20240215Comments of the Commission Staff.pdf

CHRIS BURDIN
DEPUTY ATTORNEY GENERAL IDAHO PUBLIC UTILITIES COMMISSION PO BOX 83720 BOISE, IDAHO 83720-0074 [phone]
IDAHO BAR NO. 9810
Street Address for Express Mail: 11331 W CHINDEN BL VD, BLDG 8, SUITE 201-A BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER COMP ANY'S 2023 INTEGRATED RESOURCE PLAN
) ) CASE NO. IPC-E-23-23
)
) ) COMMENTS OF THE ) COMMISSION STAFF __________________ )
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission, by and
through its Attorney of record, Chris Burdin, Deputy Attorney General, submits the following
comments.
BACKGROUND
On September 29, 2023, Idaho Power Company ("Company") filed an application
("Application") with the Idaho Public Utilities Commission ("Commission") requesting that the
Commission issue an order acknowledging the Company's 2023 Integrated Resource Plan
("IRP").
The Company states that the 2023 IRP represents a comprehensive analysis of the
optimal mix of both demand-and supply-side resources available to reliably serve customer
demand and flexible capacity needs from 2024 to 2043. Application at 1-2.
STAFF COMMENTS 1 FEBRUARY 15, 2024
The Company represents that the primary goals of the 2023 IRP are to: (1) identify sufficient resources to reliably serve the growing demand for energy within the Company's service area throughout the 20-year planning period (2024-2043); (2) ensure the selected Preferred Portfolio balances cost and risk, while including environmental considerations; (3) give equal and balanced treatment to supply-side resources, demand-side measures, and transmission resources; and (4) involve the public in the planning process in a meaningful way. Id. at 5. The Company represents that it used the AURORA model to develop portfolios for the 2023 IRP. Id. at 7-8. The Company states that two notable trends emerged in the 2023 IRP, the vital nature of added transmission and the substantial downward trend in portfolio greenhouse gas emissions. Id. at 10. The Company represents that it identified several key resources or potential projects to evaluate in additional detail, and the Company required the model to build portfolios both with and without each resource or project. Id. at 14. The Company states that these models with and without views include: (1) with and without the B2H project; (2) with and without different phases of the Gateway West projects; and (3) with and without specific Valmy Unit 1 and Unit 2 natural gas conversion assumptions. Id.The Company represents that, based on its analysis, the Company selected a Preferred Portfolio identified in the 2023 IRP as "Valmy 1 & 2", referring to the portfolio's conversion of both Valmy units from coal to natural gas. Id. at 14-15. The Company states that this Preferred Portfolio is the least-cost, least-risk option that incorporates positive changes toward clean, low­cost resources without compromising system reliability. Id.The Company's Preferred Portfolio adds 3,325 megawatts ("MW") of solar, 1,800 MW of wind, 1,453 MW of storage (four-and eight-hour batteries, as well as long-duration 100-hour storage), 360 MW of additional energy efficiency ("EE"), 340 MW of hydrogen ("H2"), 160 MW of new demand response ("DR"), and 30 MW of geothermal. Id. at 3. Additionally, the Preferred Portfolio includes conversions of multiple coal-fired generation units to natural gas, showing the Company exiting coal entirely in 2030 and adding a net total of261 MW of natural gas via coal conversions through 2043 (reflecting the addition of 967 MW of gas conversions and 706 MW of gas conversion exits, netting 261 MW of additional gas generation). Id.STAFF COMMENTS 2 FEBRUARY 15, 2024
The Company represents that, in total, the Preferred Portfolio adds 6,888 MW of
incremental resource capacity over the next 20 years and includes the B2H transmission line
beginning in July 2026 and three Gateway West transmission line segments phased in from 2029
to 2040. Id.
The 2023 IRP contains the Company's Near-Term Action Plan that reflects near-term
actionable items of the Preferred Portfolio necessary to successfully position the Company to
provide reliable, economic, and environmentally sound service to its customers into the future.
Id. at 15.
The Company represents that the 2023 IRP incorporates prior recommendations it
received concerning several issues, and the 2023 IRP provides additional analysis/discussion of
those issues. Id. at 17.
On October 31, 2023, the Commission issued a Notice of Application and Notice of
Intervention Deadline. Order No. 35974. The Commission granted intervention to Micron
Technology, Inc. Order No. 36014. On December 1, 2023, a Notice of Parties was issued.
STAFF ANALYSIS
Staff recommends acknowledgment of the Company's 2023 IRP.
However, Staff believes that the Company's Preferred Portfolio may not be the least-cost
portfolio. Staff has evidence that a portfolio containing more coal and gas ("fossil fuel")
resources may be substantially less expensive than the Preferred Portfolio, albeit with an
unknown level of risk. Therefore, Staff recommends that the Company perform additional
analyses to validate the least-cost, least-risk portfolio and submit a supplemental report with the
results.
Staff recognizes the significant time and effort the Company invested in developing this
IRP and appreciates the vast amount of information compiled within it. The report has become
increasingly complex and increasingly important as the types of analysis and results from the
report guide and inform resource investments.
It is important to reiterate that the Commission's acknowledgment of the IRP should not
imply that the results and resources included in the Preferred Portfolio infer prudence. Staff
considers the resources included in the Company's Preferred Portfolio as "proxies" that the
Company selected based on assumptions made at the time. Staff expects that the Company will
STAFF COMMENTS 3 FEBRUARY 15, 2024
select each resource at the time of acquisition by evaluating it against the range of alternatives
that are available at that time and at current prices to obtain a determination of prudence.
Additional Staff comments and recommendations are organized in the following sections:
I.The Preferred Portfolio -Analysis and Recommendations;
II.The Near-Term Action Plan;
III.The Load Forecast;
IV.The Demand-Side Management Program;
V.The Seasons and Hours of Highest Risk;
VI.PURP A and Other Planning Assumptions; and
VII.Review of2021 Staff Recommendations.
