20250401Direct Ellsworth.pdf

RECEIVED
April 1, 2025
IDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY' S APPLICATION FOR ITS ) CASE NO. IPC-E-25-15
FIRST ANNUAL UPDATE TO THE )
EXPORT CREDIT RATE FOR NON- )
LEGACY ON-SITE GENERATION )
CUSTOMERS FROM JUNE 1, 2025 )
THROUGH MAY 31, 2026, IN )
COMPLIANCE WITH ORDER NO. 36048 . )
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
JARED L. ELLSWORTH

1 Q. Please state your name and business address .
2 A. My name is Jared L. Ellsworth My business
3 address is 1221 West Idaho Street, Boise, Idaho 83702 .
4 Q. By whom are you employed and in what
5 capacity?
6 A. I am employed by Idaho Power Company ("Idaho
7 Power" or "Company") as the Transmission, Distribution and
8 Resource Planning Director for the Planning, Engineering
9 and Construction Department .
10 Q. Please describe your educational background.
11 A. I graduated in 2004 and 2010 from the
12 University of Idaho in Moscow, Idaho, receiving a Bachelor
13 of Science Degree and Master of Engineering Degree in
14 Electrical Engineering respectively. I am a licensed
15 professional engineer in the State of Idaho .
16 Q. Please describe your work experience with
17 Idaho Power.
18 A. In 2004, I was hired as a Distribution
19 Planning engineer in the Company' s Delivery Planning
20 department . In 2007, I moved into the System Planning
21 department, where my principal responsibilities included
22 planning for bulk high-voltage transmission and substation
23 projects, generation interconnection projects, and North
24 American Electric Reliability Corporation' s reliability
25 compliance standards . I transitioned into the Transmission
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Idaho Power Company

1 Policy and Development group with a similar role, and in
2 2013, I spent a year cross-training with the Company' s Load
3 Serving Operations group. In 2014, I was promoted to
4 Engineering Leader of the Transmission Policy and
5 Development department and assumed leadership of the System
6 Planning group in 2018 . In early 2020, I was promoted into
7 my current role as the Transmission, Distribution, and
8 Resource Planning Director. I am currently responsible for
9 the planning of the Company' s wires and resources to
10 continue to provide customers with cost-effective and
11 reliable electrical service .
12 Q. What is the purpose of your testimony?
13 A. The purpose of my testimony is to describe
14 the results of the Company' s annual update to its Export
15 Credit Rate (""ECR") per the Idaho Public Utilities
16 Commission ("Commission") Order No. 36048, issued in Case
17 No . IPC-E-23-14 . In that case, the Commission directed
18 Idaho Power to update all proposed components of the ECR
19 except the season and hours of highest risk in an annual
20 filing beginning April 1, 2025 . 1
21 Q. What is the Company requesting regarding the
22 ECR in this case?
23
1 Case No. IPC-E-23-14, Order No. 36048 at 7 (December 29, 2023) .
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Idaho Power Company

1 A. The Company is requesting the Commission
2 approve its proposed ECR which will apply on a per
3 kilowatt-hour ("kWh") of excess energy exported to Idaho
4 Power' s system by non-legacy customers with on-site
5 generation. Specifically, Idaho Power is requesting the
6 Commission approve the following rates to be effective
7 between June 1, 2025, and May 31, 2026 : 14 . 0598� for summer
8 on-peak, 1 . 7682G for summer-off peak, and 0 . 9540� for all
9 hours during the non-summer season.
10 Q. How is your testimony organized?
11 A. My testimony will first give an overview of
12 the components of the ECR, and the Commission approved
13 methodology in which they are updated. I will then discuss
14 the proposed ECR to be effective between June 1, 2025, and
15 May 31, 2026, and the main drivers behind the change in the
16 updated ECR.
17 Q. Have you prepared any exhibits?
18 A. Yes, my testimony includes the following
19 exhibits :
20 • Exhibit No . 1 provides a summary of the
21 proposed ECR to be effective between June 1,
22 2025, and May 31, 2026 .
23 • Exhibit No . 2 contains the Excel ECR workpaper
24 with summary schedules and supporting data
25 included.
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Idaho Power Company

1 • Exhibit No . 3 contains the 2023 line loss study
2 relied on for the ECR update.
3 • Exhibit No . 4 contains the most recently filed
4 Variable Energy Resource ("VER") Integration
5 study relied on for the ECR update.
6 • Exhibit No . 5 contains the transmission and
7 distribution ("T&D") deferral calculation.
8 I . ECR COMPONENTS
9 Q. What are the components of the ECR?
10 A. As approved by the Commission in Order No.
11 36048, the following are the components of the ECR:
12 • Avoided Energy Costs
13 • Avoided Line Losses
14 • Integration Costs
15 • Avoided Generation Capacity
16 • Avoided or Deferred T&D Capacity Costs
17 Q. Did the Commission approve a method for
18 calculating the ECR?
19 A. Yes . In Order No. 36048, the Commission
20 approved a seasonal and time-variant ECR with avoided cost-
21 based value considerations .2 The Commission further approved
22 the specific methods in which each component of the ECR is
23 to be calculated. In the following portion of my testimony,
2 Id. , at 6.
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1 I will describe the approved methods for each component of
2 the ECR.
3 Q. Are there any components of the ECR which
4 the Commission did not order to be updated annually?
5 A. Yes . In Order No. 36048, the Commission
6 found that the season and on- and off-peak hours shall only
7 be updated in a separate docket or in a General Rate Case
8 ("GRC") filing as appropriate.3 This was based on the
9 recommendation from Commission Staff that updates to the
10 summer season be part of future GRC filings and updates to
11 on-peak hours should be filed in a separate docket. 4
12 Q. Please describe the seasonal and time-based
13 structure of the ECR.
14 A. The Commission-approved summer season is
15 June 1 through September 30 . During the summer season, the
16 on-peak hours are 3 p.m. to 11 p.m. Monday through
17 Saturday, excluding holidays, and the off-peak hours during
18 the summer season are between 11 p.m. and 3 p.m. Monday
19 through Saturday, and all hours on Sundays and holidays .
20 The non-summer season is October 1 through May 31, and
21 during non-summer all hours are considered off-peak. 5
22
23
3 Id.
4 Id. , Staff Comments at 5 (October 12, 2023) .
5 Id. , Order No. 36048 at 6 (December 29, 2023) .
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Idaho Power Company

I Avoided Energy Costs
2 Q. Please explain the Commission-approved
3 methodology for valuing avoided energy.
4 A. The avoided energy costs are determined
5 using twelve months (January 1 through December 31) of
6 Energy Imbalance Market ("EIM") Load Aggregation Point
7 ("FLAP") market prices, weighted for historical customer-
8 generator exports ("ELAP Weighted Average") .
9 Q. Did the Commission instruct the Company to
10 distribute the avoided energy costs in alignment with the
11 summer and non-summer seasons?
12 A. Yes .
13 Avoided Line Losses
14 Q. Please explain the Commission-approved
15 methodology for valuing avoided line losses .
16 A. Avoided line losses are to be valued using
17 the most recently completed line loss study. The Commission
18 directed the Company to apply the annual energy line losses
19 to the avoided energy value . Further, the peak loss
20 coefficient is applied to the avoided capacity calculation.
21 Integration Costs
22 Q. What methodology did the Commission approve
23 to account for integration costs?
24 A. In Order No. 36048, the Commission approved
25 the use of the then most recently completed VER Study,
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Idaho Power Company

1 which was the 2020 VER Study. However, in the order, the
2 Commission also directed Idaho Power to complete an updated
3 integration study as soon as possible and to file for
4 Commission approval and inclusion for future ECR updates .
5 Integration costs are accounted for as an offset to the
6 avoided energy component .
7 Avoided Generation Capacity
8 Q. Please explain the Commission-approved
9 method for valuing avoided generation capacity.
10 A. Three primary inputs are used to determine
11 the avoided generation capacity value: (1) contribution to
12 capacity (adjusted by the on-peak line loss coefficient) ,
13 (2) the cost of an alternative resource, and (3) the energy
14 exported during the on-peak hours .
15 Q. Please explain the method for determining
16 the contribution to capacity.
17 A. The Commission approved the Effective Load
18 Carrying Capacity ("ELCC") method to calculate the capacity
19 contribution for all on-site customer generation exports
20 that occur over the course of a year. ELCC values are
21 individually calculated by year, and these results are
22 averaged to produce a five-year trailing average. The five-
23 year average ELCC is then multiplied by the maximum export
24 value from the most-recently available year' s data; the
25 resulting capacity contribution is then multiplied by the
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Idaho Power Company

1 on-peak line loss coefficient. This value represents the
2 total capacity contribution utilized in the calculation of
3 the avoided generation capacity value.
4 Q. What resource is used as the alternative
5 resource?
6 A. The Company was ordered to use the levelized
7 capacity cost for the least-cost dispatchable resource from
8 its most recently filed Integrated Resource Plan ("IRP") .
9 Q. What hours is the avoided generation
10 capacity value applied to?
11 A. The avoided generation capacity value is
12 applied to the on-peak hours of the summer season.
13 Q. Please summarize how the avoided generation
14 capacity component of the ECR is calculated.
15 A. The below equation shows how the avoided
16 generation capacity component of the ECR is calculated.
17 ECR of Avoided CapacityYear = ELCCAverage • Losses •Max OutputyeQr •Avoided CostIRP
Export Energy in All Risk Hoursy,ar
18 Avoided or Deferred T&D Capacity Costs
19 Q. Please explain the Commission-approved
20 methodology for valuing avoided or deferred T&D capacity.
21 A. The Commission approved a method where T&D
22 capacity is valued using a project-by-project deferral
23 analysis, assessing every T&D capacity project over a 20-
24 year time frame . To determine the 20-year time frame the
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Idaho Power Company

1 Company will reference the most recently filed IRP.
2 Q. What hours is the deferred T&D capacity
3 value applied to?
4 A. The T&D capacity value is applied to the on-
5 peak hours of the summer season.
6 II . PROPOSED ECR
7 Q. How frequently is the ECR to be updated?
8 A. Per Commission Order No. 36048, the Company
9 is to update the ECR annually beginning in 2025 . As I
10 previously outlined, the Company will review all value
11 components of the ECR annually.
12 Q. What are the ECR values the Company proposes
13 to implement for June 1, 2025, through May 31, 2026, and
14 how do those compare to the existing ECR values?
15 A. Figure 1 displays a summary of the proposed
16 ECR values in the "Proposed" column and the currently in-
17 effect ECR values in the "Current" column. The proposed ECR
18 per kWh of exported energy is 14 . 0598� for summer on-peak,
19 1 . 7682G for summer off-peak, and 0 . 9540G for all hours
20 during the non-summer season. Exhibit No. 1 contains a
21 summary of the proposed ECR values, and Exhibit No . 2
22 contains all inputs and calculations for the proposed ECR.
23
24
25
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Idaho Power Company

