20240318IPC DIRECT ELLSWORTH TESTIMONY.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
APPROVAL OF A MARKET PURCHASE
AGREEMENT.
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CASE NO. IPC-E-24-12
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
JARED L. ELLSWORTH
RECEIVED
2024 MARCH 18, 4:33PM
IDAHO PUBLIC UTILITIES
COMMISSION
ELLSWORTH, DI 1
Idaho Power Company
Q. Please state your name, business address, and 1
present position with Idaho Power Company (“Idaho Power” or 2
“Company”). 3
A. My name is Jared L. Ellsworth and my business 4
address is 1221 West Idaho Street, Boise, Idaho 83702. I am 5
employed by Idaho Power as the Transmission, Distribution & 6
Resource Planning Director for the Planning, Engineering & 7
Construction Department. 8
Q. Please describe your educational background. 9
A. I graduated in 2004 and 2010 from the 10
University of Idaho in Moscow, Idaho, receiving a Bachelor 11
of Science Degree and Master of Engineering Degree in 12
Electrical Engineering, respectively. I am a licensed 13
professional engineer in the State of Idaho. 14
Q. Please describe your work experience with 15
Idaho Power. 16
A. In 2004, I was hired as a Distribution 17
Planning engineer in the Company’s Delivery Planning 18
department. In 2007, I moved into the System Planning 19
department, where my principal responsibilities included 20
planning for bulk high-voltage transmission and substation 21
projects, generation interconnection projects, and North 22
American Electric Reliability Corporation’s (“NERC”) 23
reliability compliance standards. I transitioned into the 24
Transmission Policy & Development group with a similar 25
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Idaho Power Company
role, and in 2013, I spent a year cross-training with the 1
Company’s Load Serving Operations group. In 2014, I was 2
promoted to Engineering Leader of the Transmission Policy & 3
Development department and assumed leadership of the System 4
Planning group in 2018. In early 2020, I was promoted into 5
my current role as the Transmission, Distribution and 6
Resource Planning Director. I am currently responsible for 7
the planning of the Company’s wires and resources to 8
continue to provide customers with cost-effective and 9
reliable electrical service. 10
Q. What is the Company’s request in this case? 11
A. Idaho Power is requesting the Idaho Public 12
Utilities Commission (“Commission”) approve the market 13
purchase agreement with Powerex Corp. (“Powerex”) necessary 14
to meet the identified capacity deficiency in 2026 and 15
declaration that all payments the Company makes to Powerex 16
pursuant to such agreement will be allowed as prudently 17
incurred expenses for ratemaking purposes. 18
Q. What is the purpose of your testimony in this 19
case? 20
A. The purpose of my testimony is to inform the 21
Commission of the Company’s need for new resources to meet 22
an identified capacity deficit in 2026 as informed by a 23
Loss of Load Expectation (“LOLE”) methodology utilized in 24
the 2021 Integrated Resource Plan (“IRP”), again in the 25
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Idaho Power Company
2023 IRP, and subsequently further enhanced through system 1
reliability evaluations. I will describe the most recent 2
assessment of system reliability and its impact to the 3
capacity deficit identified in the annual capacity position 4
utilized in the 2023 IRP. Finally, I will provide support 5
for the acquisition of resources to address the identified 6
near-term capacity needs. 7
I. BACKGROUND 8
Q. What is the goal of the IRP? 9
A. The goal of the IRP is to ensure: (1) Idaho 10
Power’s system has sufficient resources to reliably serve 11
customer demand and flexible capacity needs over a 20-year 12
planning period, (2) the selected resource portfolio 13
balances cost, risk, and environmental concerns, (3) 14
balanced treatment is given to both supply-side resources 15
and demand-side measures, and (4) the public is involved in 16
the planning process in a meaningful way. Idaho Power uses 17
Energy Exemplar’s AURORA’s Long-Term Capacity Expansion 18
(“LTCE”) modeling platform to develop portfolios, through 19
the selection of a variety of supply- and demand-side 20
resource options, that are least-cost for a variety of 21
alternative future scenarios while meeting reliability 22
criteria. To verify the top performing portfolios meet the 23
Company’s reliability requirements, Idaho Power utilizes a 24
LOLE methodology. 25
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Idaho Power Company
Q. Please explain the Loss of Load Expectation. 1
A. The LOLE is a statistical measure of a 2
system’s resource adequacy, describing the expected number 3
of event-days per year that a system would be unable to 4
meet demand. As utilities continue to add more renewable 5
energy to the electric grid, analyzing the effect variable 6
energy resources have on system reliability has become more 7