Staff recommendations are summarized at the end of this document in the STAFF
RECOMMENDATION section.
I. THE PREFERRED PORTFOLIO -ANALYSIS AND RECOMMENDATIONS
The Preferred Portfolio is one of the primary results of the IRP process. It is the list of
supply-and demand-side resources the Company believes will reliably meet the forecasted load
over the next 20 years that are least cost and least risk. Because the Company uses the IRP
portfolio results and methods of analysis as part of its justification for new resource projects,
Staff examined the portfolio development process carefully, and found evidence that the
Preferred Portfolio may not be the least-cost portfolio.
Staff explains its findings and recommendations in the following five sub-sections:
1.An overview of the resource selection process;
2.The Company's Preferred Portfolio;
3.Portfolio cost comparison;
4.Possible sources of portfolio bias; and
5.Recommendations.
1.Overview of the Resource Selection Process
The Company uses the AURORA Long-Term Capacity Expansion ("L TCE") modeling
tool to select the resources for a portfolio. Application at 7-8. The Company inputs its
forecasted system load, its existing resources, and a list of possible new resources into the L TCE
STAFF COMMENTS 4 FEBRUARY 15, 2024
model. For each resource, the Company inputs performance and cost characteristics. The
Company also adds external constraints on the system that simulate likely future developments
such as the addition of a transmission line or the exit of a generation resource. The forecasted
system load is applied, and the model calculates the optimal mix of new resources needed to
meet the load at a specified reliability standard. This resulting portfolio is then subject to a
variety of pricing scenarios to determine which portfolio is the least-cost across most, or all, of
the scenarios. Application at 8.
2.The Company's Preferred Portfolio
Over the IRP's 20-year time window the Company forecasted that system load would
grow by 975 average megawatts ("aMW"), and the peak load would increase by 1,507 MW. IRP
Appendix C at 16-17. The aMW growth represents the additional steady-state energy the
Company must provide, and the peak load represents the amount of additional capacity the
Company must provide. Table No. 1 displays this information.
Table No. 1: Forecasted Load Growth
Year aMW Peak Hr
(MW)
2024 2024 3830
2043 2999 5337
Net Growth: 975 1507
To satisfy this increased load, the Company proposed a Preferred Portfolio containing a
mix of new resources. Table No. 2 lists the net change for each type of resource over the 20-year
time window. It also groups the resources into dispatchable resources, Variable Energy
Resources ("VER"), Battery Energy Storage System ("BESS") resources, and Demand-Side
Management ("DSM") resources.
STAFF COMMENTS 5 FEBRUARY 15, 2024
Table No. 2: 2023 Preferred Portfolio
20-yr Resource Category Resource Net Change (MW) (MW)
Coal -841 Net Dispatchable:
Gas 261
Hydrogen 340 -210
Geothermal 30
Solar 3325 Net Variable:
Wind 1800 5125
BESS 1453 Net BESS:
1453
Energy Efficiency 360 Net DSM:
Demand Response 160 520
From these two tables, the big picture of the Company's proposal comes into focus. To
satisfy the 975 aMW increase, the Company proposes to reduce its dispatchable resources, build
five times more variable generation than the average load increase, and add 1,500 MW of BESS
resources.
The Company's calculated net present value ("NPV") for this 20-year portfolio is $9.7
billion. Application at 11.
3.Portfolio Cost Comparison
To perform a high-level check on the cost-effectiveness of the Company's solution, Staff
created a simplified model of the load requirement, and devised a hypothetical way to satisfy it
using a combination of baseload and peaking dispatchable resources. The average load increase
of 975 aMW can be hypothetically satisfied by a single Combined-Cycle Combustible Turbine
("CCCT") gas plant, adjusted for its Capacity Factor ("CF"). Similarly, the peak load increase of
1,507 MW can be hypothetically satisfied by a single peaking resource, a Simple-Cycle
Combustion Turbine ("SCCT"), adjusted for its CF. Staff understands that this solution is
simplistic, and multiple smaller dispatchable resources would be more likely, but it serves as a
reasonable basis to compare order-of-magnitude costs. This model is illustrated in Figure No. 1
below.
STAFF COMMENTS 6 FEBRUARY 15, 2024
Figure No. 1: Model of a Hypothetical Dispatchable Resource Portfolio
6000
5000
4000
5 3000 2'.
2000
1000
0 Average Load & Peak Load }
Average Load growth }
2024 2043
1507 MW peak increase covered by 1658 MW SCCT
975 aMW increase covered by 1773 MW CCCT
Using the cost inputs and operating assumptions from the IRP Appendix C, page 21, Staff
calculated that this dispatchable portfolio would cost approximately $6. 7 billion to build in the
first planning year and operate for 20 years. This is $3 .2 billion less than the NPV cost of the
Preferred Portfolio.
To compare the two portfolio costs more fairly, Staff recalculated the VER and BESS
portions of the Preferred Portfolio cost by using the same method as the dispatchable portfolio.
By assuming both portfolios are fully built in year one, with 20 years of operating costs, the
portfolios can be evenly compared. The results show the VER and BESS portfolio has an up­
front cost estimate of $13. 9 billion, more than $7 billion more expensive than the dispatchable
portfolio. Staff calculations are shown in Table No. 3 below.