I Figure 1 : Current and Proposed ECR values
Season Current Proposed
Export Profile
Volume(kWh per kW) Annual 1,465 1,362
Capacity Contribution(%) Annual 10.12% 10.07%
Export Credit Rate by Component(cents/kWh)
Energy Summer 5.6533¢ 1.76820
Including integration and losses Non-Summer 4.83650 0.95400
Annual* 5.15660 1.28520
Generation Capacity On-Peak 11.16790 11.90170
Off-Peak 0.00000 0.00000
Annual* 1.06160 1.13600
Transmission&Distribution Capacity On-Peak 0.17550 0.38990
Off-Peak 0.00000 0.00000
Annual* 0.01670 0.03720
Total Summer On-Peak 16.99660 14.05980
Summer Off=Peak 5.6533 ¢ 1.7682 ¢
Non-Summer 4.83650 0.95400
Annual* 6.23480 2.45850
*Annual values provided for informational purposes only and reflect seasonal weighting
for 12 months ending December 31.
Note:Summer season is defined as June I-September 30. On-Peak hours is defined as
3pm-IIpm,Monday-Saturday, excluding holidays.All other Summer hours defined as
Off-Peak.Non-Summer season defined as October I-May 31.
2 Energy
3 Q. Please describe how the Company quantified
4 the proposed energy component of the proposed ECR values .
5 A. The Company first used the 2024 hourly ELAP
6 market prices, weighted for historical customer-generator
7 exports to determine the avoided energy component, and then
8 included adjustments for avoided line losses and
9 integration costs . The Company distributed the values in
10 alignment with the summer and non-summer season, as more
11 fully described above .
12
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Idaho Power Company

1 Q. What are the resulting updated energy
2 components?
3 A. The energy-related component (which includes
4 avoided energy valued at the weighted average ELAP prices,
5 line losses, and integration) , per kWh of exported energy,
6 are 1 . 7682G for the summer season and 0 . 9540G for the non-
7 summer season. Figure 2 below summarizes the proposed
8 energy component of the ECR.
9 Figure 2 : Proposed ECR Energy Component
Energy Component Summer Non-Summer Units
ELAP -Weighted Average $23.61 $15.81 $/MWh
Plus: Line Loss Gross-up $1.04 $0.70 $
Less: Integration Costs k6.97 $ 6.97 $/MWh
Energy Value $17.68 $9.54 $/MWh
10 Q. How did updating the ECR with the 2024 ELAP
11 prices impact the energy component of the ECR?
12 A. The updated energy component decreased
13 primarily due to lower 2024 ELAP prices during export hours
14 as compared to 2022 ELAP prices (those relied upon for the
15 ECR rates currently in effect) . Figure 3 below displays
16 average monthly ELAP prices from 2021 through 2024 .
17
18
19
20
21
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1 Figure 3 : 2021-2024 ELAP Prices
A�erzge of Price
S2Su c
$200.00
$150.00
Years(Flow Date)
-2021
-2022
$100.00
-2023
-2024
$50.00 - -
lan Feb Mar Apr May Oct Nov Dec Jun Jul Aug Sep
Non-Summer Summer
Season - Months(Flow Date) - Flow Date + -
2 As can be seen in Figure 3, 2022 ELAP prices
3 experienced a higher degree of volatility during 2022 that
4 persisted through the first few months of 2023 .
5 Figure 4 shows the monthly ELAP Weighted Average for
6 the current ECR (which relies on 2022 EIM prices) and the
7 proposed ECR (which relies on 2024 EIM prices) .
8 Figure 4 : Monthly ELAP Weighted Average Prices .
Current ECR ECR Update
Season Month Value Energy $/MWh Value Energy $/MWh
NS 1 $ 102,879 3,144 $ 32.72 $ 245,051 3,913 $ 62.63
NS 2 $ 167,545 6,362 $ 26.33 $ 136,706 7,016 $ 19.49
NS 3 $ 233,461 8,973 $ 26.02 $ 141,922 12,802 $ 11.09
NS 4 $ 436,204 9,977 $ 43.72 $ 31,692 18,703 $ 1.69
NS 5 $ 445,602 11,077 $ 40.23 $ (12,752) 20,240 $ (0.63)
S 6 $ 320,466 10,728 $ 29.87 $ 270,382 17,346 $ 15.59
S 7 $ 574,323 8,850 $ 64.90 $ 416,881 13,686 $ 30.46
S 8 $ 567,746 7,962 $ 71.30 $ 361,978 14,319 $ 25.28
S 9 $ 592,657 8,543 $ 69.37 $ 351,963 13,988 $ 25.16
NS 10 $ 516,061 9,157 $ 56.36 $ 434,150 12,701 $ 34.18
NS 11 $ 332,075 4,809 $ 69.06 $ 241,687 6,853 $ 35.27
NS 12 $ 517,249 2,494 $207.40 $ 150,126 4,311 $ 34.82
Annual $4,806,268 92,076 $ 52.20 $2,769,787 145,879 $ 18.99
S $2,055,192 36,084 $ 56.96 $1,401,205 59,339 $ 23.61
9 NS $2,751,076 55,993 $ 49.13 $1,368,582 86,539 $ 15.81
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Idaho Power Company

1 Q. Generally, what causes year-over-year
2 fluctuations in the ELAP prices?
3 A. There are many factors that can lead to
4 fluctuations in ELAP prices . Overall, the ELAP prices are a
5 function of supply and demand and lower ELAP prices mean
6 there was either high energy supply, or low demand, or
7 both. Notably, in the spring months there are more negative
8 prices due to more hydropower output during spring run-off
9 conditions, and more solar on the market combined with a
10 lower demand for electricity. This creates oversupply
11 conditions, which can lead to negative prices . Additional
12 factors that affect prices include the cost of coal and gas
13 and extreme weather events .
14 Q. Are the 2024 ELAP prices relied upon for the
15 Company' s proposal final?
16 A. The January 2024 through November 2024 ELAP
17 prices are final . While unlikely to occur, the December
18 2024 ELAP prices remain subject to change, based on the
19 outcome of the California Independent System Operator' s
20 ("CAISO") dispute resolution process .
21 Q. When will the December 2024 ELAP prices be
22 considered final?
23 A. The primary factor driving the completeness
24 of the ELAP prices is the dispute resolution process for
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Idaho Power Company

1 the EIM, which is defined by CAISO. The Initial Statement
2 T+9B is received nine business days after the relevant
3 trading day and has a dispute deadline of 31 business days
4 from the relevant trading day (in this case, December 31,
5 2024) . Note, the data submitted with this filing has
6 already passed that initial dispute deadline.
7 However, to ensure completeness, the Company relies
8 on the Recalculation Statement T+70B, which is not fully
9 reconciled and received until 70 business days after the
10 relevant trading day. As such, the Company has submitted
11 ELAP prices through November 2024 based on the
12 Recalculation Statement T+70B, and while it is unlikely
13 December values will change when the December Recalculation
14 Statement T+70B is received, should the December values
15 change, Idaho Power will immediately notify Staff and will
16 submit a supplemental filing with the updated values . Given
17 the infrequency of these occurrences, it is expected there
18 would either be no impact to the ECR or a very slight
19 change .
20 Q. What study did the Company rely on to
21 quantify the avoided line losses?
22 A. The Company relied on its most recent line
23 loss study, which remains the 2023 line loss study (this
24 study was also relied on to determine the current ECR
25 values) . Specifically, in determining the proposed line
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1 loss values applied to the energy component, the Company
2 applied a loss coefficient of 1 . 044 . Exhibit No. 3 contains
3 the 2023 line loss study.
4 Q. What were the resulting values?
5 A. The proposed avoided per kWh line losses are
6 0 . 104G and 0 . 070G in the summer and non-summer seasons,
7 respectively, which compares to 0 . 251� and 0 . 216� for the
8 same period in the current ECR.
9 Q. What drove the decrease in the line loss
10 values?
11 A. Because the specific line loss coefficients
12 have not changed - and the avoided line-losses are simply a
13 function of the ELAP Weighted Average and the coefficients
14 - the driver of the decrease in the line losses was the
15 result of a lower ELAP Weighted Average in 2024 .
16 Q. What study did the Company rely on as a
17 basis for its proposed integration costs?
18 A. The Company relied on its 2024 VER Study,
19 which was completed in December 2024 and is attached as
20 Exhibit No . 4 to my testimony.
21 Q. Which value from the 2024 VER Study is the
22 Company proposing be used in its ECR update?
23 A. The integration cost most appropriate to use
24 in the ECR update is from the 0-100 megawatt solar
25 portfolio, which translates to a reduction in the energy
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1 component of 0 . 697� per kWh. This compares to integration
2 costs of 0 .293G per kWh that are included in the current
3 ECR.
4 Q. Please describe the drivers of the change in
5 the integration costs .
6 A. Between the 2020 VER Study and the 2024 VER
7 Study, the cost to integrate solar resources with Idaho
8 Power' s system has increased, primarily attributed to an
9 increase in solar on Idaho Power' s system. As the amount of
10 solar on the system increases, the need and use of
11 integrating resources increases proportionally. It is the
12 increased need to provide more integration capability with
13 the increased solar resources that has increased the cost
14 of integration.
15 Avoided Generation Capacity
16 Q. Please describe how the Company quantified
17 the generation capacity component of the proposed ECR.
18 A. The Company first updated its five-year
19 trailing average ELCC to include 2023 and 2024 . The ELCC
20 values for years 2020 through 2024 were then averaged to
21 produce an ELCC of 10 . 07 percent. To calculate the capacity
22 contribution the Company multiplied the updated average
23 ELCC by the maximum export value from 2024 (the latest year
24 of available data) and the on-peak line loss coefficient .
25 As stated in the avoided line loss section above, the line
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1 losses have not been updated since the current ECR was
2 filed, therefore the Company is using the same on-peak line
3 loss coefficient of 1 . 053 .
4 The cost of an alternate resource was also not
5 updated as the Company has not filed a new IRP since it
6 filed its current ECR values . The most recently filed IRP
7 is the 2023 IRP and the least cost dispatchable resource is
8 a simple cycle combustion turbine at a cost of $145 . 94/kW-
9 year. The energy generated during on-peak hours was updated
10 using 2024 customer exports .
11 The equation below shows how these components are
12 utilized to calculate the ECR of avoided generation
13 capacity.
(10.07%) • (1.053) • (107,127 kW) • ( $145.94 )
11.90
(
14 ECR of Avoided Capacity2024 = kW year _ kWh
year13,924,296 kWh l — \ kWh 1
year J
15 Q. How is the result accounted for in the ECR
16 values?
17 A. The generation capacity value of 11 . 9017�
18 per kWh is only applied to the summer on-peak hours .
19 Q. Please describe the drivers of the change in
20 the generation capacity value.
21 A. As noted above, only the ELCC, the maximum
22 export value, and the energy generated during on-peak hours
23 changed. The maximum export value and the energy generated
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1 during on-peak hours both increased because of more
2 customer generators on the Company' s system in 2024 versus
3 2022, the year used in the current ECR. The updated average
4 ELCC value is 10 . 07 percent as compared to 10 . 12 percent
5 from the current ECR.
6 Q. Is the Company proposing any changes to the
7 ELCC values for 2020, 2021, or 2022 as part of this year' s
8 filing?
9 A. Yes . In preparation of this year' s filing,
10 the Company identified it had inadvertently double counted
11 customer generator exports in the system load calculation
12 when it previously determined the adjustment to recalculate
13 2020, 2021, and 2022 ELCC values . If the prior year ELCC
14 values are not adjusted, there will be discrepancy between
15 how 2023 and 2024 ELCC values were developed as related to
16 those prior years .
17 Q. Please explain the significance of the
18 needed ELCC modification you identified.
19 A. When presenting ELCCs for 2020, 2021, and
20 2022 in Case No. IPC-E-23-14, the Company calculated the
21 ELCC of customer generator exports the same way it
22 calculates the ELCC of all other resource types . That is, a
23 base run was calculated that excluded the specified
24 resource and a second run where the specified resource was
25 added to the system. The addition of the specified resource
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1 lowers the net load. Of note, the Company' s system load is
2 derived by considering all the generation in-front-of-the-
3 meter and the interchange flows .
4 Because customer generator exports originate from
5 behind-the-meter, the reported system load already accounts
6 for the impact of customer generator exports . The Company
7 identified that a more appropriate way to calculate the ECR
8 ELCC is to add the exports to the system load. This changes
9 the base run to include the impact of the customer
10 generator exports through the system load, meaning the
11 second run should now add the customer generator exports
12 back to the net load. This change is necessary to ensure
13 that the impact of customer generator exports to the
14 Company' s system load are not double counted.
15 Q. Please summarize the Company' s proposed 5-
16 year average ELCC?
17 A. Table 1 below shows the ELCC values
18 previously relied upon when the current ECR was approved in
19 Case No . IPC-E-23-14 (column "IPC-E-23-14") . The Company is
20 proposing to use an average ELCC of 10 . 07 percent, which
21 updates the 2020 through 2022 ELCC values consistent with
22 what I explained above and averages those with the ELCC
23 values for 2023 and 2024; these values averaged together
24 results in the proposed 5-year average ELCC relied upon in
25 this year' s annual update.
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I Table 1 : ELCC Values
Year IPC-E-23-14 Proposed Updated
2020 7.50% 7.50%
2021 14.90% 17.39%
2022 7.95% 9.55%
2023 - 12.17%
2024 - 3.73%
Average 10.12% 10.07%
2 Note, correcting for the subtraction of exports did
3 not impact the 2020 ELCC, likely due to the relatively low
4 penetration of on-site generation. However, both 2021 and
5 2022 values are impacted and accordingly, the Company
6 believes it is appropriate to update those values for
7 inclusion in this year' s update.
8 Avoided or Deferred T&D Capacity Costs
9 Q. Please describe how the Company quantified
10 the T&D capacity component of the proposed ECR.
11 A. Using the Commission-approved methodology to
12 determine the value of on-site generation in deferring the
13 need for the Company to build additional T&D resources, the
14 Company identified local peak hours for each T&D resource.
15 Local peak hours are specific to the amount of types of
16 loads connected to individual resources . The analysis
17 incorporated the 20 years of project data from the 2023
18 IRP, 2007 to 2026, to identify the historical trends and
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1 projected T&D projects and the capacity need for each
2 project .
3 Q. What are the updated avoided or deferred T&D
4 capacity costs?
5 A. The updated avoided or deferred T&D capacity
6 costs, per kWh of exported energy for summer on-peak is
7 0 . 3899G .
8 Q. Please describe the drivers of the change in
9 the avoided or deferred T&D capacity costs .
10 A. The primary driver of the increase in the
11 avoided or deferred T&D capacity costs was related to an
12 increase in solar penetration from 0 . 61 percent to 2 . 12
13 percent and an increase in customer generator exports .
14 Using 20 years of project data from the 2023 IRP, the
15 number of deferrable T&D projects increased from nine to
16 42, which increased the dollar value of deferral savings .
17 The updated T&D deferral value calculations can be found in
18 Exhibit No . 5 and the updated T&D capacity costs
19 calculations can be found in Exhibit Nos . 1, 2, and 5 .
20 III . CONCLUSION
21 Q. Please summarize the Company' s request in
22 this filing.
23 A. Idaho Power requests the Commission approve
24 its annual ECR update to be effective June 1, 2025, through
25 May 31, 2026 . The ECR update follows the methodology
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Idaho Power Company