critical. The LOLE methodology recognizes that the output 8
of variable energy resources, such as wind and solar, 9
change with time (with their hourly output being dependent 10
on a multitude of factors like weather and environmental 11
conditions); it is essential to capture and value that 12
variability. 13
Q. What inputs are derived from the LOLE 14
methodology that are utilized in the AURORA LTCE model? 15
A. Idaho Power implements the LOLE methodology 16
through an internally developed Reliability and Capacity 17
Assessment Tool (“RCAT”) which is capable of producing 18
inputs such as a Planning Reserve Margin (“PRM”) and 19
resource Effective Load Carrying Capability (“ELCC”) 20
values. The PRM metric can be defined as the percentage of 21
expected capacity resources above forecasted peak demand. 22
The ELCC calculation is a reliability-based metric used to 23
assess the capacity contribution of variable and energy-24
limited resources. The PRM and ELCC values that are 25
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Idaho Power Company
calculated using the LOLE methodology are a direct input to 1
the AURORA LTCE model. 2
Q. How are the PRM and ELCC values utilized? 3
A. Because the AURORA LTCE model and the RCAT are 4
two separate tools, a translation is required between the 5
probabilistic LOLE analysis performed in RCAT and the 6
portfolios produced by the AURORA LTCE model. First, PRM 7
and ELCC values are calculated using the LOLE methodology 8
and directly inputted to the AURORA LTCE model. After 9
AURORA solves for and produces portfolios, select resource 10
buildouts and their corresponding data are analyzed with 11
the LOLE methodology and tested to ensure they meet the 12
pre-designated reliability hurdle through the calculation 13
of annual capacity positions. It is critical when comparing 14
future resource portfolios that each plan achieves at least 15
a base reliability threshold. Figure 1 below illustrates 16
the model consolidation process. 17
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Idaho Power Company
Figure 1. Idaho Power’s Reliability Flowchart 1
2
Q. Have the LOLE-derived annual capacity 3
positions replaced the previously utilized load and 4
resource balance? 5
A. Yes. While they serve the same purpose, to 6
determine capacity deficiencies, the annual capacity 7
position calculation is a 2023 IRP methodology improvement 8
that replaced the load and resource balance process 9
performed in prior IRP filings. The load and resource 10
balance was a tabulated plan that helped visually ensure 11
Idaho Power had sufficient resources to meet projected 12
customer demand including a margin to account for extreme 13
conditions, reserves, and resource outages, identifying 14
resource deficiencies during the 20-year IRP planning 15
horizon. Beginning with the 2023 IRP, to better align with 16
and represent the probabilistic reliability analyses 17
utilized and to be consistent with best practices in the 18
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Idaho Power Company
industry, the RCAT was utilized to calculate annual 1
capacity positions in place of the deterministic load and 2
resource balance. The LOLE-derived annual capacity position 3
calculation is a better indication of resource reliability 4
as compared the previously utilized load and resource 5
balance. The goal is the same under both processes: 6
identification of the timing of the Company’s first 7
resource need, or the point at which Idaho Power’s 8
reliability requirements may not be met. 9
Q. If the goal of both processes is the same, how 10
is the LOLE-derived annual capacity position calculation an 11
IRP methodology improvement? 12
A. In the 2021 IRP, the Company derived static 13
PRM and resource ELCC values that were held constant 14
throughout the 20-year planning horizon. As the RCAT and 15
AURORA serve different purposes in Idaho Power’s planning 16
process, the Company recognized that further efforts were 17
needed to translate and align the data exchanged between 18
the two models. Historically, the PRM was based on the peak 19
load of a given year plus some additional amount to account 20
for abnormal weather events or equipment outages. This 21
method worked well to ensure reliability for Idaho Power as 22
a summer peaking utility with mostly flexible generation 23
resources. However, as the wider industry, and the Company, 24
experience increased reliance on variable energy resources, 25
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Idaho Power Company
whose hour-to-hour and season-to-season generation changes, 1
it is no longer viable to only contemplate peak hour 2
requirements. 3
To ensure that AURORA would recognize similar 4
capacity needs as identified by the RCAT, the Company 5
developed seasonal PRM values for years in the planning 6
horizon that experience significant changes in the resource 7
buildout, better representing the seasonal resource needs. 8
Historically, when a portfolio added predominantly flexible 9