Table No. 3: 'Dispatchable' Portfolio Cost versus 'VER & BESS' Portfolio Cost
Reqd Capacity Nominal Ruource MW Factor MW
CCCT 975 55.0% 1773 seer 1.507 90.9% 1658 Solar � Wl,:;-d 10-:l 1800 eru· I 1453
Fixed Total Years O&M Variable Capital of ($/kW-O&M Variable Total Cost
($/l(W) Capl,tal Cost Ops month) FixedO&M IS/MWhJ O&M($)1 !SI$ 1,590 $2,818,636,364 20 $ 1.40 $ 595,636,364 $ 3.10 $529,542,000 $ 3,943,814,727 s 991 S l,,642,944,994 io s 2.10 s 835,564,356 s 6.00 $316,831,680 s 2,795.341,031
$ YE... $4,063 150 000 � _ 1.90 I $ 1,516,200,000..J -.1--S . � 5,579,350,000 I
$ s 1 782 $ 3,207,600,000-4 20 : $ 4.10 $1,771,200,000 I $ 1,600 I $2,324,800,000 , 20'5 2.90 S l,0ll.288,000 I $ _s s - 4 4,978,800,000 • $ 3,336,088,000 Note 1: To estimate the fuel costs, the CCCTis assumed to operate 100% of all hours, and the SCCTlo operate 20% of all hours over the 21).year period.
Portfolio Cost
($}
$ 6,739,155,758
$ 13,894,238,000
Staff recognizes that this simplified cost comparison does not account for many factors
such as project feasibility, gas pipeline limitations, gas price risk, and carbon price risk.
STAFF COMMENTS 7 FEBRUARY 15, 2024
Nonetheless, the $7 billion portfolio cost difference calls into question the accuracy of the L TCE
model and the Company's validation process.
4.Possible Sources of Portfolio Bias
Given the large cost difference between a dispatchable portfolio and the VER and BESS
portfolio, Staff examined the LTCE modeling process and found several possible sources of
potential bias. Staff organized these sources into three groups which are discussed in the
following sub-sections:
a.Externally imposed constraints on the L TCE model;
b.Internal cost inputs and operating assumptions used by the model; and
c.Selection and optimization algorithms within the model.
a.External Constraints
Staff believes one of the most significant sources of bias came from the external
constraints included in the model. Some of these constraints assumed completion dates of
transmission lines, which Staff agrees are appropriate. However, others involved preferential
assumptions about dispatchable resources. Among this latter group, are the following two
constraints:
1.Forcing a coal exit or a conversion to gas at a predetermined time; and
11.Forcing exits from gas at a predetermined time.
i.Forcing a Coal Exit or a Conversion to Gas at a Predetermined Time
First, the Company forced the L TCE model to choose between exiting coal and
converting to gas in a predetermined year. The Company did not allow the model to consider
continuation of coal operations, and the Company provided no economic basis for why it forced
the choice nor for the timing of its choice. The Company told the model to select between exit or
conversion for Valmy Coal Unit 2 in 2025, and Bridger Coal Units 3 and 4 in 2029. When asked
for its reasons, the Company stated that the Valmy "exit date is based on alignment with the
plant's co-owner and operator, NV Energy." See Response to Production Request No. 32. The
Company also stated that the Bridger "exit and conversion timing are based on alignment with
STAFF COMMENTS 8 FEBRUARY 15, 2024
the co-owner and operator, PacifiCorp." Id. Staff is not aware of any economic justification for
these decisions.
At a minimum, knowing the cost difference between fueling these plants with coal versus
gas is useful in valuing any tradeoffs in risk between two fueling strategies. Staff believes there
are compelling economic and reliability reasons to continue considering coal generation. Coal
adds resource diversity which protects against price risk. In 2022, the average dispatchable price
of coal was one-half of the price of gas-generated power, and one-third of the price of market­
purchased power1 . Furthermore, coal can be physically stored on site, which hedges against the
supply-chain risk inherent in gas resources.
Staff recommends that the Company remove the coal-exit constraints from the L TCE to
allow the model to make choices based on economics. Furthermore, Staff recommends that the
Company provide justification for these exit-conversion actions in separate case filings.
ii.Farcing an Exit from Gas at a Predetermined Time
Second, the Company constrained the L TCE model to exit the converted-to-gas Bridger
Units 1-4 in 2037. The Company's reason for this is that the "extension to 2037 aligns with the
assumptions made by the co-owner and operator, PacifiCorp." See Response to Production
Request No. 32. The Company also says that this date was based on "an update from the
assumed end of life for these units of 2034 used in the 2021 IRP." Id. emphasis added. Although
Staff agrees that the end of life for a resource is a valid constraint to build into the model, the
Company's response suggests that the end-of-life for the Bridger gas plants is flexible. Staff
recommends that the Company provide justification for setting the end oflife to 2037. Also,
Staff recommends that the Company build an option to extend the resource life at an estimated
cost and then let the model choose whether to exit or extend.
b.Internal Cost Inputs and Operating Assumptions
A second category that may be causing the L TCE model to choose VERs and BESSs
over other fueled dispatchable resources are the internal cost inputs and operating assumptions.
Staff specifically discusses two examples:
1 IPC-E-23-12, Staff Comments, Table No. 4 STAFF COMMENTS 9 FEBRUARY 15, 2024
1.CFs and the Levelized Cost of Capacity ("LCOC"); and
11.Interconnection costs.
i.CFs and the LCOC
The CF assumed for each resource is an important factor used to determine the
contribution of each type of resource. CFs determine the percentage of a resource's nominal
capacity that will be available to meet the peak load ("peak CF") and to produce energy ("energy
CF"). The smaller the CF, the smaller the resource's contribution to peak load and energy
provided to the system. Everything else being equal for two resources, a larger CF will be more
cost-effective than a lower CF. For each resource, its peak CF and energy CF are typically
different values.
First, the CF data was not easy to find in the report. Given the significance of CFs in
determining cost effectiveness, Staff expected the IRP to prominently display the CFs for each
resource. However, the peak CFs were not listed in the IRP and the energy CFs were listed in
the last column ofIRP Table 8.4. At Staff's request, the Company provided its assumed peak
CFs as part of its response to Production Request No. 38. Staff recommends that the Company
clearly display its assumed CFs for both peak and energy in future reports and discuss how it
determined the values.
