas generation and increase in natural 13
gas price, expenses related to natural gas generation have 14
increased 259 percent. 15
Next, Non-PUPRA purchased power expense has 16
increased 59 percent since 2013. This is a result of the 17
addition of the Jackpot Solar PPA, as well as the increase 18
in AURORA calculated market purchase volumes and market 19
prices. PURPA expense has increased 60 percent since 2013 20
as a result of increased PURPA generation and updated PURPA 21
contract values. 22
Lastly, surplus sales revenue has decreased 44 23
percent from 2013. As a result of the increase in system 24
load, decrease in coal capacity, and increase in natural 25
BRADY, DI 22
Idaho Power Company
gas prices, there are fewer opportunities to make economic 1
off-system sales in the 2023 test year. 2
Q. How are transmission losses on market 3
purchases (FERC Account 555) accounted for within the 4
Company’s calculation of 2023 Base NPSE? 5
A. Within the AURORA model, transmission losses 6
are incorporated into the market price paid by the 7
purchasing entity. In other words, the purchase price on 8
all short-term market purchases is grossed up to account 9
for transmission losses. As a result, the non-PURPA 10
purchased power expenses of $99.5 million included in FERC 11
Account 555 include both purchased power and transmission 12
losses on purchased power. 13
Q. Does the Company propose to update the base 14
level NPSE accounts that are not calculated by AURORA, or 15
partially calculated by AURORA, as part of this request? 16
A. Yes. The Company’s proposal reflects 2023 17
test year amounts for the below FERC Accounts. 18
19 Q. How did the Company determine the 2023 Base 20
Level amount for FERC Account 447.050, Transmission Loss 21
Revenue? 22
BRADY, DI 23
Idaho Power Company
A. FERC Account 447.050, Transmission Loss 1
Revenue, was forecasted by multiplying Idaho Power’s 2
average hourly marginal price, as calculated by AURORA, by 3
36 average MW, which is the assumed average MW generated in 4
each hour to serve third-party transmission losses. 5
Q. How did the Company determine the average 6
hourly MW generated to serve third-party transmission 7
losses? 8
A. The 36 MW was provided by the Load Research 9
and Forecasting Department and is further described in the 10
workpapers filed by Mr. Larkin. 11
Q. How did the Company determine the 2023 Base 12
Level amount for FERC Account 565, Third-Party Transmission 13
Expense? 14
A. The 2023 test year amount for FERC Account 15
565, Third-Party Transmission Expense, of $10.3 million was 16
calculated by multiplying the Company’s historical 3-year 17
average wheeling rate, based on total wheeling expenses and 18
volumes reported in the FERC Form 1, by the AURORA 19
calculated market purchase volumes. Information used in 20
this calculation can be found in my workpapers. 21
Q. How did the Company determine the 2023 Base 22
Level amounts for FERC Account 536.003, Water for Power and 23
FERC Account 555, Demand Response? 24
BRADY, DI 24
Idaho Power Company
A. FERC Account 536.003, Water for Power, is 1
forecast at 0 for the 2023 test year. Idaho Power did not 2
have water lease expense amounts in 2022 and does not 3
anticipate any for the 2023 test year. 4
FERC Account 555, Demand Response, was forecast for 5
the 2023 test year based on Idaho-jurisdictionalized 6
forecast costs associated with projected participation in 7
the three programs. 8
Q. Have you quantified the 2023 Base Level NPSE 9
amounts? 10
A. Yes. The 2023 Base Level NPSE amounts as 11
proposed by the Company for Commission-approval are as 12
follows: 13
Table 5 14
2023 Base Level NPSE 15
Table 5 2023 Base Level NPSE
95% Accounts (with 95% recovery in PCA)

100% Accounts (with 100% recovery in PCA)
16
Q. How do these 2023 Base Level NPSE amounts 17
compare with the 2013 Base Level NPSE amounts? 18
BRADY, DI 25
Idaho Power Company
A. The 2023 Base Level NPSE total is 1
$490,558,413, an increase of $184,873,544 from the 2013 2
Base Level NPSE of $305,684,869. 3
Q. Is Idaho Power proposing to update Schedule 4
55, Power Cost Adjustment, with this filing? 5
A. Yes. As discussed in Mr. Larkin’s testimony, 6
the update in base NPSE will result in a reduction in the 7
variance between base and forecast NPSE embedded in current 8
PCA rates. Therefore, Idaho Power has calculated an updated 9
PCA rate that incorporates the proposed 2023 Base Level 10
NPSE. If approved as filed, the Company’s 2023 Base Level 11
NPSE would result in a reduction in PCA revenue collection 12
of $171,516,689 using the June 2023 through May 2024 PCA 13
year. Applying this rate change to 2023 test year sales 14
results in the $170,912,271 detailed in Mr. Larkin’s 15
testimony – the only difference due to differing sales 16
between the June 2023 through May 2024 time period and the 17
January 2023 through December 2023 time period. This 18
comprises the majority of the PCA-related transfer 19
adjustment discussed in Mr. Larkin’s testimony. The 20
calculations made to determine the updated PCA forecast 21
rate, as well as the decrease in PCA revenue collection as 22
a result of the 2023 Base Level NPSE update are provided in 23
my workpapers. 24
BRADY, DI 26
Idaho Power Company
Q. Have you prepared a revised Schedule 55 that 1
includes the updated PCA rate? 2
A. Yes. Attachment 1 to Idaho Power’s 3
Application filed concurrently herewith is a revised 4
Schedule 55 and includes the proposed PCA rates in clean 5
and legislative formats. 6
Q. Does this conclude your direct testimony in 7
this case? 8
A. Yes, it does. 9
// 10
BRADY, DI 27
Idaho Power Company
DECLARATION OF JESSICA G. BRADY 1
I, Jessica G. Brady, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Jessica G. Brady. I am employed 4
by Idaho Power Company as a Regulatory Analyst in the 5
Regulatory Affairs Department. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony and Exhibit Nos. 27 through 30 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 JESSICA G. BRADY 19
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