generation resources it was also sufficient to give these 10
resources a static peak capacity contribution as it was 11
harmonious with a static PRM. As variable energy resource 12
and energy limited resource additions increase, static 13
values no longer account for the reduced peak capacity 14
contribution due to saturation nor do they capture the 15
diversity benefit (positive or negative) of a mix of 16
different types of variable energy resources and energy 17
limited resources. 18
Q. Were any changes made to the use of resource 19
ELCC values as well? 20
A. Yes. The ELCC of future variable energy 21
resources and energy limited resources are dependent upon 22
the resources built before them, making the ELCC 23
calculation of future resources challenging. Idaho Power 24
implemented seasonal resource specific ELCC saturation 25
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Idaho Power Company
curves for variable energy resources and energy limited 1
resources in the AURORA LTCE model for the 2023 IRP. 2
Q. Please explain the synchronization of the RCAT 3
and the AURORA LTCE model. 4
A. To better assess the dynamic diversity benefit 5
caused by a changing resource mix, a feedback process was 6
implemented between the AURORA LTCE model and the RCAT for 7
the 2023 IRP. Under the feedback process, the annual 8
capacity positions for an AURORA LTCE main case portfolio 9
buildout were calculated using the RCAT. Once the annual 10
capacity positions were known, the PRM in the AURORA LTCE 11
model was modified in years that had significant resource 12
changes so that both models identified a similar annual 13
capacity position. The feedback loop continued until the 14
main case portfolio was reliable under the LOLE threshold. 15
The resulting AURORA-produced optimized main case 16
portfolios provide the least-cost, least-risk future 17
resource buildouts. 18
II. ANNUAL CAPACITY POSITION 19
Q. What have the previous capacity position 20
results indicated with respect to Idaho Power’s resource 21
sufficiency? 22
A. The Company has been generally resource-23
sufficient since the addition of the Langley Gulch natural-24
gas fired power plant almost a decade ago until the filing 25
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Idaho Power Company
of the 2021 IRP. That is, Idaho Power’s owned generation 1
and transmission resources, along with negotiated purchases 2
under Power Purchase Agreements (“PPA”) and mandatory 3
purchases under the Public Utility Regulatory Policies Act 4
of 1978 (“PURPA”), were sufficient to meet the Company’s 5
load growth over that time. With the resource and load 6
inputs from the 2021 IRP, Idaho Power rapidly moved from an 7
expected resource-sufficient position through 2028,1 to a 8
near-term capacity deficiency starting in 2023. The rapid 9
change in the resource position, identified during 10
preparation of the 2021 IRP, was caused by several dynamic 11
and converging factors, including third-party transmission 12
capacity constraints, load growth, and a decline in the 13
peak-serving effectiveness of certain supply-side and 14
demand-side resources. These dynamic circumstances led the 15
Company to immediately file a request for a CPCN to acquire 16
resources to be online in 2023.2 17
Q. What were the capacity positions ultimately 18
identified in the 2021 IRP? 19
A. The capacity positions identified in Idaho 20
Power’s 2021 IRP, acknowledged with Order No. 35603, 3 were 21
deficits of approximately 101 MW in 2023, 186 MW in 2024, 22

1 Idaho Power’s Second Amended 2019 Integrated Resource Plan, Case No. IPC-E-19-
19.
2 Case No. IPC-E-22-13.
3 Case No. IPC-E-21-43.
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Idaho Power Company
311 MW in 2025, 560 MW in 2026, and 665 MW in 2027. As a 1
result, in addition to the Company’s request for a CPCN for 2
the 2023 resource procurement, Idaho Power filed a CPCN and 3
approval of a PPA to acquire resources to be online in 20244 4
and a CPCN and approval of an Energy Storage Agreement to 5
acquire resources to be online in 2025.5 6
Q. Since the completion of the 2021 IRP, has the 7
Company refreshed its capacity positions, potentially 8
influencing Idaho Power’s resource need? 9
A. Yes. The Company continually assesses system 10
reliability, monitoring near-term known changes, 11
operational enhancements, limitations, or constraints on 12
the existing system, if any, that would impact the resource 13
needs. Furthermore, on September 29, 2023, the Company 14
filed its 2023 IRP, which included current information on 15
the expected timing of major new loads, the resource 16
procurements the Company had made to date, annual capacity 17
positions and other updates. 18
Q. What were the annual capacity positions 19
identified in the 2023 IRP? 20
A. Incorporating modeling input updates and the 21
additional enhancements to the Company’s reliability 22
evaluation discussed earlier in my testimony, the 23