Second, Staff believes that some of the peak CFs and energy CFs are biased toward
VERs and BESSs and away from fossil fuel resources. The Company proposed that CCCTs be
modeled with an energy CF of 55 percent. IRP at 116, Table 8.4, emphasis added. However, the
Company also stated that "According to the Energy Information Administration ("EIA"), a
typical modem high efficiency Combined Cycle Combustion Turbine ("CCCT") plant capacity
factor is about 65 percent." See Response to Production Request No. 84, emphasis added. This
CF difference of ten percent is significant, especially for the CCCT, which Staff believes is a
feasible baseload resource. The Company also used the same 55 percent CF for SCCTs.
Another example is the utility-scale solar resource, the Company assumed a peak CF of
27.7 percent. National Renewable Energy Laboratory ("NREL") data shows the value in
southwest Idaho should be 25.8 percent2. Furthermore, as hundreds ofMWs of solar are added
2 https://atb.nrel.gov/electricity/2022/utility-scale_pv
STAFF COMMENTS FEBRUARY 15, 2024
to the system, Staff believes the peak CF will diminish. Therefore, it seems more reasonable for
the Company to err conservatively and assume a value on the low side rather than the high side.
Staff recommends that the Company meet with Staff to review the source of each CF
assumption.
Third, Table 8.3 in the IRP presents the LCOC values for each resource based on its
nominal capacity. The table does not adjust for the resource's peak CF. This gives the mistaken
impression that VER and BESS are among the least expensive resources. If the LCOC values
are adjusted by the peak CF, the results show that the lowest values belong to gas resources, and
that wind resources are among the most expensive. To illustrate this point, Staff compiled Table
No. 4 below, which compares the two LCOC values for each resource. The table is sorted by the
CF-adjusted LCOC column.
Table No. 4: Comparison of Nominal LCOC with CF-Adiusted LCOC
Nominal CF-
Adjusted upply-Side Resources LCOC Peak CF LCOC ($/kW/nio.) ($/kW/mo) Clean Peaking Gas -I:Jydrogen Combusti0n Turbine 12 90.9% 13 PeakingGas-·Simole Cycle Combustion Turbine (SCCT) 12 90.9% 13 Baseload Gas -Cembined Cycle Combustion Turbine (cccn 17 90.9% 19 Muhi-Day Storage -Iron Oxide Battery (100 hour) 20 100.0% 20
SolarPV 7 27.7% 26 Danskin 1 Retrofit -SCCT to CCCT Conversion 26 90.9% 29 Mediwn Duration Storage -Li Battery (8 hour) 27 79.2% 34 Long Duration Storage -Pumped Hydro (12 hour) 36 100.00/o 36 Short Duration Storage -Li Battery ( 4 hour) -Grid Distributed 15 38.5% 40 Short Duration Storage -Li Battery ( 4 hour) 17 38.5% 43 Biomass 54 100.00/o 54 Geothermal 51 90.5% 56
Wind-WY 12 20.8% 58 Nuclear -Small Modular Reactor 82 98.1% 83
Wind-ID 14 15.5% 91
Staff recommends that the Company prominently display CFs and the CF-adjusted
LCOCs in future IRPs so readers can better appreciate the tradeoffs between resources.
STAFF COMMENTS 11 FEBRUARY 15, 2024
ii.Interconnection Costs
Interconnection costs are another area where Staff believes the Company's assumptions
are biased toward VER and BESS resources.
When determining the up-front capital cost for each resource, the Company must include
the cost to interconnect that resource to the grid. Factors that can affect this cost include the
nominal power being added, the proximity of the resource to the nearest point of connection, and
the available system capacity at the point of interconnection.
The Company did not include any interconnection cost data in the IRP except for a single
column of normalized ($/kW) data in its Cost Input table. IRP Appendix C at 21. Staff asked
for the full cost estimates for each resource in Production Request No. 36 and for additional
information in Production Request No. 80.
The Company's responses revealed that the Company estimated a 300 MW solar resource
and a 300 MW wind resource sited in Magic Valley would each cost $6.5 million to
interconnect, for a normalized cost of $22 per kilowatt ("kW"). In contrast, a 100 MW retrofit of
an existing gas plant in Magic Valley that is already interconnected would cost $9.4 million for
interconnection upgrades, yielding a normalized cost of $94 per kW. This normalized cost is
more than 400 percent more than for the VER resources. Staff was not convinced by the
Company's explanation for this difference.
The Company also estimated the interconnection cost for a new 300 MW CCCT located
near the existing Langley Gulch plant to be $41.8 million due to the need for transmission
capacity upgrades. In contrast, a new 300 MW wind resource in Wyoming, with the same
transmission needs as the CCCT, would only cost $6.5 million to interconnect. This yields a
normalized cost of $140 per kW for the CCCT, and $22 per kW for the wind resource, a
difference of 636 percent. Table No. 5 displays this information below.
STAFF COMMENTS 12 FEBRUARY 15, 2024
Table No. 5: Comparison of Interconnection Costs
Nominal Cost Capacity Resource Assumed for Cost As.5uiq>ti>n N ores Local h:iercomecti:m Assmq)ti:>n Cost fstiimte Estimte
Cost Estimate (per kW)
Natural Gas 300 Treasure Valley Area Connection to 230-kV Bus Combined Cvc/e Combustion Transmission Line Upgrades Required $41,862,000 $140 Danskin I Retrofit 100 Mountain Home Area Connection to 230-kV Bus SCCT to CCCT Conversion $9,370,000 $94 Solar PV 300 Mountain Home Area Connection to 230-kV Bus
Utilitv-Scale I-Axis Tracking Local Transmission Upgrades Required $6,500,000 $22
Wind -Wyoming 300 Within 5 Mi of Jim Bridger Connection to 345-kV Bus $6,500,000 $22
Wind-Idaho 300 Magic Valley Area Assumes 345-kV Connection $6,500,000 $22
Staff believes that the interconnection cost data is biased toward VER resources and
away from fossil fuel resources. Staff recommends that the Company meet with Staff to review
the interconnection cost estimates and attempt to standardize the assumptions for each resource.