1 approved by the Commission in Order No. 36048 . The updated
2 ECR per kWh exported is 14 . 0598� for summer on-peak,
3 1 . 7682� for summer off-peak, and 0 . 9540� for non-summer.
4 Q. Does this conclude your testimony?
5 A. Yes, it does .
6
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Idaho Power Company

1 DECLARATION OF JARED L. ELLSWORTH
2 I, Jared L. Ellsworth, declare under penalty of
3 perjury under the laws of the state of Idaho:
4 1 . My name is Jared L. Ellsworth. I am employed
5 by Idaho Power Company as the Transmission, Distribution &
6 Resource Planning Director for the Planning, Engineering &
7 Construction Department.
8 2 . On behalf of Idaho Power, I present this
9 pre-filed direct testimony and Exhibits 1-5 in this matter.
10 3 . To the best of my knowledge, my pre-filed
11 direct testimony is true and accurate.
12 1 hereby declare that the above statement is true to
13 the best of my knowledge and belief, and that I understand
14 it is made for use as evidence before the Idaho Public
15 Utilities Commission and is subject to penalty for perjury.
16 SIGNED this 1st day of April 2025, at Boise, Idaho.
17 - z I
18 Signed: (;
19 Jared L. Ellsworth
20
Ellsworth, DI 24
Idaho Power Company

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-15
IDAHO POWER COMPANY
ELLSWORTH , DI
TESTIMONY
EXHIBIT NO. 1

ECR SUMMARY ECR Annual Update
Season ECR
Export Profile
Volume(kWh per kW) Annual 1,362
Capacity Contribution(%) Annual 10.07%
Export Credit Rate by Component(cents/kWh)
Energy Summer 1.76820
Including integration and losses Non-Summer 0.95400
Annual* 1.28520
Generation Capacity On-Peak 11.90170
Off-Peak 0.00000
Annual* 1.13600
Transmission&Distribution Capacity On-Peak 0.38990
Off-Peak 0.00000
Annual* 0.03720
Total Summer On-Peak 14.05980
Summer Off-Peak 1.76820
Non-Summer 0.95400
Annual* 2.45850
*Annual values provided for informational purposes only and reflect seasonal weighting for 12
months ending December 2024.
Note:Summer season is defined as June I-September 30. On-Peak hours is defined as 3pm-Ilpm,
Monday-Saturday, excluding holidays.All other Summer hours defined as Off-Peak.Non-Summer
season defined as October 1-May 31.
Exhibit No. 1
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 1 of 4

Avoided Annual Update
Summer Non-Summer
Avoided Energy Calculation Update Update Units Description
ELAP-Weighted Average $ 23.61 $ 15.81 $/MWh
Plus:Line Loss Gross-up $ 1.04 $ 0.70 $ Exhibit No.3-Analysis of System Losses(March 2023)
Less:Integration Costs $ (6.97) $ (6.97) $/MWh Exhibit No.4-Idaho Power 2024 VER Integration Study
.............................................................................................................................................................................................................................................................................................................................................................................................................
.....AvoidedEnergy...Value.............................................................................$............17.68 $ 9.54 $/MWh
.............................................................................................................................................................................................................................................
Annual Energy Value $ 12.8E $ 12.8E
Monthly Seasonal Energy Calculation
Season Month Value Energy $IMWh
NS 1 $ 245,051 3,913 $ 62.63
NS 2 $ 136,706 7,016 $ 19.49
NS 3 $ 141,922 12,802 $ 11.09
NS 4 $ 31,692 18,703 $ 1.69
NS 5 $ (12,752) 20,240 $ (0.63)
S 6 $ 270,382 17,346 $ 15.59
S 7 $ 416,881 13,686 $ 30.46
S 8 $ 361,978 14,319 $ 25.28
S 9 $ 351,963 13,988 $ 25.16
NS 10 $ 434,150 12,701 $ 34.18
NS 11 $ 241,687 6,853 $ 35.27
NS 12 $ 150,126 4,311 $ 34.82
Annual $ 2,769,787 145,879 $ 18.99
S $ 1,401,205 59,339 $ 23.61
NS $ 1,368,582 86,539 $ 15.81
Exhibit No. 1
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 2 of 4

Avoided 1Capacity ' Update
Avoided Generation Capacity Calculation Update Units Description
Effective Load Carrying Capability 10.07% % 5-year rolling average ELCC(CY2020-2024)
(x)Nameplate Capacity 107.13 MW
Total Capacity Contribution 10.78 MW
(x)Levelized Fixed Cost of Avoided Resource $ 145.94 $/kW-year 2023 Integrated Resource Plan-Appendix C,page 18
(x)kW to MW conversion 1,000 kW
(/)On-Peak Exports 13,924 MWh CY2024 real-time customer generation exports
On-Peak Avoided Generation Value $ 113.03
(x)Capacity Peak Loss Coefficient 1.053
..........................................................................................................................................................................................................................................................................................................................................................................................
€....On-Peak Avoided Generation Capacity Value...................�........119.02..........$/MWb...............................................................................................................................................................................................€
Annual Generation Capacity Value $ 11.36 $/MWh
Customeri iirts-ELCC&Maximum Output I Current Reliabilityp, ii i Data)
Year-2020
ELCC(MW) 2
Maximum Output(MW) 26.67
..........................................................................................................................................................................................................................................................................................................................................................................................
7.50%
..........................................................................................................................................................................................................................................................................................................................................................:
Year-2021
ELCC(MW) 7
Maximum Output(MW) 40.26
..........................................................................................................................................................................................................................................................................................................................................................................................
ELCC(%) 17.39%
. ...........................................................................................................................................................................................................................................................................................................................................................:
Year-2022
ELCC(MW) 6
Maximum Output(MW) 62.86
...........................................................................................................................................................................................................................................................................................................................................................................................
ELCC(%) 9.55%
. ...........................................................................................................................................................................................................................................................................................................................................................:
Year-2023
ELCC(MW) 11
Maximum Output(MW) 90.40
..........................................................................................................................................................................................................................................................................................................................................................................................
12
................................................................................................................12.17%
......................................................................................................................................................................................................................................:
Year-2024
ELCC(MW) 4
Maximum Output(MW) 107.13
...........................................................................................................................................................................................................................................................................................................................................................................................
>....ELCC(%).................................................................................................................. .........73% €
..........................................................................................................................................................................................................................:
....................................5-Year Average...................................................................................................10.07%......................................................................Year rolling average ELCC(CY2020.2024)....................................................
Exhibit No. 1
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 3 of 4