4 Case No. IPC-E-23-05 and IPC-E-23-20.
5 Case No. IPC-E-23-20.
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Idaho Power Company
incremental capacity needs identified in the 2023 IRP were 1
22 MW in 2026 and 44 MW in 2027, with the need continuing 2
to grow through the remainder of the planning horizon. 3
Q. Did Idaho Power’s modeling updates include the 4
Boardman to Hemingway transmission line (“B2H”) as a new 5
resource? 6
A. Yes. B2H was identified and acknowledged as a 7
cost-effective resource in the Company’s 2021 IRP preferred 8
resource portfolio with a current planned in-service date 9
of summer of 2026. B2H will provide Idaho Power with 750 MW 10
of capacity in the west-to-east direction for market 11
purchases for load service and transmission service to 12
third-party transmission customers under the Company’s Open 13
Access Transmission Tariff. Further, an asset exchange 14
between PacifiCorp and Idaho Power, in complement with B2H, 15
will provide the Company with 200 MW of bidirectional 16
transmission capacity between southern power markets (Mona 17
and Four Corners) and the Idaho Power system. The full B2H 18
capacity is modeled in the transmission portion of AURORA, 19
with separate transmission links modeled for each owner, 20
one with Idaho Power’s share and one with PacifiCorp’s 21
share. The Company treats approximately 500 MW of B2H’s 22
summer capacity as equivalent to a summer resource and the 23
200 MW of transmission capacity to southern power markets 24
as equivalent to a winter resource. All transmission 25
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capacity has the potential to be leveraged for market 1
purchases. The 2023 IRP continued to confirm the cost-2
effectiveness of B2H and the associated asset exchange and 3
its inclusion in the IRP’s Preferred Portfolio. 4
Q. Did Idaho Power evaluate how the annual 5
capacity position would change should the online date of 6
B2H be delayed? 7
A. Yes. The 2023 IRP considered an alternative 8
B2H online date beyond July 2026 should there be a delay in 9
receiving permits, supply chain constraints, or other 10
unforeseen events. The alternative scenario assumed a 11
November 2026 online date for B2H, which changes the 12
Company’s capacity needs from 22 MW under a July 2026 B2H 13
online date to 356 MW under a November 2026 B2H online 14
date. 15
Q. You indicated Idaho Power continually assesses 16
system reliability. Has the Company updated the system 17
reliability assessment since the 2023 IRP was filed in 18
September 2023? 19
A. Yes. The Company recognizes that during the 20
near-term resource decision-making phase, the annual 21
capacity positions can be very fluid. In addition, in the 22
face of growing loads, Idaho Power constantly monitors 23
resource needs and responds with added urgency, as 24
evidenced by Idaho Power’s consecutive requests for CPCNs 25
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Idaho Power Company
to acquire resources to be online in 2023, 2024 and 2025.6 1
The most recent system reliability assessment, which 2
assumes the online date for B2H is beyond summer of 2026, 3
has identified a capacity deficit of 236 MW in 2026. 4
Q. What drove the changes to the annual capacity 5
positions for 2026 in the most recent system reliability 6
assessment? 7
A. Aside from modeling input updates associated 8
with the latest load forecast, expected existing resource 9
availability and the most recent 5-year rolling average 10
Equivalent Forced Outage Rates during Demand (“EFORd”), the 11
biggest drivers of the change in the annual capacity 12
position in 2026 are associated with (1) B2H, (2) the 13
Capacity Benefit Margin (“CBM”), and (3) the North Valmy 14
Generating Station (“Valmy”). Due to delays in obtaining 15
some necessary permits, the anticipated in-service date of 16
B2H is beyond the summer of 2026. Absent the available 17
transfer capacity of B2H in July 2026, and further the 200 18
MW of bidirectional transmission capacity from the southern 19
power markets, the capacity deficit increases. 20
Q. What changes were made to the CBM modeling 21
assumptions since the annual capacity position identified 22
in the development of the 2023 IRP? 23
A. CBM is transmission capacity Idaho Power sets 24