Staff also recommends that the Company display its interconnection assumptions more plainly.
c.The Resource Selection and Optimization Algorithms
A third source of possible bias in the L TCE model is the model's resource selection
algorithm. Staffs concern is that the LTCE model may not select large resources when the
incremental load deficit is small.
For example, if a 100 MW load deficit is forecast for a given year, will the LTCE model
select a 300 MW resource, or will it select a 1 00MW resource, with everything else being equal?
If it will always select the more appropriately sized lO0MW resource, then the size of the
selectable resources can become a source of bias. The Company set the baseload gas CCCT
resource to be 300 MW, and the peaking gas SCCT resource to be 170 MW, but the VER
resources are each set at 100 MW.
Another hypothetical example occurs if the load forecast shows small deficits accruing
over several years. For example, if the load deficit grows by 100 MW in years one, four, and
seven, will the L TCE model select 100 MW resources for each year, or will it see that the
collective deficit in 7 years will be 300 MW and analyze if a 300 MW resource might be more
economical?
Although these are hypothetical examples, Staff notes that most of the IRP portfolio
results show that the L TCE model selected a new gas resource only when a large fossil fuel
resource exited. In other words, the exit of a large fossil fuel resource created a load deficit large
STAFF COMMENTS 13 FEBRUARY 15, 2024
enough to allow the model to select the CCCT resource, and the model then selected it. This
observation also implies that the model may view the CCCT resource as more economical than
VER resources when the CCCT resource is available.
Staff recommends the Company meet with Staff to confirm the algorithm logic and run
tests to observe how the model works.
5.Recommendations
In summary, Staff believes that the IRP's Preferred Portfolio may not be the least-cost
portfolio. A portfolio with a larger share of dispatchable fossil fuel resources appears to be
substantially less expensive. Although Staff is unable to assess many of the risks associated with
a dispatchable resource portfolio, Staff believes dispatchable resources can be more reliable than
VERs and enhance system reliability. However, Staff also recognizes that fueled carbon­
emitting resources also have different risks.
Because the Company uses IRP assumptions and results as part of its justification for
future resource projects, Staff believes that the Company should resolve some of these concerns
through additional analysis and through a supplement to the IRP. Staffs proposed process, and
other related recommendations, are outlined below.
a.Prepare an !RP Supplement
First, Staff recommends that the Company establish a meeting of interested Parties. The
meeting should aim to resolve the questions about various cost inputs and the L TCE model
selection algorithms.
Second, Staff recommends that the Company re-run its most prominent existing scenarios
but with the following changes to the baseline planning assumptions:
1. Modify the forced coal exits to allow for coal continuation or conversion to gas
for Valmy and Bridger; and
11. Justify the Bridger end-of-life in 2037 and modify the LTCE model to allow a
service-life extension option.
Third, Staff recommends that the Company cost test at least one new portfolio that has a
preponderance of dispatchable fossil fuel resources.
STAFF COMMENTS 14 FEBRUARY 15, 2024
Last, Staff recommends that the Company submit a supplement to the existing IRP that
reflects the conclusions of this effort. The supplement should be subject to comments from the
Parties.
b.Provide Separate Justification for the Conversion or Exits of Va/my and Bridger
Staff also recommends that the Company submit separate filings for each proposed
conversion or exit ofValmy and Bridger. These actions carry significant cost and risk
implications for ratepayers, and due diligence is needed to assess the prudence.
c.Implement Changes to Future IRPs
Finally, Staff recommends that the Company make the following changes to future IRPs:
1. Clearly display the assumed peak and energy CFs for each selectable resource.
Also, discuss how the values were determined;
11.Prominently display both nominal LCOCs and CF-adjusted LCOCs for each
selectable resource. Discuss which values are used by the L TCE model; and
111.Plainly display the underlying assumptions and estimates used to determine
interconnection costs for each selectable resource. Standardize the assumptions
unless there is a clear and compelling difference.
II.THE NEAR-TERM ACTION PLAN
The Company requested that the Commission acknowledge the Company's Near-Term
Action Plan. Staff recommends that the Commission refrain from doing so and limit itself to
only acknowledging the overall 2023 IRP.
Staff notes that the Near-Term Action Plan consists of eight action items, some of which
derive from the Preferred Portfolio. Since Staff believes the Preferred Portfolio may not be least­
cost, Action Plan items that are based on the portfolio may not be appropriate. Accordingly,
Staff provides the following comments for each of the Company's proposed actions.
a.Boardman to Hemingway ( B2H' ) Online by Summer 2026
The Company provided an updated September 2023 cost estimate for the planned
transmission project, which was 26 percent higher than the cost estimate provided in the
STAFF COMMENTS 15 FEBRUARY 15, 2024
Company's Certificate of Public Convenience and Necessity ("CPCN") filing in January 2023.3
The increase was largely due to preliminary construction bids. The Preferred Portfolio relied on
the completion ofB2H in July of 2026, with construction estimated to start by the end of 2023.
In November 2023, the Company stated that the B2H construction start was delayed into
the first half of 2024.4 As part of the Company's alternative portfolios, a November 2026 B2H
portfolio was created with an estimated cost of $21 million more than the Preferred Portfolio.
Staff is concerned about the schedule delays and continued cost growth for the B2H project.
b.Continue Exploring the Company's Participation in Southwest Intertie Project -North
The Company provided minimal information about the Southwest Intertie Project-North
("SWIP-N") project within the 2023 IRP. The Company is exploring 500 MW of south-north
capacity from the transmission line. See Response to Production Request No. 18. The
Company's participation in "[t]he SWIP-N project could enable the Company to access the
liquid desert southwest market during winter, while avoiding more costly internal resource builds
to meet the forecasted growth in peak winter energy demands." See Response to Production
Request No. 50. The Company stated it was in active negotiations regarding this project;
therefore, the 2023 IRP did not provide cost assumptions for the Company's involvement with
the project. Id. Additionally, SWIP-N was not included in any of the Company's portfolios.5 In
the 2021 IRP, the Company evaluated the SWIP-N transmission project with an estimated 200
MW capacity with an estimated cost of $133 million with an in-service date of pre-summer
2025.6 Due to lack of transparency of the Company's participation in SWIP-N within the 2023
IRP, Staff recommends the next IRP provide more detailed information about the scope and cost
of the project.