1 1 1� 1 ♦ Distribution Capacity ECR Annual Update
Avoided T&D Capacity Calculation Update Units Description
Distribution Capacity Savings $ 1,085,776 $ Exhibit No. 5-Transmission and Distribution Avoided Capacity
Plus:Transmission Capacity Savings - $ Exhibit No. 5-Transmission and Distribution Avoided Capacity
Total T&D Capacity Savings $ 1,085,776 $
(/)Project Years 20 years Exhibit No. 5-Transmission and Distribution Avoided Capacity
Annual T&D Capacity Savings $ 54,289 $/year
(/)On-Peak Exports 13,924 CY2024 real-time customer generation exports
...............................................................................................................................................................................................................................................................................................................................................................................................................
.....On-Peak T&D Capacity Value.........................................................$..................3.90 $/MWh €
............. .......................................................................................................................................................................................................................................
Annual Generation Capacity Value $ 0.37 $1MWh
Exhibit No. 1
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 4 of 4

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-15
IDAHO POWER COMPANY
ELLSWORTH , DI
TESTIMONY
EXHIBIT NO. 2

SEE ATTACHED SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-15
IDAHO POWER COMPANY
ELLSWORTH , DI
TESTIMONY
EXHIBIT NO. 3

Analysis of System Losses Idaho Power Company
ANALYSIS OF SYSTEM LOSSES
In
Idaho Power Company
Prepared by:
Jackson Daly
Andres Valdepena Delgado
System Planning Department
March 2023
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 1 of 17

Analysis of System Losses Idaho Power Company
Contents
ExecutiveSummary.......................................................................................................................................3
Introduction..................................................................................................................................................4
SystemLevel Description..............................................................................................................................4
TransmissionSystem.................................................................................................................................4
DistributionSystem...................................................................................................................................4
StationsLevel............................................................................................................................................5
PrimaryLevel.............................................................................................................................................5
SecondaryLevel ........................................................................................................................................5
Energy Loss Coefficient Calculations.............................................................................................................6
Transmission Level Energy Losses.............................................................................................................6
Distribution Substation Level Energy Losses ............................................................................................7
Distribution Level Energy Losses...............................................................................................................8
Distribution Line Transformer Losses.......................................................................................................8
Primary-Secondary Distribution Losses Split............................................................................................8
Losses Comparison with FERC Form 1 ......................................................................................................9
PeakLoss Coefficients.............................................................................................................................11
Avoidable Losses by On-Site Customer Generation ...................................................................................12
Appendix A: 2012 Energy Losses Data Sources................................................................................14
Appendix B: 2012 Peak Losses Data Sources....................................................................................16
Appendix D: Reconciliation with FERC Form 1 ................................................................................17
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 2 of 17

Analysis of System Losses Idaho Power Company
Executive Summary
This study presents the peak and energy loss coefficients for the Idaho Power delivery system.The
analysis was conducted using 2022 data.The delivery system was broken down into four different
system levels, including:
• Transmission: Includes voltage levels between 46 kV and 500 kV
• Distribution Stations: Includes distribution station transformers
• Distribution Primary: Includes distribution lines and facilities between 12.47 kV and 34.5 kV
• Distribution Secondary: Includes distribution service lines and distribution line transformers
The losses documented in this study represent the physical losses that occurred on the Idaho Power
delivery system facilities.Application of the calculated loss coefficients is limited to loads served from
Idaho Power Company facilities. The peak loss coefficients were calculated based on data from the
system peak hour in 2022,which occurred on July 141h, 2022, at 7:00 PM.
The study incorporated various methods to calculate the losses at different voltage levels. For the 161
kV and above transmission system, current readings and resistance from the lines were used to
determine the losses. For the 138 kV transmission system, the losses were determined by calculating the
total inputs into the 138 kV system and subtracting the outputs, leaving the difference as the losses in
the 138 kV system. For the sub-transmission system, electric current or power and resistance readings
were used to determine losses. The total transformer losses were determined by adding the winding
and core losses.The distribution system losses were determined as the difference between the input to
the distribution system and the output, where the output of the distribution system is the end-use
customer usage obtained from the Advance Metering Infrastructure ("AMI") and the industrial and
commercial usage, MV90 database.
The individual system loss coefficients are determined as the system level inputs, divided by the system
level outputs.The loss coefficients used at each delivery point in the system are calculated as the
product of the individual level loss coefficients.The resulting coefficients for the 2022 study are
summarized in Table 1.
• 1.029 1.037
1.036 1.042
1.051 1.056
• . 1.076 1.076
Table 1: Delivery Point Loss Coefficients
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 3 of 17

Analysis of System Losses Idaho Power Company
Introduction
Loss coefficients are the ratio of the system input required to provide a given output at a particular
system level. Individual loss coefficient for each system level relates the input and the output by(1):
Level Input Level Losses
Loss Coefficient = Level Output 1 + Level Output
The system loss coefficient is obtained by multiplying all the upstream system level coefficients
together.
System Level Description
The Idaho Power delivery system was split into four categories:transmission, distribution stations,
distribution primary, and distribution secondary.The system inputs and outputs for each level are
described below.
Transmission System
The transmission level includes losses for all facilities and lines from 46 kV up through 500 kV. Losses
from the Generation Step-Up ("GSU")transformers and transmission tie-bank transformers are included
in the transmission level. Customer owned facilities at the transmission level are not included.
Transmission level inputs consist of the following:
+ Idaho Power Generation
+ Power Purchases/Exchanges
+ Customer Owned Generation Connecting to Transmission Lines
+ Wheeling Transactions
Transmission level outputs consist of the following:
- High Voltage Sales
- Power Exchanges*
- Wheeling Transactions
- Output to Distribution Stations
The exchanges outputs are adjusted to remove the scheduled losses for the Idaho Power share of losses
in the jointly owned Bridger-Idaho and Valmy-Midpoint transmission systems. FERC From 1 includes the
Bridger and Valmy scheduled losses as exchanged out. The calculated losses in this study include the
Idaho Power share of losses on the Bridger and Valmy systems as transmission level losses.
Distribution System
The distribution system consists of all equipment operating at 35 kV and below.This accounts for all
substation transformers, distribution lines, and distribution transformers.The distribution system can be
split into 3 different levels: stations, primary and secondary.These different levels are chosen to account
for the losses most accurately at the different points of delivery.
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 4 of 17

Analysis of System Losses Idaho Power Company
Stations Level
Stations level consists only of the substations servicing the distribution system (transformers with a low
voltage side of 7—35 W).
Station level inputs consist of the following:
+ Transmission System Outputs
Station level outputs consist of the following:
- Direct Sales
- Wheeling Transactions
Although this level has no additional inputs, it is chosen as there are several customers who are served
directly from the substation.
Primary Level
The primary level consists of all the primary distribution power lines. Primary lines being lines operated
between 7-35 W.
Primary level inputs consist of the following:
+ Distribution Stations Outputs
+ PURPA/Customer Generation
Primary level outputs consist of the following:
- Customer Sales
- Wheeling Transactions
The primary distribution level contains a large amount of generation under the Public Utility Regulatory
Policies Act ("PURPA") and customers with on-site generation and customers who connect directly to
the distribution primary level.
Secondary Level
The secondary level consists of all equipment operating at a service voltage.This includes distribution
transformers and distribution lines operating at a service voltage.
Secondary level inputs consist of the following:
+ Primary Level Outputs
+ Net Metering/Customer Generation
Secondary level outputs consist of the following:
- Customer Sales
- Idaho Power Internal use
- Street Lighting/Unbilled
- Wheeling Transactions
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 5 of 17

Analysis of System Losses Idaho Power Company
Customer with on-site generation are inputs to the secondary level and come from both rooftop solar
and small hydro generation.
Energy Loss Coefficient Calculations
Table 8 shows the total system flow diagram for the 2022 energy losses.The table outlines each system
level's input and output as well as the total energy losses (MWh) and loss coefficient.The transmission
level output(MWh)to the distribution station level is calculated by subtracting the remaining output
and calculated losses from the transmission level inputs
Transmission Level Energy Losses
For the 500—161 kV, 69 kV, and 46 kV voltage levels,the transmission losses were calculated using
Ohm's Law where current readings were available (2).
PLoss = 1Z ' R
Where 1 is the current flowing in a particular transmission line in Amperes and R is the resistance of the
transmission line in Ohms.
For the lines where current readings were unavailable,the apparent power(S) in MVA and voltage (V)
readings were used to calculate the current using the equation below(3).
V
1 = —
S
Due to the complexity of the 138-kV system,the losses were calculated by obtaining all the energy into
the 138-kV system and subtracting all the energy leaving the 138-kV system.
The summary of losses for the different voltage levels in the transmission system are shown in Table 2:
23,400 214,741 224,711 3,210 128,558 - 48,061 23,037
WW
7,148 9,909 39,915 990 9,088 36,450 9,210 5,827
6,005 3,504 18,393 6,222 4,931 35,175 7,065 3,961
Total Losses 1 36,553 228,154 283,019 42 5 71,625 64,336 32,825
Table 2:Type of Losses(MWh) by Voltage Level
The losses in the transmission transformers,generator step-up transformers and tie-banks,were
calculated by adding the two components of the losses in a transformer, the winding losses, and the
core losses.
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 6 of 17

Analysis of System Losses Idaho Power Company
The winding losses, also called copper losses, were calculated using (4):
N
Losses (MWh) _ (Hourly Usage)2 . R u 100
n=1
Where Rpu is the total per-unit resistance on a 100 MVA base and Hourly Usage is the average hourly
usage on the transformer in MWh.
The core losses were obtained using records from the Idaho Power Apparatus department "no-load
losses" records. It was assumed that the transformers were energized the entire year.The total core
losses for each transformer were calculated using (5):
8760
Core Losses (MWh) = NLL - 1000
Where NLL are the no-load losses in kWh for each transformer, and 8760 is the hours in the year 2022.
The total losses for the transmission level were found by adding the losses for the transmission lines and
the losses for the transmission transformers.The total losses for the transmission system are shown
below, broken down by voltage level and component type Table 3.
Transmission Losses Transmission Losses
By Voltage By Component
500kV 36,553 Lines 665,718
345kV 228,154 Core 67,050
230kV 283,019 Winding 39,055
161kV 10,422 Total 771,823
138kV 142,577
69kV 48,061
46kV 23,037
Total 771,823
Table 3:Transmission Losses (MWh) Breakdown
Distribution Substation Level Energy Losses
The distribution station losses were found by calculating the losses in the substation distribution
transformers for the calendar year 2022. Distribution transformers are classified, in this study, as any
transformer with a secondary voltage of 35-kV, 25-kV, or 12.5kV.The losses in other station apparatus
equipment and bus are assumed to be negligible.
The losses in the station transformer were calculated using the same method used to calculate the
losses in the transmission transformers using(3) and (4). For the few transformers that had no metering
data available in Idaho Power's PI data custodian,the MV90 data was used.The total losses in the
distribution stations are broken down by both voltage level and component type are shown in Table 4.
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 7 of 17