6 Case Nos. IPC-E-22-13, IPC-E-23-05, and IPC-E-23-20.
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aside on the Company’s transmission system, as unavailable 1
for firm use, for the purposes of accessing reserve energy 2
to recover from severe conditions such as unplanned 3
transmission and generation outages or energy emergencies. 4
An energy emergency must be declared by Idaho Power before 5
the CBM transmission capacity becomes firm. The Company 6
holds 330 MW of import transmission capacity aside on the 7
Idaho to Northwest path for CBM. CBM does not, however, 8
have corresponding third-party transmission reservations to 9
the Mid-C market. 10
Because of continued transmission market 11
limitations beyond the Idaho Power border, in the 2023 IRP 12
the Company reduced the contribution of CBM toward the 13
annual capacity position, from 330 MW for all seasons to 14
200 MW for March through October and 0 MW in the winter for 15
planning purposes. Idaho Power’s continued evaluation of 16
CBM has indicated that, similar to the winter months, last 17
minute transmission acquisition between the market and 18
Idaho Power’s border under emergency conditions in the 19
summer months has not been consistently available. The 20
Company still believes CBM is valuable for customers from a 21
reliability perspective and believes that transmission 22
availability may change in the future. However, for the 23
time-being, for resource planning purposes, the Company 24
believes it is appropriate to adjust CBM to 0 MW year-round 25
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given the recent challenges ensuring a connection to the 1
Mid-C market in emergency conditions. 2
Q. What changes were made to Valmy’s availability 3
that have impacted the annual capacity position? 4
A. Since identification of the conversion of 5
Valmy Units 1 and 2 to natural gas operations by 2026 as an 6
economic resource alternative in the 2023 IRP, Idaho Power 7
and NV Energy, the Valmy co-owners, have aligned on a 8
decision to convert the units and have finalized a 9
conversion agreement that will amend the pertinent sections 10
of the existing ownership and operations agreements to 11
reflect gas-fired operations of both units. With definitive 12
agreements in place that detail the Company’s increased 13
Valmy capacity beginning in 2026, Idaho Power included the 14
additional 261 MW of available capacity in the latest 15
system reliability assessment. 16
Q. You indicated modeling input changes consisted 17
of updates made to the latest load forecast, resource 18
availability and EFORd. What has changed since development 19
of the 2023 IRP? 20
A. Any time the system reliability evaluation is 21
performed, Idaho Power includes the most up-to-date load 22
and resource inputs. With the continued high load growth in 23
the Company’s service area, the load forecast is 24
consistently monitored and updated as new information 25
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becomes available. In addition, planned maintenance of one 1
of the Oxbow hydro units will reduce the overall resource 2
availability in 2026. The 5-year rolling average EFORd was 3
updated with the latest published data from the NERC 4
Generation Availability Data System, reflecting the 5
industry average generation resource performance data and 6
outage rates using the most recent data. Finally, two PURPA 7
contracts with solar projects proposed to be located in 8
eastern Oregon were terminated due to the developers’ 9
failure to perform, resulting in the removal of 72 MW of 10
available solar nameplate capacity. 11
Q. Based on your most recent evaluation of system 12
reliability, how has the annual capacity position for 2026 13
changed since Idaho Power’s 2023 IRP was filed? 14
A. The Company’s most recent system reliability 15
assessment to determine the annual capacity positions has 16
identified an increase in the previously identified 17
capacity deficit to 236 MW in 2026. As I discussed 18
previously, due to the fluidity of the annual capacity 19
positions during the near-term resource decision-making 20
phase, Idaho Power continually assesses system reliability. 21
But because the Company has been repeatedly matching near-22
term resource procurements with the capacity need 23
identified at a point in time, the fluctuating need is 24
requiring continued procurement of resources. 25
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Q. Does the load forecast used to identify the 1
236 MW deficit in 2026 include large load inquiries that 2
Idaho Power continues to experience in its service 3
territory? 4
A. No. In the 2023 IRP, the Company provided a 5
large load planning scenario that added 200 MW to Idaho 6
Power’s load forecast to account for potential additional 7
large loads. Although the Company continues to receive 8
inquiries for large loads that are considering siting in 9