3 See Company's Confidential Attachment 1 -B2H Cost Breakdown.
4 hllp :/lwww.new data.com/clearing up/clearing it up/indu trial-demand-is-drivine-erowth-acro s-idaho-power -territory/article 6d5b6f2e-896 l-l lee-b600-9364c84be9dc.html#:-:text=Con truction%20on%20lhe%20500%2DkV.the%20first%20half0/420of%202024. (last visited January 31, 2024).
5 See Appendix C at 42-71.
6 2021 Integrated Resource Plan at 89.
STAFF COMMENTS 16 FEBRUARY 15, 2024
c.Install Cost Effective Distribution-Connected Storage from 2025 to 2028
The Company did not provide details on this action item within the 2023 IRP. However,
in response to Production Request No. 12, the Company stated, "At this time, Idaho Power does
not have any distribution-connected storage projects planned for 2025 and beyond but is
constantly evaluating various local needs to see if distribution-connected storage could be a cost­
effective solution." Additionally, the Company referenced Table 5.1 in the 2023 IRP of
examples of targeted grid storage with capacities between two to four MW. Staff recommends
that the Company provide additional analysis for any distribution-connected battery projects it is
planning in future filings, such as a general rate case. Staff also recommends that the Company
clarify how it selects between distribution-connected and transmission-connected battery projects
in future IRP filings.
d.Convert Valmy 1 & 2 from Coal to Natural Gas by Summer 2026
The Company selected to convert both units ofValmy 1 and 2 from coal to natural gas by
the Summer of2026 within its Preferred Portfolio. The Company exited Unit 1 as coal in 2019
and plans to exit Unit 2 as coal by the end of 2025. Staff reiterates its recommendation for the
Company to submit separate filings for each proposed conversion or closure ofValmy and
Bridger.
e.Acquire up to 1,425 MW of Combined Wind and Solar in 2026-2028
This action is based on the Preferred Portfolio resource selections, which Staff believes is
insufficiently validated. Staff reiterates its recommendation that the Company provide a
supplemental filing with additional analysis as described in the Preferred Portfolio section.
f.Explore a 5 MW Long-Duration Storage Pilot Project
The Company's Preferred Portfolio includes a total of 1,453 MW of storage, including
100-hour storage. In the Company's response to Production Request No. 11, the Company said
it was still exploring long-duration storage options, such as a 100-hour iron-air battery. The
Company stated that it would seek Commission approval with a formal filing if it decided to
move forward with such a project. Staff agrees with this course of action.
STAFF COMMENTS 17 FEBRUARY 15, 2024
g.Include 14 MW of Western Resource Adequacy Program(' WRAP') CapacityIn Order No. 35920, the Commission ordered the Company to include available information about the WRAP's costs, benefits, as well as lessons learned by the Company in its IRPs. Following the Company's expected binding date into WRAP, 14 MW is included in the Company's Capacity Position starting in 2027. See Response to Production Request No. 19. Staff believes that the Company has complied with Order No. 35920. h.Gateway West ( GWW ') Phase 1 Online by End of2028The Company modeled additional transmission capacity within the Preferred Portfolio. GWW Phase 1 consists of two transmission line segments and one substation. The Company has a one-third permitting interest in Midpoint-Hemingway #2 (Segment 8) and Midpoint-Cedar Hill (Segment 10) 500-kilovolt ("kV") transmission lines. This project also includes the Mayfield 500-kV substation. The Company believes that its participation in this project will enable 1,000MW of incremental resources on the system. Like other similar transmission projects, such as B2H, there are risks of schedule delays and cost growth. Staff is concerned that the assumed availability date may be delayed, which in tum will also affect the availability of renewable energy in the Preferred Portfolio. III.THE LOAD FORECASTThe Company builds its load forecast with a probability range. The 50th percentile load forecast ("P50") represents the most probable load. The 70th percentile load ("P70") has a greater magnitude than the P50 load, and has a 70 percent chance the actual load will be lower, and a 30 percent chance the actual load will be higher. The Company used a P50 load forecast and a more stringent reliability target than the industry standard in its 2021 IRP analyses. For the 2023 IRP, the Company adopted the industry standard reliability target, but used a P70 load forecast. Staff identified two issues as a result of the Company's decisions: (1) a lack of proper justification for using P70 load forecast for reliability purposes; and (2) potential inflated expected energy costs for rates and avoided costs by using the higher load forecast. STAFF COMMENTS 18 FEBRUARY 15, 2024
1.Justification for the P70 Load Forecast
Staff believes that the Company failed to provide sufficient evidence that the P70 load
forecast was the appropriate choice. Staff recommends that the Company meet with Staff during
the next IRP cycle, to discuss how to provide reasonable and adequate evidence in its next IRP to
determine and verify an anticipated peak load forecast used to ensure sufficient resources for
purposes of reliability.
The Company used a P70 peak load forecast to determine the amount of resources needed
to meet a 0.1 event-days per year (" 1-in-10") Loss of Load Expectation ("LOLE") reliability
target, which is considered an industry standard. This was a change from using a P50 peak load
forecast and a 0.05 event-days per year ("1-in-20") LOLE threshold from the 2021 IRP7. In that
case, Staff stated that "a reliability target should be determined independent of the Company's
loads and resources, and instead should be a policy decision based on the tolerance of customers
and the public to costs, risks, and other impacts related to electricity outages." Case No. IPC-E-
21-43, Staff Comments at 9. In this case, when asked how and why the Company determined
that the P70 peak load forecast was the right level to use for its planning case, the Company
stated that it was selected in combination with 1-in-10 LOLE threshold, because the annual
capacity position determined under this assumption was similar to that determined under the
assumption of a P50 peak load forecast and a 1-in-20 LOLE threshold from the 2021 IRP. See
Response to Staff Production Request No. 21.