Analysis of System Losses Idaho Power Company
Stations Losses Stations Losses
By Voltage By Component
500kV - Lines -
345kV - Core 51,487
230kV - Winding 46,201
161kV - Total 97,688
138kV 71,625
69kV 16,275
46kV 9,788
97,688
Table 4: Station Losses(MWh) Breakdown
Distribution Level Energy Losses
The losses in the distribution level were determined by comparing the input to the system (feeder meter
data)to the output(customer billing data). Losses were inputs (feeder meter data) minus outputs
(customer billing data).
Distribution Line Transformer Losses
The distribution system losses can be separated into primary distribution and secondary distribution
losses.The distribution losses can be split between line and transformer losses.The split was done by
taking the average losses of the 138-k, 69-kV, and 46-kV systems as a proxy and determining what
proportion of those losses were line losses and which were transformer losses.These proportions were
then applied to the adjusted distribution losses to determine the distribution line losses and distribution
transformer losses. The results of this calculation can be seen in Table 5 below.
Line vs Transformer losses 2022 System Losses
Line Losses 316,822 Avg Line Loss 64%
Transformer losses 178,213 Avg Transformer Loss 36%
Total Distribution Losses 495,035
Table 5: Line vs Transformer Losses (MWh)
Primary-Secondary Distribution Losses Split
The split between the distribution primary and secondary lines losses was determined using the wire
milage for the distribution primary and secondary systems.The line mileage was obtained from the form
TAX650; the total distribution wire milage was found by adding up the total wire milage for the 12.5-kV,
25-kV, and 34.5-kV systems. From the TAX671 form,the primary line milage can be found broken down
by number of phases; the mile milage was converted to wire mileage by multiplying it by the number of
phases.The result is the total primary wire mileage which we can subtract from the total distribution
wire mileage to find the secondary wire mileage.
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 8 of 17

Analysis of System Losses Idaho Power Company
Using the final wire mileage, it was determined that the primary lines make up 68%of the total wire
mileage and the secondary lines make up the other 32%. These percentages can then be applied to the
total distribution line losses to determine the primary and secondary specific line losses. These
calculations can be seen in Table 6 below.
Primary vs Secondary
Primary Line Losses 215,080 12.5kV 50,974.12
Secondary Line Losses 101,743 25kV 1,377.87
Total Line Losses 316,822 34.5kV 16,797.35
Primary Losses 2151080 Total Line Mileage MM 69,149.34
Secondary Losses 279,955 IL lill
Total Distribution Losses 495,035 1—Phase 13,250.97
2—Phase 928.81
3—Phase 10,611.49
Primary Wire Mileage 46,943.06
Secondary Wire Mileage 22,206.28
Total Wire Mileage 69,149.34
Table 6: Distribution Losses (MWh) Breakdown
The primary distribution losses consist only of the primary line losses,the total losses for the primary
level is 214,985 MWh.The secondary distribution losses can be found by adding the distribution
transformer losses from Table 5 and the secondary line losses calculated above in Table 6, resulting in
279,955 MWh of losses for the secondary distribution level.
Losses Comparison with FERC Form 1
The losses obtained in the distribution system were added to the losses calculated from the levels above
and compared to the FERC Forum 1 losses. Idaho Power collects hourly data via SCADA for all generation
above 3 MW,for generation under the 3 MW limit there is no SCADA data being collected creating a
mismatch on the total losses calculated via FERC Form 1 and the losses calculated in this study.To adjust
for the generation without SCADA,the losses were adjusted in the distribution system to match the
total losses reported in FERC Form 1.This calculation can be seen in Table 7 below.
Calculated Distribution Losses. FERC Forum 1 Compariso�
Distribution Input 15,619,939 FERC Total Energy 18,376,323
Distribution Output 15,120,270 FERC Forum 1 Losses 1,238,735
Distribution Losses 499,669 Bridger/Valmy Losses 125,811
Missing Losses (4,634) Total FERC Losses 1,364,546
Corrected Losses 495,035 Calculated Losses 1,369,180
Adjusted Losses (4,634)
Table 7: Calculated Losses(MWh) Correction
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 9 of 17

Analysis of System Losses Idaho Power Company
Loss Coefficients Tables
Tables 8 and 9 contain the MWh losses in each of the level as well as the inputs and output to each
level.Table 8 shows the energy coefficients over the entire calendar year 2022 whereas Table 9 shows
the peak coefficients during the peak day in 2022.
Outputs2022 Energy Loss Coefficients Table -Wheeling Included (Values in MWh)
Transmission lnput�sW Loss Coefficients Losses Transmission
Power Supply 11,325,243 Transmission 1.029 771,823 Retail Sales 151,444
Utility purchases 4,394,440 High Volt 1,318,132
PURPA/Cust Gen 1,950,434 Wheeling 9,114,526
Exchange IN 27,768 Exchange OUT 0
Wheeling IN 9,325,825
Total 27,023,710 Delivery Point Coefficient 1.029 771,823 Total 10,584,102
Distribution Stations 1.006 97,688
From Transmission 15,667,785 Direct Sales 946,593
Wheeling 91,552
Total 15,667,785 Delivery Point Coefficient 1.036 869,511 Total 1,038,145
• Distribution Primary 1.014 215,080
From Stations 14,531,952 Sales 3,067,827
PURPA/Cust Gen 805,834 Wheeling 656
Total 15,337,786 1 Delivery Point Coefficient 1.051 1,084,591 Total 3,068,483
- • • . • Distribution Secondary 1.024 279,955 . • • . • •
From Primary 12,054,223 Sales 11,704,706
NET Metering 92,076 Wheeling 117,676
Street lighting 43,961
Total 12,146,929 Total 1.076 1,364,546 Total 11,866,343
Table 8:2022 Energy Loss (MWh)Coefficients Table
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 10 of 17

Analysis of System Losses Idaho Power Company
Peak Loss Coefficients
An identical method to the annual losses coefficients was used in calculating the peak hour loss
coefficients. For the calculated losses,the same equations were used but only for the data from July 14th
at 7:00 PM.The inputs to the system were determined with the use of historical PI data from the same
hour, along with MV90 hourly data. Some aspects were determined to be 0 or small enough to not
influence the end results and were excluded to simplify the calculation. The results of this peak hour
analysis are shown in Table 9 below.
2022 Peak Loss Coefficients Table-Wheeling Included (Values in MWh)
Outputs
Power Supply 1,869 Transmission 1.037 181 Retail Sales 19
Utility purchases 1,500 High Volt 0
PURPA/Cust Gen 853 Wheeling 752
Wheeling IN 804
Total 5,026 Delivery Point Coefficient 1.037 181 Total 771
• Distribution Stations 1.005 20 1 •
From Transmission 4,074 Direct Sales 108
Wheeling 15
Total 4,074 Delivery Point Coefficient 1.042 201 Total 123
• Distribution Primary 1.013 55 d •
From Stations 3,931 Sales 404
PURPA/Cust Gen 365 Wheeling 0
Total 4,296 Delivery Point Coefficient 1.056 256 Total 404
• • . • Distribution Secondary 1.019 72 • • . • •
From Primary 3,837 Sales 3,765
Total 3,837 Total 1.076 328 Total 3,765
Table 9: 2022 Peak Loss (MWh) Coefficients Tanie
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 11 of 17

Analysis of System Losses Idaho Power Company
Avoidable Losses by On-Site Customer Generation
Customers with on-site generation could avoid some of the losses previously discussed in this report.
However,there are losses, such as transformer core losses,that are not a function of load and will not
be able to be avoided by customers with on-site generation
To determine the avoidable losses from customers with on-site generation,the losses due to
transformer core-losses and distribution secondary were removed from the calculation and new
coefficients were calculated.The avoidable losses were separated into two different periods, an on-peak
period that covers June 15th to September 15th from 3:00pm to 11:00pm excluding Sundays and holidays
and an off-peak period that cover the rest of the hours in the year.
Previously, the loss coefficients were determined for the entire year and for the peak hour. In order to
determine the coefficients for the on-peak season,the hourly data from 138-kV system was used as
proxy to modify the peak and energy calculations.The 138-kV system was chosen due to having all
hourly data available and being a better representation on the Company loading at any given time.
The peak losses were modified to capture the load variability (and losses)that occurred from June 15th
to September 15th.Table 10 shows the adjustments to the peak coefficients to determine the on-peak
avoidable losses.
2022 • VODER(Values in MWh)
Transmission91W •ss Coefficients AMMI hjra ns missionOutputs
Power Supply 1,869 Transmission 1.034 164 Retail Sales 19
Utility purchases 1,500 High Volt 0
PURPA/Cust Gen 853 Wheeling 752
Exchange IN 0 Exchange 0
Wheeling IN 804
Total 5,026 Delivery Point Coefficient 1.034 164 Total 771
Distribution Stations 1.003 14
From Transmission 4,091 Direct Sales 108
Wheeling 15
Total 4,091 Delivery Point Coefficient 1.037 178 Total 123
di Distribution Primary 1.012 52 •
From Stations 3,954 Sales 404
PURPA/Cust Gen 365 Wheeling 0
Total 4,319 Delivery Point Coefficient 1.050 230 Total 404
• • . is Distribution Secondary 1.000 - • . •
From Primary 3,863 Sales 3,863
Total 3,863 j Total 1.050 1 230 j Total 3,863
Table lu:HaJusted VOIDER Energy Losses(MM) Coefficients Table
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 12 of 17