Idaho Power’s service territory, the Company has not yet 10
utilized this large load scenario to determine its future 11
resource procurement needs. Idaho Power will continue to 12
evaluate whether a transition to the large load scenario is 13
necessary. Such a transition would increase resource 14
deficits in future years. 15
III. MEETING THE CAPACITY DEFICIENCY 16
Q. Did Idaho Power evaluate any alternative 17
solutions for meeting the capacity deficiencies to avoid 18
building a new resource? 19
A. Yes. As I discussed earlier in my testimony, 20
as part of the IRP process, the Company uses AURORA’s LTCE 21
modeling platform to develop portfolios, through the 22
selection of a variety of supply- and demand-side resource 23
options, that are least-cost for a variety of alternative 24
future scenarios while meeting reliability criteria. The 25
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future supply- and demand-side resources available to meet 1
identified capacity deficiencies, whose costs are generally 2
based on the 2022 Annual Technology Baseline report 3
released by the National Renewable Energy Laboratory,7 4
include new gas-fired resources, hydrogen, wind, solar, 5
battery storage, market purchases via available 6
transmission capacity, demand response and energy 7
efficiency. The Preferred Portfolio from the 2023 IRP, 8
which included a July 2026 online date for B2H, identified 9
the conversion of Valmy Units 1 and 2 to natural gas, the 10
procurement of 100 MW of solar as the most cost-effective 11
resources for meeting the identified capacity deficits in 12
2026 along with 19 MW of energy efficiency potential 13
(identified in the energy efficiency potential study). In 14
addition, as part of the 2023 IRP modeling, the Company 15
evaluated an alternative B2H online date beyond July 2026 16
should there be a delay in receiving permits, supply chain 17
constraints, or other unforeseen events, assuming an online 18
date for B2H of November 2026. This evaluation is, in 19
essence, identifying the most cost-effective alternative 20
for meeting the identified capacity deficit should the B2H 21
online date be delayed to November 2026. 22
Q. How was the evaluation of the November 2026 23
B2H on-line date performed? 24

7 atb.nrel.gov/.
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A. Three different November 2026 B2H simulations 1
were analyzed with AURORA’s LTCE modeling: (1) a November 2
2026 B2H on-line date with a conversion of both Valmy Units 3
1 and 2 to natural gas, (2) a November 2026 B2H on-line 4
date with the conversion of only Valmy Unit 2 to natural 5
gas, and (3) a November B2H on-line date without the 6
availability of either Valmy unit. These simulations 7
include the costs associated with adding generation 8
resources (both supply-side and demand-side) and optimally 9
dispatching the resources to meet the constraints within 10
the model. The three different simulations and their 11
associated costs, presented below in Table 1, can be 12
compared to identify the most cost-effective alternative to 13
meeting the 2026 capacity deficit should B2H be delayed to 14
November 2026. 15
Table 1. 2023 IRP Portfolio Costs 16
Portfolio Net Present Value
Years 2024-2043
($ x 1,000,000)
(1) Nov2026 B2H Valmy 1&2 $9,767
(2) Nov2026 B2H Valmy 2 $9,880
(3) Nov2026 B2H Without Valmy $10,192
17
With a portfolio cost of $9.767 billion, the conversion of 18
Valmy Units 1 and 2 to natural gas in 2026 is $113 million 19
less than the conversion of only Valmy Unit 2, and $425 20
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million less than a portfolio that does not include the 1
conversion to natural gas of either Valmy unit, indicating 2
that the conversions of Valmy Units 1 and 2 to natural gas 3
continues to be a cost-effective resource alternative, 4
particularly with a November 2026 B2H online date. 5
Q. What additional resources were selected as 6
cost-effective alternatives for meeting the capacity 7
deficiency under a scenario with a November 2026 B2H online 8
date and the conversion of both Valmy units to natural gas? 9
A. When compared to the 2023 IRP Preferred 10
Portfolio, in 2026 an additional 300 MW of solar was 11
selected, 400 MW in total, as well as 155 MW of battery 12
storage and 40 MW of demand response, indicative of the 13
Company’s need to procure resources to continue to provide 14
safe, reliable electric service to its customers in 2026 15
and beyond. 16
Q. Has Idaho Power taken any actions to acquire 17
resources to meet the 236 MW capacity deficit in 2026? 18
A. Yes. Under Idaho law, Idaho Power has an 19
obligation to provide adequate, efficient, just, and 20
reasonable service on a nondiscriminatory basis to all 21
those that request it within its certificated service area.8 22
Further, as indicated by Order No. 35643, Idaho Power is 23
responsible for planning and managing its load and resource 24