Although using a higher percentile of the peak load forecast is one way to ensure enough
capacity margin is included in its portfolios for purposes of meeting its reliability target, Staff
does not believe that using a capacity position as a reference point that was based on an inflated
LOLE target is proper justification for choosing the proper percentile ofload. Staff recommends
the Company meet with Staff early in the next IRP cycle to discuss methods to determine and
verify the percentile of load that is appropriate to meet its reliability target in the next IRP.
2.Cost Implications from using the P70 Load Forecast
While analyzing the 2023 IRP, Staff realized that the Company's use of the P70 load
forecast had the potential to inflate the variable energy costs used to value DSM benefits and
customer rates that utilize outputs from the IRP. Although a P70 forecast may be appropriate for
7 A l-in-20 LOLE is more stringent than a l-in-10 LOLE.
STAFF COMMENTS 19 FEBRUARY 15, 2024
sizing capacity needs, as discussed above, because the magnitude of the P70 was greater than the
P50, the modeling algorithms require higher-than-average energy costs. This yields higher costs
for every portfolio and could potentially drive the AURORA-generated market prices higher,
which flow into various customer rates and the cost-effectiveness tests used in the Company's
DSM programs.
Staff recommends that for future IRPs, if the Company determines its Preferred Portfolio
by using something other than the P50 load forecast, it should still use the P50 loads in its
dispatch model to calculate IRP portfolio energy costs and marginal avoided costs. Staff also
recommends that for tariffs that are affected by avoided cost calculations (i.e. Lamb Weston,
Brisbie, Schedule 20), separate dockets should be filed, and Staff will analyze the Company's
cost bases in those dockets.
IV.THE DEMAND-SIDE MANAGEMENT PROGRAM
The DSM program is fundamentally connected to the IRP. Staff discusses changes to the
DSM program and avoided cost implications in the two following sub-sections.
1.Program Planning
In meetings with Staff, and at its August Energy Efficiency Advisory Group ("EEAG")
meeting, the Company implemented changes in this IRP for its DSM program planning. The
Company's previous policy was to plan and evaluate its DSM programs using avoided cost
averages provided by the most recently acknowledged IRP. After discussions, the Company is
now changing its policy to use avoided costs provided by the most recently filed IRP. Staff
believes that this change will allow DSM programs to reflect the Company's system and
planning process more closely.
Under the previous policy, avoided costs from the most recent IRP cannot be used to plan
DSM programs because the IRP is not typically acknowledged until the following year. Instead,
the Company must rely on avoided cost data that is two years out of date to plan a program
occurring the following year, creating a three-year lag.
Under the updated policy, changes in avoided costs will be recognized in a more timely
manner. See Response to Production Request No. 52. By using the most recently filed avoided
costs, DSM program planning will more closely reflect the most current data.
STAFF COMMENTS 20 FEBRUARY 15, 2024
2.A voided Costs
Staff is concerned that the 2023 IRP avoided costs are based on the Preferred Portfolio
and the P70 load forecast, and therefore the avoided costs may be incorrect.
a.Preferred Portfolio Impact
As described in the Preferred Portfolio section, Staff believes that the Company's cost
input assumptions may be biased toward VERs and away from fossil fuel resources.
Adjustments may be necessary for the least-cost, dispatchable, selectable resource ( currently the
SCCT), which would affect the avoided cost of capacity. Similarly, a different Preferred
Portfolio could change the avoided cost of energy.
Staff recommends that the Company not use the 2023 IRP DSM avoided costs included
in this filing and reassess the avoided costs as part of the recommended supplemental filing. For
this IRP cycle, the Company should consider the supplemental IRP filing "the most recently filed
IRP". If the Company has not filed a supplemental IRP by the time the Company either
evaluates its 2024 DSM program or conducts 2025 DSM program planning, the Company should
use the DSM avoided costs from its 2021 IRP.
b.P70 Impact
As described in the P70 load forecast section, the P70 load forecast skews the DSM
avoided costs. In its supplemental response to Production Request No. 67, the Company
provided a comparative analysis of the DSM avoided cost averages based on the P70 and P50
forecasts. Staff reviewed the analysis and agreed with the Company's conclusion that, while the
P70-based avoided costs are higher, the increase is "approximately 1 percent ... but actual
variance changes by year and time period." See Supplemental Response to Production Request
No. 67 at 3. Staff recommends that the Company use the P50 load when determining avoided
costs in the next IRP.
V.SEASONS AND HOURS OF HIGHEST RISK
Through the proceedings of Case No. IPC-E-23-11 and IPC-E-23-14, an increased
emphasis was placed on how the Company determines the highest risk seasons and hours. The
STAFF COMMENTS 21 FEBRUARY 15, 2024
highest risk seasons and hours, as determined in the IRP, are used as a basis for the Export Credit
Rate, Time-of-Use rates, the dispatch parameters of DR programs, and the load shapes of EE
benefits. In Order No. 36048, the Commission directed that any updates to the summer season
or the hours of highest risk be considered in a separate docket or in a general rate case. Order
No. 36048 at 6. In the sections below, Staff conducted a thorough review of the methodologies
and results of the Company's seasons of highest risk and hours of highest risk. The Company's
modeling shows a summer season from June 1 -September 15, a winter season from Nov 1 -
February 28/29, and hours as detailed in Table No. 6.