Analysis of System Losses Idaho Power Company
Similarly,the off-peak coefficients were modified to remove the on-peak data and obtained an off-peak
coefficient.Table 11 shows the modifications to the off-peak coefficients.
2022 • Adjusted VOIDER
OutputsTransmissio Loss Coefficients Losses Transmission
Power Supply 11,325,243 Transmission 1.026 697,937 Retail Sales 150,532
Utility purchases 4,394,440 High Volt 1,318,132
PURPA/Cust Gen 1,945,752 Wheeling 9,114,526
Exchange IN 53,368 Exchange 25,600
Wheeling IN 9,325,825
Total 27,044,628 Delivery Point Coefficient 1.026 697,937 Total 10,608,790
• • Distribution Stations 1.003 45,753 * 1 • •
From Transmission 15,737,901 Direct Sales 946,593
Wheeling 91,552
Total 15,737,901 Delivery Point Coefficient 1.029 743,690 Total 1,038,145
Distribution Primary 1.014 212,900 •
From Stations 14,654,003 Sales 3,042,892
PURPA/Cust Gen 805,968 Wheeling 656
Total 15,459,971 Delivery Point Coefficient 1.044 956,589 Total 3,043,548
• • . Distribution Secondary 1.000 • . •
From Primary 12,203,524 Sales 12,203,524
Total 12,203,524 j Total 1.044 1 956,589 1 Total 12,203,524
Table 11:Adjusted VODER Peak Losses(MWh) Coefficients Table
The avoidable losses coefficients are shown in Table 12 below.
• •
• 1.026 1.034
1.029 1.037
1.044 1.050
• . 1.044 1.050
Table 12:Adjusted VOIDER Delivery Point Loss Coefficients
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
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Analysis of System Losses Idaho Power Company
Appendix A: 2012 Energy Losses Data Sources
Transmission Value
Inputs (MWh) Data Source Notes
Power Supply FERC Form 1 p 401a line
Generation 11,325,243 9
FERC Form 1 p 326.8-
327.12 col g (Subset of OATT Power purchases from
Utility Utility Purchases FERC utilities/entities not directly connected to
Purchases 4,394,440 Form 1 p 401a line 10) IPC system
FERC Form 1 pp 326-
327.7 col g(Subset of Power purchased from non-IPC owned
PURPA/Cust Utility Purchases FERC generation connected to IPC transmission
Gen 1,950,434 Form 1 p 401a line 10) system
FERC Form 1 p 401a line Details on FORM 1 p 326.12-327.13
Exchange In 27,768 12 See "FF1 326-327.xlsx"
FERC Form 1 p 401a line
Wheeling In 9,325,825 16 File: "Wheeling Form 1 Detail.xlsx"
Transmission
Outputs
High Voltage FERC Form 1 p 401a line
Sales 1,318,132 24 Details on Form 1 p 311
FERC Form 1 p 401a line Details on FORM 1 p 326.12-327.13
Exchange Out 25,600 12 See "FF1 326-327.xlsx"
FERC Form 1 p 401a line
Wheeling Out 9,114,526 17 File: "Wheeling Form 1 Detail.xlsx"
Retail
Transmission FERC Forum 1—p 304
Sales 151,444 FERC Forum 1—p 304 Rate 9T, 19T, and Unbilled Rev. Large
Distribution
Station
Outputs
Direct Station FERC Forum 1—p 304
Sales 946,593 FERC Forum 1—p 304 Special Contracts
Wheeling Out 91,552 Operation Data File: "Wheeling Form 1 Detail.xlsx"
Distribution
Primary Inputs
Subset of Utility Purchases
PURPA gen connected to FERC Form 1 p 401a line 10
IPC Primary distribution Total from p 401a line 10 is split by system
system from FERC Form level on spreadsheet:
PURPA 805,834 1 p 326-327.7 col g "FF1 326-327.xlsx"
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
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Analysis of System Losses Idaho Power Company
Distribution
Primary
Outputs
Direct Primary FERC Forum 1—p 304
Sales 3,067,827 FERC Forum 1—p 304 Rate 09P, 19P, 08, and Unbilled Rev. Small
Wheeling Out 656 Operations Data File: "Wheeling Form 1 Detail.xlsx"
Distribution
Secondary
Inputs
Net Met/Ore
Solar 92,076 Operations Data "IPC_Exports_by_Class.xlsx"
Distribution
Secondary
Outputs
FERC Forum 1—p 304
Distribution 07, 09S, 19S, 24S,Total Billed Residential
Sales 11,704,706 FERC Forum 1—p 304 Sales—Rate 15., and Unbilled Rev.
FERC Forum 1—p 304
Rate 15, 40, and TOTAL Billed Public Street
Street Lighting 43,961 FERC Forum 1—p 304 and Highway Lighting
Wheeling Out 117,676 1 Operations Data I File: "Wheeling Form 1 Detail.xlsx"
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 15 of 17

Analysis of System Losses Idaho Power Company
Appendix B: 2012 Peak Losses Data Sources
Transmission Value
Inputs (MW) Data Source Notes
Power Supply
Generation 1,869 Pi
Utility Purchases 1,500 Pi see file "Peak_day_data.xlsx"
PURPA/Cust Gen 853 Pi
Wheeling In 804 Operations data on peak hour File: "Wheeling Forum 1 Detail.xlsx"
Transmission
Outputs
Transmission customer sales
from MV90 data: filename
Retail Sales 19 "MV90 2022 8760.xlsx"
Wheeling Out 752 Pi File: "Wheeling Forum 1 Detail.xlsx"
Distribution
Station Outputs
Sales from MV90 data:
Direct Station filename "MV90 2022
Sales 108 8760.xlsx"
Wheeling Out 15 Pi File: "Wheeling Forum 1 Detail.xlsx"
Distribution
Primary Inputs
PURPA 365 Pi
Distribution
Primary Outputs
Sales from MV90 data:
Direct Primary filename "MV90 2022
Sales 404 8760.xlsx"
Distribution
Secondary
Outputs
Wheeling Out 36.9 Pi File: "Wheeling Forum 1 Detail.xlsx"
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
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Analysis of System Losses Idaho Power Company
Appendix D: Reconciliation with FERC Form 1
The data used in the development of the energy loss coefficients in this report is consistent with that
reported in the 2022 FERC Form 1, page 401a. Values used in Figure 1 are reconciled with values in 2022
FERC Form 1 below.
System Losses
Item Figure 1 2012 FERC Comment
MWh Form 1 MWh
Total System Losses 1,364,546 1,238,725 Form 1, pg 401a, line 27
Adjustment for Bridger Loss 124,135 Bridger Loss transactions counted as
Transactions system outputs in Form 1 (part of
total in Form 1, pg 401a, line 13)
Adjustment for Valmy Loss 1,676 Valmy Loss transactions counted as
Transactions system outputs in Form 1 (part of
total in Form 1, pg 401a, line 13)
Adjusted Total 1,364,546 1,364,180
The ratio of Adjusted FERC Form 1 losses to Figure 1 losses is 99.66%. Reasons for the small discrepancy
may include non-uniformity between the calculation method used to determine transmission losses on
the Bridger and Valmy subsystems in this study versus the calculation method used to determine the
actual loss transactions and estimation methods used where small amounts of data were missing in the
tabulation of individual level losses.
Exhibit No.3
Case No. IPC-E-25-15
J. Ellsworth, IPC
Page 17 of 17