8 Idaho Code §§ 61-302, 61-315, 61-507.
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portfolio and the Commission expects “the Company to 1
closely monitor its projected capacity needs going forward 2
and to act proactively to ensure a robust RFP process can 3
be completed.”9 Therefore, in order to meet its obligations 4
to reliably serve customers, on September 15, 2022, Idaho 5
Power filed an application with the Public Utility 6
Commission of Oregon (“OPUC”) to open an independent 7
evaluator selection docket to oversee the Request for 8
Proposals (“RFP”) process.10 This also ensured a fair and 9
transparent procurement process that was compliant with the 10
OPUC’s competitive bidding rules, which the Commission 11
directed Idaho Power to follow as well.11 The Company’s 12
compliance with the OPUC competitive bidding guidelines, 13
which will be discussed in greater detail in the direct 14
testimony of Mr. Hackett, ultimately led to a competitive 15
solicitation through the issuance of the 2026 All-Source 16
RFP, seeking a combination of energy and capacity resources 17
that provide a minimum of approximately 350 MW of peak 18
capacity and up to 1,100 MW of variable energy resources 19
for 2026 and 2027 (“2026 RFP”). 20
Q. Why did the 2026 RFP request a minimum of 21
approximately 350 MW of peak capacity and up to 1,100 MW of 22

9 Page 13.
10 Docket UM 2255.
11 Order No. 32745. Case No. IPC-E-10-03.
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variable energy resources for 2026 and 2027 if the 1
identified capacity deficit was 236 MW in 2026? 2
A. Following the 2021 IRP, the Company had 3
identified a 311 MW deficiency in 2025 and a 665 MW 4
deficiency in 2027. Assuming the 311 MW deficiency would be 5
addressed through the 2024 and 2025 resource procurements 6
for which Idaho Power received CPCNs, the incremental need 7
was 354 MW (665 MW - 311 MW = 354 MW), or approximately a 8
350 MW peak capacity need. 9
Given the significant timeframe related to the RFP 10
process under the OPUC competitive bidding guidelines, the 11
2026 RFP was responsive to the resource needs identified in 12
the Company’s 2021 IRP filing, which included near-term 13
preferred portfolio additions of wind, solar, storage, 14
cost-effective energy efficiency measures, the conversion 15
of coal units to natural gas, incremental demand response, 16
and B2H coming online in 2026. The transmission included in 17
the 2021 IRP preferred portfolio, including B2H, provides 18
valuable capacity that ultimately must be paired with 19
energy to serve load. In addition to soliciting resources 20
that provide capacity and energy aligned with the resource 21
needs, the 2026 RFP solicited a portion of the energy 22
market purchases that will be necessary to serve load for 23
2026 and beyond. This market purchase approach is intended 24
to allow the Company to begin acquiring a portion of the 25
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energy that will be needed to serve load using pre-existing 1
firm transmission rights, without acquiring more than what 2
will be needed in a majority of hours, while also allowing 3
Idaho Power to make additional procurement decisions and 4
solicitations over time, considering updated information 5
and the most recent IRP available at that time. 6
Additionally, the RFP needed to remain flexible to 7
account for the fluidity of the Company’s annual capacity 8
positions as well as any potential delays in the B2H online 9
date. Ultimately, the 2026 resources selected through the 10
RFP process were based on the most recent capacity 11
deficiency of 236 MW in 2026. As detailed in Company 12
witness Mr. Hackett’s testimony, through the Company’s 13
robust competitive bidding process, Idaho Power has 14
identified the three most cost-effective bids from the 2026 15
RFP evaluation as necessary to fill the 2026 capacity 16
deficit. The first bid resulted in the execution of a 200 17
MW contract with Powerex for a capacity-based product and 18
firm energy contract effective June 2026. The second bid 19
selected was a benchmark resource, the Idaho Power-owned 20
battery storage facility providing up to 150 MW of 21
operating capacity. Idaho Power is currently negotiating 22
agreements for the third project submittal resulting from 23
the 2026 RFP, a 200 MW solar photovoltaic (“PV”) plus 100 24
MW battery storage project. However, because there are time 25
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constraints associated with the market purchase agreement 1
that led the Company to submit it to the Commission 2
expeditiously, Idaho Power is only filing a request for 3
approval of the market purchase agreement at this time. 4
Q. How does the 200 MW Powerex market purchase 5
impact the 236 MW capacity deficiency? 6
A. In 2026, the Powerex market purchase reduces 7
the capacity deficiency from 236 MW to approximately 186 MW 8
– a 50 MW reduction. In the 2021 and 2023 IRPs, the Company 9
had already assumed that transmission capacity between the 10
Pacific Northwest and Idaho was resource equivalent 11