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-15
IDAHO POWER COMPANY
ELLSWORTH , DI
TESTIMONY
EXHIBIT NO. 4

4N6 HIDAHO KweRe
2024 VER Integration Cost
Study
December 2024
© 2024 Idaho Power
Exhibit No.4
Case No. IPC-E-25-15
J. Ellsworth, IPC
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Idaho Power Company 2024 VER Integration Study
Table of Contents
Tableof Contents..............................................................................................................................i
Acknowledgements......................................................................................................................... 1
Glossary..................................................................................................................................... 2
ExecutiveSummary......................................................................................................................... 3
RegulatoryHistory .......................................................................................................................... 3
PriorStudy................................................................................................................................. 4
On-Site Generation and the Export Credit Rate ....................................................................... 4
Future Cadence of Updates ............................................................................................................ 4
Study Integration and Process Flow ......................................................................................... 5
Methodology................................................................................................................................... 6
ModelBasis............................................................................................................................... 6
Ancillary Service Requirements and Reserves.......................................................................... 6
Incremental Resource Study Cases........................................................................................... 7
Consideration of the Inclusion of Incremental Resource Capital Costs ................................... 8
Metric and Threshold Evaluation........................................................................................ 9
Corrective Measure .......................................................................................................... 10
Determination of the Integration Cost................................................................................... 11
Results........................................................................................................................................... 13
Exhibit No.4 Page i
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Idaho Power 2024 VER Integration Study
Acknowledgements
Idaho Power would like to thank the members of the Technical Review Committee whose
expertise was invaluable towards the development of this VER Integration Study.
Name Organization
Wesley Cole, Ph.D. National Renewable Energy Laboratory (NREL)
Brian Johnson, Ph.D., P.E. University of Idaho
Kurt Myers Idaho National Laboratory (INL)
Mike Louis, Matt Suess, Yao Yin Idaho Public Utilities Commission (IPUC)
Kim Herb, Ryan Bain, Ryan Kern Public Utility Commission of Oregon (OPUC)
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Idaho Power 2024 VER Integration Study
Glossary
EUA—Expected Unserved Ancillaries
EUE—Expected Unserved Energy
IPUC—Idaho Public Utilities Commission
IRP—Integrated Resource Plan
IRPAC—IRP Advisory Council
k—indicates a multiple of 1,000
LOLE—Loss of Load Expectation
LTCE—Long-Term Capacity Expansion
MW—Megawatt
MWh—Megawatt-hour
NPV—Net Present Value
O&M—Operations and Maintenance
OPUC—Public Utility Commission of Oregon
RCAT—Reliability and Capacity Assessment Tool
SCCT—Simple-Cycle Combustion-Turbine
TRC—Technical Review Committee
VER—Variable Energy Resource
VODER—Value Of Distributed Energy Resources
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Idaho Power 2024 VER Integration Study
Executive Summary
Idaho Power Company's (Idaho Power or company) 2024 Variable Energy Resource Integration
Cost Study (2024 VER Integration Study) contains the company's updated integration costs and
lays out the methodology by which they were produced. See the Methodology section for more
details.
The company assembled and leveraged the expertise of a Technical Review Committee (TRC) to
provide feedback throughout the study process. See the Acknowledgements section for a list of
the members and organizations represented on the TRC.
The methodology proposed and implemented in this report leverages the preferred portfolio
and the regulation reserve requirements utilized in the most recently acknowledged Integrated
Resource Plan (IRP), namely the 2023 IRP. Going forward, leveraging the results of the IRP will
simplify and streamline the VER study process and allow for more frequent updates to the
company's integration costs.
Idaho Power's updated integration costs are in the last column of the following table:
Portfolio
Portfolio Cost Cost Differential
Cost with without Relative to
Ancillaries Ancillaries Preferred Portfolio
NPV ($x NPV($x Difference ($x Incremental Integration
Portfolio 1,000) 1,000) 1,000) Energy (MWh) Cost$/MWh
Preferred Portfolio $9,678,287 $9,406,427 N/A N/A
100MW Solar $9,677,224 $9,369,718 $35,646 5,116,037 6.97
200MW Solar $9,696,854 $9,330,309 $94,685 10,232,074 9.25
100MW Wind $9,589,833 $9,314,133 $3,840 6,005,227 0.64
200MW Wind $9,505,452 $9,220,324 $13,268 12,010,455 1.10
Regulatory History
Idaho Power has historically used VER integration studies as the basis for developing the
company's integration charges, specifically Schedule 87— Intermittent Generation Integration
Charges (Schedule 87) in Idaho. In Oregon, integration charges are addressed within Schedule
85—Cogeneration and Small Power Production Standard Contract Rates, which Idaho Power
files with the Public Utility Commission of Oregon (OPUC).
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Idaho Power 2024 VER Integration Study
Prior Study
The company's last VER integration study was published in 2020 (2020 VER Integration Study).
This study was referenced in the IPUC's Order No. 36048 regarding the compensation structure
applicable to customers with on-site generation. In that order, the IPUC directed Idaho Power
to use the 2020 VER Study to update Schedule 87.
Given that the data used to develop the 2020 VER Study is now at least six years old, Idaho
Power petitioned the IPUC in Docket No. IPC-E-24-08 to allow the company to develop an
updated VER Study and use it as the basis for updating integration charges. On June 10, 2024,
the IPUC issued Order No. 36219 granting Idaho Power permission to develop a new VER study
and use it as the basis for updating Schedule 87. The order also required Idaho Power to file
both the study and updated integration charges with the IPUC no later than December 31,
2024.
On-Site Generation and the Export Credit Rate
The Company additionally uses the results from the VER integration study as one of the
components of the Export Credit Rate ("ECR") for on-site generation customers. The ECR is the
rate paid to retail customers with on-site generation taking service under net billing. Customer
on-site generation, most typically from solar generation, is a VER, meaning it does not provide
firm or dispatchable energy to the company's system; therefore, there are costs associated with
accommodating the uncertainty associated with these resources. Idaho Power incurs
integration costs due to reduced flexible resource optimization, caused by VER uncertainty,
when planning operations ahead of real time. The ECR reflects the total costs and benefits of
customer on-site generation on the Company's system, including VER integration costs which
will come from the most recent VER Integration Cost Study.
While the VER integration study determined the cost of accommodating additional utility scale
solar, the Company found that a utility scale profile is a reasonable proxy for the shape of on-
site solar generation. As such, the Company assesses that the integration costs identified in this
report are an appropriate input to the ECR without modification.
Future Cadence of Updates
Beginning with this study, Idaho Power intends to more frequently update both its VER studies
and the associated integration costs. Historically, Idaho Power has filed VER integration studies
as one-off studies, each of which had a distinct and largely incomparable methodology and
scope.
In the past, VER integration studies have been a holistic process in which the reserve
requirements were defined and calculated and then fed directly into a modeling effort to
calculate the cost of integrating additional VERB. Although the company's prior VER studies
aligned with modeling used in IRPs, the standalone nature of each new VER study made it
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Idaho Power 2024 VER Integration Study
difficult to compare integration studies or integration costs over time. Additionally, this
bespoke approach to VER studies did not allow Idaho Power to fully leverage already vetted
models to generate VER integration charges—in part due to misalignment between study
timing and the availability of data, as well as their ultimate use case.
Now, there are robust datasets with which to model the cost of integrating wind and solar
resources and, due to the significant overlap of the IRP process, Idaho Power intends to update
VER integration costs after IRP acknowledgment when factors warrant an update. Such an
approach would end the one-off nature of VER integration studies and would, instead, yield a
simplified and easily replicable process that leverages the highly scrutinized and vetted IRP. To
be clear, Idaho Power is not indicating that the process would need to occur after each IRP.
Rather, the company's objective, beginning with this VER study, is to build a standard protocol
for updating integration costs as needed following completion of the IRP process.
Study Integration and Process Flow
Looking ahead, Idaho Power intends to connect, rather than have disjointed processes for, the
IRP and VIER integration studies. Going forward, both processes could be included in the IRP. In
order to merge these processes as much as possible and to minimize duplicative work, the
determination of regulating reserve requirements will need to be separated from the
generation of VIER integration costs. Idaho Power intends for reserve requirements to be
determined as part of the process of updating IRP inputs, thus creating a standardizing update
process. The standard IRP modeling process would then follow, with the determination of the
Preferred Portfolio and its vetting culminating in regulatory consideration of the IRP. Upon IRP
acknowledgment, the VER Integration Cost study can commence in a structured and
mechanical manner using the same model as the IRP. Study cases would be determined and the
VER integration costs would be calculated with the results filed in an update to the current
charges. An overview diagram of the proposed process is outlined in the figure below, with the
timing and order of actions moving from left to right:
Data Long-Term portfolio V VER Cost Study
Inputs Capacity Analysis IRP Filing Integration Filing
Expansion Cost Study
Calculation of
Reserve Costs Assessment
Requirements Generation of File Integration
Study Cases Charge Update
Creation of
Reserve Determination
Compliant and
Portfolios for Risk Assessment Acknowledgment
Scenario and of the Preferred
Sensitivity Portfolio
Analysis
Calculation of Update
All Other IRP Dependencies
Inputs and Additional
Assumptions Outputs
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Idaho Power 2024 VER Integration Study
Methodology
As part of this study, Idaho Power has updated its methodology for calculating VER integration
charges as used in Schedule 87. The goal of the changes are as follows:
• leverage existing models to the extent possible,
• create an evergreen process that is simple to update and is largely automatic and, based
on the above,
• develop a method that is transparent and easy to review.
In the today's rapidly changing electric utility industry, it will be difficult to create a truly
evergreen process, but Idaho Power believes that the methods detailed below provide a solid
foundation from which this process can evolve as necessary.
Model Basis
Where possible, this integration study has used the 2023 IRP model. That model has been well
vetted through the entire IRP process and serves as the basis for many analyses that Idaho
Power has undertaken since the acknowledgment of the 2023 IRP. That model has been vetted
first in the public IRP Advisory Council (IRPAC) meetings, where important inputs and
assumptions are made available to stakeholders for comment and feedback. From there, the
analysis was scrutinized via validation and verification tests, with draft results presented to the
IRPAC for further feedback. The results culminated in the IRP report, which received extensive
regulatory review by key stakeholders, including staff members of the IPUC and OPUC. Finally,
to conclude the cycle, the 2023 IRP was acknowledged by Idaho Power's state regulators.'
Ancillary Service Requirements and Reserves
To be consistent with the 2023 IRP analysis, Idaho Power is leveraging Energy Exemplar's
AURORA software, the same tool that has been used for numerous prior plans. Idaho Power has
a long history using the AURORA electric market model as its primary tool for modeling
resource operations and determining operating costs among many other uses. AURORA is an
economic model that optimizes the dispatch of generation and transmission resources to match
demand. The operation of existing and future resources is based on forecasts of important
i Idaho PUC Case No. IPC-E-23-23, Order No.36233 and Oregon PUC Docket No. LC 84,Order No. 24-285
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Idaho Power 2024 VER Integration Study
drivers including: demand, fuel prices, hydroelectric conditions, and operational resource
characteristics.
One of AURORA's notable strengths is its ability to quantify the cost of VER integration by
modeling the regulating reserves required to reliably deliver power to an electric system with
non-dispatchable generation. AURORA does this through the use of ancillary services in the
form of"up regulation" and "down regulation" products. In order for a resource to provide an
up regulating reserve it needs to be able to respond by increasing its output to match a
decrease in generation of the VER resource. Effectively, the resource needs to be online and in
a state to respond. For most resources, this means that, instead of outputting a megawatt-hour
(MWh), they are instead held back such that additional capacity could be deployed, hence
earning the title of a reserve.
When AURORA dispatches resources, it optimizes to reduce the cost to serve load while
adhering to the ancillary or regulation requirements. In doing so, it also calculates the cost of
providing those regulating reserves. For this study, the regulating reserve requirements are the
same as those used in the 2023 IRP model.z
Incremental Resource Study Cases
The first step in determining the cost of integrating the next incremental wind or solar resource
(applicable to both distributed and utility-scale installations) is selecting appropriate study or
use cases. These cases were created considering a handful of pertinent factors detailed below.
Integration Block Size: There are tradeoffs when selecting the size of the incremental resource
used to study the cost of VER integration. If the size is too small, it may be difficult to
reasonably guess which block of integration charges a project would be subject to without
going through the full process of understanding where a project is in the queue. If the size is too
large, then a subsidy could potentially be created between early and late entrants in a block.
Thus, it is important to strike a balance of reasonably size blocks.
For this integration study, Idaho Power, with help from the TRC, selected a 100-megawatt
(MW) block size for the study. This size aligned with the 2023 IRP proxy wind or solar resource
sizing. It also strikes a reasonable balance to avoid to the extent possible the negative effects of
having blocks that are too large or too small. If historical trends continue with the average size
of a wind or solar Public Utility Regulatory Policies Act of 1978 qualifying facility (QF) at roughly
20 MW,3 the 100 MW block approach would allow five projects to integrate before moving to
Z 2023 IRP Report:Table 9.1 page 123.
12023 IRP Appendix C:Technical Appendix, pg 28-29.Average Solar QF size 18 MW and Wind QF size of 20 MW.
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Idaho Power 2024 VER Integration Study
the next block, thereby ensuring near-term certainty of the integration charge for a new QF
project.
VER Groups: With the 100 MW block size determined, Idaho Power then focused on
determining the appropriate combination and total amount of the different VERs to study.
Similar to incremental block sizing, there are tradeoffs with the number and variety of cases to
analyze. With too few cases, the integration charge that a project is subject to may not
reasonably represent the system as it exists at the time of integration. With too many cases,
significant effort can be wasted studying cases that have low probability of occurring.
In consultation with the TRC after describing the prior parameters, it was agreed that four
incremental resource cases would be studied: 100 MW of solar, 200 MW of solar, 100 MW of
wind, and 200 MW of wind. Although these cases are limited compared to the prior VER
studies, they represent more than the expected increase in new QF VER development to occur
between this update and the next expected update following acknowledgment of the 2025 IRP.
The 2023 IRP showed that if recent trends in the development of either wind or solar QFs
continue, even the 100 MW blocks are not expected to be exceeded in the next few years,4
which is well past the next expected update to the integration charges. This is true with the
inclusion of distributed solar installations as well.
Consideration of the Inclusion of Incremental Resource Capital Costs
During meetings with the TRC, the question was raised whether capital and fixed operations
and maintenance (0&M) costs should be included in the update to integration charges. The TRC
was concerned that, because the IRP's preferred portfolio is optimized around a particular set
of resources, the inclusion of additional VER resources might not be able to meet the ancillary
service requirements they necessitate. Although Idaho Power agrees with the TRC that this is a
possibility and may include this charge in the future, the Company, through a literature review,
found little information on how to assess unmet ancillary needs and no information on how to
correct an unmet ancillary need should one be found. Given the current lack of generally
accepted modeling practice regarding this concept, Idaho Power does not believe it appropriate
to include in this study but finds it valuable to detail a proposed methodology so that the
company can receive feedback for possible inclusion in future studies.
In the TRC meetings, the Company proposed an outline for a possible method to calculate these
additional costs. At a high level, the method first involves determining a metric with which to
evaluate unmet ancillary needs and from there to determine a cutoff point at which a
corrective action would be necessary. Once the threshold is set, the IRP model would be run to
determine if there were violations of the threshold and then also to determine the corrective
generation resource to bring any unmet ancillary needs under the threshold. With the
4 Cogeneration and Small Power Production Forecast, 2023 IRP Advisory Council Meeting Oct. 13, 2022.
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Idaho Power 2024 VER Integration Study
corrective generation resources added to the model, the additional capital and fixed 0&M costs
could be captured, as well as any cost-offsetting activities those resources could provide.
Metric and Threshold Evaluation
As previously noted, when doing a literature review on the subject, Idaho Power was not able
to find an accepted industry best practice method with which to evaluate unmet ancillary
needs. Thus, for this first proposal, other analogous metrics were evaluated from typical
reliability analysis because of their overlap with ability to serve load. First evaluated was the
use of a Loss-of-Load-Expectation (LOLE) type analysis. This method was investigated because
the company already used it for evaluating portfolio reliability as part of the 2023 IRP and there
are readily accepted LOLE thresholds used in the industry. In its investigations, it was quickly
determined that generating a similar metric for expected unmet ancillaries would not be
practical. The current Reliability and Capacity Assessment Tool (RCAT) has been designed to
evaluate LOLE and not assess ancillary regulating reserves. Thus, further metrics were explored
that could be implemented for this study. The use of Expected Unserved Energy (EUE) was
deemed analogous and possible to implement with the outputs of the 2023 IRP model. The EUE
metric is a measure of the amount of energy that a particular system is expected to not be able
to supply due to a lack of generating capacity in a given year. The EUE metric could also be
applied within the time constraints of this study to analyze unmet ancillaries because it is
simple to check what the expected unmet ancillaries are in a given year and then determine if
they cross the threshold value. As part of its algorithms, the Aurora based 2023 IRP model
already calculates if, when, and to what extent there would be an expected unserved ancillary.
With the ability to determine expected unserved ancillaries, the question becomes where to set
the threshold for when corrective action would be required.
Although many regions within the United States are still in the exploratory phase of analyzing
the use of EUE as a primary reliability metric, Australia is currently using it with a maximum
value of 0.002 percent of annual energy expected to be unserved and others are beginning to
coalesce around this same value. Again, because this method has not yet been widely evaluated
or adopted, in some contexts the 0.002 percent threshold may be referred to as a 20 parts per
million threshold. In other words, for a utility expected to deliver 1,000,000 MWh in a year,
they would set their threshold at 20 MWh of EUE in that year, which is 0.002 percent of
1,000,000 MWh.
With the 0.002 percent threshold set, the next issue is to determine the basis by which to
calculate the expected unserved ancillaries—specifically whether the 0.002 percent threshold
should be applied strictly to the expected ancillaries in a given year or applied to some other
value. In this case, Idaho Power believes that using the same expected delivered energy basis
may be appropriate. The reason for this basis is that within AURORA, as in actual operations, a
reserve MWh and an energy MWh are intermingled items. In order for a resource to provide a
MWh of up regulation reserve, it must be held back from producing a MWh of energy, hence
reserve. Because these values are so intertwined, Idaho Power proposes that the threshold for
expected unserved ancillaries be set at 0.002 percent of annual delivered energy.
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Idaho Power 2024 VER Integration Study
Corrective Measure
With the metric and threshold set, the final component to analyzing the inclusion of
incremental capital costs necessary for the integration of VERB is the determination of a
corrective measure. The determination of the corrective measure requires considerable
analysis, including identifying the cost-optimal resource type and quantity of that resource to
provide the ancillary reserves necessary for the integration of VERB.
For simplicity and alignment with the 2023 IRP, 50 MW blocks of 4-hour battery storage were
used as the corrective measure for this study. The primary candidate resources from the 2023
IRP that can provide the necessary reserves are peaking gas and 4-hour storage. For this study,
4-hour storage was chosen because its operational characteristics and cost make it the least-
cost ancillary-providing resource.
In the case of the peaking gas plant in the form of a Simple-Cycle Combustion-Turbine (SCCT),
once the unit is online, it can provide ancillaries but will be limited by both its ramp rate and
the difference between its minimum and maximum capacity. This effectively limits the 170 MW
SCCTs modeled in the 2023 IRP to 85 MW or 50 percent of their nameplate of reserve providing
capacity. In comparison, 4-hour storage resources can go from a state of charging to a state of
discharging in very short periods. If a storage resource is charging from a solar facility and the
output of that solar facility drops rapidly due to cloud cover, the storage resource can, in that
moment, switch to a discharging state. This swing from charging to discharging is a swing of
twice the nameplate of the storage resource. Thus, for the 50 MW 4-hour storage modeled in
the 2023 IRP, it could provide 100 MW of reserve capability. Using the levelized capacity costs
in the 2023 IRPS of$12/kW-month and $17/kW-month for an SCCT and 4-hour storage resource
respectively and adjusting to account for the ancillaries each resource could provide, the values
change to $24/kW-month and $8.5/kW-month per kW of ancillaries provided, respectively, for
an SCCT and 4-hour storage resource. This analysis shows that the 4-hour storage resource is
the least cost per kW of ancillary providing resources in the 2023 IRP.
With the least-cost ancillary-providing resource selected, the next issue is determining the
amount of that resource needed to bring the amount of expected unserved ancillaries below
the previously determined threshold. After consulting with the TRC, Idaho Power chose to use
the following algorithm:
1. Determine if the expected unserved ancillaries in any given year exceeds the 0.002
percent threshold.
a. If a year exceeds the threshold, add a number of blocks equal to the expected
unserved ancillaries minus the total delivered energy times the threshold, all
divided by the ancillary-providing capability of the correcting resource block
5 Idaho Power 2023 IRP-Appendix C:Technical Appendix page 25.
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Idaho Power 2024 VER Integration Study
rounded up. Should this value exceed the block additions in a prior year, the
incremental blocks are added.
b. If a year is determined to be below the 0.002 percent threshold, then no
corrective action is necessary and any blocks identified in a prior year are
allowed to remain.
2. Now, there exists the possibility that because of the state of charge or other operational
constraints, the blocks may be insufficient to provide the necessary ancillaries. To
account for this possibility, the new resources are added to the portfolio and it is rerun
through AURORA to determine if the additional resources provide the necessary
ancillaries to reduce the EUA below the threshold. If they do, the process ends; but if
they do not, then the process repeats until sufficient ancillary-providing resources are
added to the model.
The pseudocode for this process is provided below:
• While output max(EUAt) > 0.002% * Energyt
— If EUAt<_ 0.002% * Energyt
• Blockst = max(0,Blockst_1)
— If EUAt > 0.002% * Energyt
• Add 50 MW blocks of 4-hr Storage resources equal to:
EUAt-Energyt*EUAThresholdl Blocks )• Blockst = max AncillaryMaxOfCorrection I' t-1
G
• Loop
Where:
EUAt is the expected unserved ancillaries in a year t
Blockst is the number of blocks of resources in year t
Energyt is the total expected delivered energy in year t
And [xj represents the ceiling function or round up.
Determination of the Integration Cost
The primary tool used to develop updated integration costs is the same AURORA model used to
develop and analyze the portfolios of the 2023 IRP. The process used to quantify those costs
was multi-step but largely procedural.
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Idaho Power 2024 VER Integration Study
1. Start with the 2023 IRP's revised preferred portfolio, titled "November 2026 132H Valmy
1 & 2".6 In the course of regulatory review of the 2023 IRP, a revised preferred portfolio
became relevant to reflect an update to the timing associated with the Boardman to
Hemingway Transmission Line (132H).
2. Create the incremental resource builds. Reflecting the incremental resource study cases
previously discussed, the VERB were added to the preferred portfolio starting in year
2025 as must-take resources reflecting the must-take obligation of QF projects.
3. Analyze the various portfolios using AURORA, consistent with the methods deployed in
the 2023 IRP. For each of these portfolios, perform additional analysis in AURORA with
the ancillary services calculations turned off.
4. The integration cost is then calculated using the relative change between the base case
with and without the ancillary services calculations compared to the same cases with
the incremental resource study cases.
The process of producing integration charges is outlined in the figure below as it was
presented to the TRC:
2023 IRP
Preferred Study Cases Portfolio Costing VER Integration
PortfolioWind: 10OMW With Charge
Comparison .
and �O
Regulating
Reserves
BetweenNovember L -A L
Portfolio With
and 20OMW Regulating Regulating
ReservesReserves
There are compelling reasons to use this method to calculate the VER integration charge. First,
the selected method leverages the AURORA-based 2023 IRP. The model inputs have already
been extensively vetted through the IRP process and the Aurora software is among the best
production cost modeling software used in North America.
Second, AURORA is able to model the holistic change in operations required to reliably
integrate renewables and, thus, is well suited to calculate the cost of integration.
6 Idaho Power 2023 IRP-Appendix C:Technical Appendix, page 45.
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Idaho Power 2024 VER Integration Study
By considering how additional must-take VERB change the Idaho Power's whole dispatch stack,
the entire cost and value stream of the additional resources can be considered in aggregate.
Results
Using the methods and procedures described above, the following net present value (NPV)
portfolio costs are produced, along with associated integration costs, for each portfolio:
Portfolio
Portfolio Cost Cost Differential
Cost with without Relative to
Ancillaries Ancillaries Preferred Portfolio
NPV ($x NPV($x Difference ($x Incremental Integration
Portfolio 1,000) 1,000) 1,000) Energy (MWh) Cost$/MWh
Preferred Portfolio $9,678,287 $9,406,427 N/A N/A
100MW Solar $9,677,224 $9,369,718 $35,646 5,116,037 6.97
200MW Solar $9,696,854 $9,330,309 $94,685 10,232,074 9.25
100MW Wind $9,589,833 $9,314,133 $3,840 6,005,227 0.64
200MW Wind $9,505,452 $9,220,324 $13,268 12,010,455 1.10
In the above table, the Portfolio column identifies the study cases, as well as the baseline
reference case, which is the "November 2026 B2H Valmy 1 & 2" portfolio from the 2023 IRP. As
the name implies, the 100MW Solar case includes 100 MW of incremental must-take solar to
the preferred portfolio. By extension, the other portfolio case names specify the resource type
and incremental must-take resource added.
The "Portfolio Cost with Ancillaries" column shows the total portfolio cost using the same
financial assumptions' and calculation methods used in the 2023 IRP. The "With Ancillaries" in
the title refers to the fact that the model had to account for the regulating reserves necessary
to integrate the VERs in the Preferred Portfolio, as well as the incremental VERB in the study
cases where applicable. The next column, "Portfolio Cost without Ancillaries," uses the same
financial assumptions and calculation methods except that the AURORA dispatch model was
allowed to integrate the VERs in the various portfolios without regard for the need to hold
regulating reserves.
The difference between the "With Ancillaries" and the "Without Ancillaries" cases is the model
estimated cost for holding regulating reserves for the VERs in each case. Thus, for the Preferred
Portfolio, the cost of the regulating reserves is the difference between $9,678,287k and
$9,406,427k or$271,860k.
Idaho Power 2023 IRP-Appendix C:Technical Appendix, page 20.
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Idaho Power 2024 VER Integration Study
The "Cost Differential Relative to Preferred Portfolio Difference" column calculates each study
case's regulating reserve cost and then subtracts the preferred portfolio difference. Working
through this for the 10OMW Solar case the calculation is ($9,677,224k—$9,369,718k) —
($9,678,287k—$9,406,427k) = $35,646k. This method isolates the additional regulating reserve
costs caused by the incremental VER resource in each study case.
The column "Incremental Energy" is the amount of energy associated with the incremental VER
resource over the planning horizon. Finally, the column "Integration Cost" divides the
regulating reserve cost due to the incremental resources and the energy expected from those
resources and converts it to a $/MWh. In the 10OMW Solar case, $35,646,000/5,116,037MWh =
$6.97/MWh. The other integration costs follow this same calculation specific to each portfolio.
Additionally, the results presented do not include costs related to additional capital for
portfolios that would need to include additional integrating resources to accommodate the
must-take VERB.
These integration costs will be reflected in Idaho Power's updated tariffs that directly or
indirectly address integration charges.
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-15
IDAHO POWER COMPANY
ELLSWORTH , DI
TESTIMONY
EXHIBIT NO. 5

SEE ATTACHED SPREADSHEET