capacity. Therefore, utilizing that same transmission 12
capacity to import the Powerex 200 MW market purchase 13
results in no incremental resource capacity gain, although 14
it does begin to fulfill the Company’s energy import needs 15
as described in the 2026 RFP and earlier in my testimony. 16
The Company was able to acquire 50 MW of incremental 17
transmission, for one year through Montana, in 2026 and 18
therefore the Powerex market purchase provides for 50 MW of 19
capacity in 2026. Once B2H is completed, the Powerex 20
contract will be treated as 200 MW of fully incremental 21
capacity. 22
Q. How do the 200 MW solar PV plus 100 MW battery 23
storage project and the Idaho Power-owned battery storage 24
facility providing up to 150 MW of operating capacity 25
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impact the 2026 capacity deficit? 1
A. The combined projects are estimated to reduce 2
the 2026 deficit an additional 176 MW. The 200 MW solar PV 3
plus 100 MW battery storage project will reduce the 2026 4
capacity deficit approximately 110 MW while the Company-5
owned battery storage facility will reduce the 2026 6
capacity deficit approximately 66 MW. 7
Q. Why does a battery storage facility that 8
provides 150 MW of operating capacity only reduce the 9
deficit 66 MW? 10
A. When solar photovoltaic (“PV”) and energy 11
storage are added together, the ELCC of the combined 12
resource is high – a 100 MW solar PV plus 100 MW storage 13
facility can have an 80 MW or higher ELCC. When solar PV 14
and battery storage additions become unbalanced via large 15
additions of one and not the other, the result is a lower 16
ELCC for the resource that was added, and a higher ELCC for 17
the resource that was not added. This is occurring in 2026 18
given the large quantity of battery storage the Company is 19
adding in 2025, and now further adding to this storage in 20
2026, resulting in a lower ELCC for energy storage 21
facilities. 22
However, this lower ELCC is just a year-2026, 23
snapshot in time issue. In addition to the 200 MW solar PV 24
plus 100 MW energy storage project as a cost-effective 25
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resource addition in 2026, Idaho Power is forecasting the 1
addition of approximately 525 MW of solar PV, spread 2
through late-2026 and 2028, associated with a large load 3
customer. The addition of this stand-alone solar will 4
increase the capacity contribution of the energy storage to 5
the portfolio in those years. Thus, while the procurement 6
of a higher amount of storage to meet 2026 needs may reduce 7
its ELCC (all the procurement is necessary for reliability 8
purposes), it sets the Company up well to accept planned 9
stand-alone solar additions to the system in the future. 10
Q. Do you believe there is sufficient support for 11
the procurement of the market purchase with Powerex 12
effective June 2026? 13
A. Yes, I do. The resource acquisitions were 14
pursued and procured as a least cost/least risk method of 15
meeting the capacity deficits first identified in the 16
Company’s 2021 IRP, again in the 2023 IRP, and subsequently 17
with the results of system reliability evaluation. Further, 18
the acquisition is a critical incremental step in 19
fulfilling the Company’s long–term import needs – that is, 20
the energy the Company will need to import on available 21
firm transmission to serve load. The fluidity of the 22
capacity deficit period and continued high load growth 23
further supports these resource procurements. 24
// 25
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IV. CONCLUSION 1
Q. Please summarize your testimony. 2
A. Idaho Power’s most recent system reliability 3
evaluation has identified a capacity deficiency of 236 MW 4
in 2026. In response to this resource need, the Company has 5
executed a 200 MW capacity-based product and firm energy 6
contract, for which Idaho Power is requesting approval of 7
at this time, and identified an Idaho Power-owned battery 8
storage providing 150 MW of operating capacity and a 200 MW 9
solar PV plus 100 MW battery storage project to help 10
satisfy the identified capacity need in 2026. 11
Q. Does this complete your testimony? 12
A. Yes, it does. 13
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DECLARATION OF JARED L. ELLSWORTH 1
I, Jared L. Ellsworth, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Jared L. Ellsworth. I am employed 4
by Idaho Power Company as the Transmission, Distribution & 5
Resource Planning Director for the Planning, Engineering & 6
Construction Department. 7
2. On behalf of Idaho Power, I present this 8
pre-filed direct testimony in this matter. 9
3. To the best of my knowledge, my pre-filed 10
direct testimony is true and accurate. 11
I hereby declare that the above statement is true to 12
the best of my knowledge and belief, and that I understand 13
it is made for use as evidence before the Idaho Public 14
Utilities Commission and is subject to penalty for perjury. 15
SIGNED this 18th day of March 2024, at Boise, Idaho. 16
17
Signed: ___________________ 18
19
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