Table No. 6: Comparison of Summer and Winter Hours of Highest Risk
Season 2021 IRP Houn 2023 IRP Hoon Summer High-Risk 4pm-I !pm 8pm-10pm Smrnrer Medium-Risk 12pm-4pm/ llpm-12pm 6pm -8pm/ 11 pm -12pm Winter High-Risk NIA 7am-I lam/6pm-9pm Winter Medium-Risk 6am -9am / 5pm -8pm I 8am -11 pm 11 am - I pm I 5pm -6pm / 9pm - I Opm
In general, the methods supporting the seasons and hours of highest risk are reasonable.
However, Staff does have concerns with certain assumptions and practices and does not
recommend updating the seasons or hours of highest risk in conjunction with this report.
1.Seasons of Highest Risk
Staff analysis of the Company's method for determining seasons of highest risk suggests
that, in general, the approach is reasonable. However, Staff is concerned with a decline of risk
hours in the months of June, September, and February and the large percentage of total risk hours
catching lower risk hours in these months. The Company describes its method as grouping the
top 90 percent of total risk hours by the day and month in which they occur. Appendix C at 92;
also see Response to Production Request No. 5. Staff was able to verify the calculations using
data provided in the Company's response to Production Request No. 3. Staff believes that while
the top 90 percent of total risk threshold does capture the seasons of highest risk, the large
percentage may contribute to an unfocused perspective of system risk. This is supported by the
Company's response to Production Request No. 74, Attachment 1, which shows sporadic risk
hours in October and in January, depending on the test year. Notably, this analysis does not
include any risk hours in February. Finally, the Company states that it did not conduct analysis
STAFF COMMENTS 22 FEBRUARY 15, 2024
of other top percentages of total risk thresholds. See Response to Production Request No. 69. In
any future cases that use this method of analysis, and in the Company's next IRP, Staff
recommends the Company provide analysis that supports the percentage of total risk hours
threshold used to select seasons of highest risk. The selected percentage should balance
capturing the critical risk seasons while providing a focused perspective on when those seasons
occur. Additionally, the analysis should evaluate why other percentages ( e.g., 70 percent or 80
percent) are or are not appropriate for determining the season of highest risk.
2.Hours of Highest Risk
Staff analysis suggests that the Company's method for determining hours of highest risk
is generally reasonable, but the analysis should include BESS resources. The Company
describes its method for determining the hours of highest risk as grouping the top 50 percent of
total risk hours for each month in a season by the hour in which they occur. Appendix C at 93;
also see Response to Production Request No. 7. Additionally, in its response to IPC-E-23-11
Production Request No. 252, the Company states that it excludes BESS and DR resources
because of their limited dispatchability and uses this analysis to inform TOU rates. Staff
disagrees with the Company's practice of excluding BESS and DR resources from the analysis.
Additionally, Staff believes that the top 50 percent of total risk hours in a month may not provide
a clear perspective on the hours of highest risk.
The Company's preferred portfolio shows the system currently has 304 MW of BESS
resources with an additional 323 MW to be added by 2025. IRP at 6, 51, and 52. The LTCE
model selects these resources to address capacity and reliability positions. Additionally, unlike a
traditional generation system, BESS resources represent a load to the Company's system greater
than their nameplate capacity due to round-trip efficiency losses. This load from charging
batteries contributes to risk and should be accounted for when modeling hours of highest risk.
Staff believes that, while excluding BESS and DR resources provides valuable insight, excluding
these resources does not accurately represent risk to the Company's system and devalues solar
resources.
Staff and Company analysis on hours of highest risk suggests that by excluding BESS
and DR resources, the high-risk hours are concentrated in later hours when solar systems are no
longer producing. Including BESS and DR resources reduces and spreads the risk across a much
STAFF COMMENTS 23 FEBRUARY 15, 2024
larger timeframe consistent with current high-risk hours. If the Company were to file to update
its highest risk hours based on the timing presented in the IRP, customer-owned generation
systems would be adversely impacted as the majority of exporting systems are solar and are not
granted the same rate stability as Public Utility Regulatory Policies Act ("PURP A") systems or
Company-owned systems.
Staff believes that while the top 50 percent of total risk threshold captures the seasons of
highest risk, the large percentage may contribute to an unfocused perspective of system risk.
This is supported by the Company's analysis in its response to Production Request No. 77,
Attachment 1. For the summer season, the analysis shows discontinuous occurrences of highest
risk between 3 am and 8 am. For the winter season, the analysis shows occurrences of highest
risk hours during all hours of the day. Similar to the seasons of highest risk, the Company states
that it did not conduct analysis of alternate risk thresholds in its response to Production Request
No. 71. Staff recommends that the Company maintain its current hours of highest risk. In any
future case that uses this analysis and, in the Company's next IRP, Staff recommends the
Company provide analysis that supports the percentage of total risk hours threshold used to
select hours of highest risk. The selected percentage should balance capturing the critical risk
hours while providing a focused perspective on when those hours occur within a given season.
Additionally, the analysis should evaluate why other percentages are or are not appropriate for
determining the hours of highest risk.
VI.PURP A AND OTHER PLANNING ASSUMPTIONS
Staff recommends that the Company adjust its PURP A assumptions in future IRPs. Also
Staff provides comments regarding other planning assumptions.
1.PURPA
Staff identified the following issues associated with forecasted PURP A development in
the 2023 IRP.
a.The Company's justification for excluding forecasted PURP A projects in its base
planning conditions is not reasonable;
b.The Company did not use the most recent data in its PURP A trend analysis; and
STAFF COMMENTS 24 FEBRUARY 15, 2024
c.The results of the PURPA trend analysis were applied in New Forecasted PURPAScenario only after the Action Plan window in 2029.Staff recommends that the Company conduct a PURP A trend analysis that includes the most recent data and apply the analysis results in the base planning conditions starting the first year of the planning horizon in the next IRP. a.New PURP A Resources Should Not Be Excluded from BaselineFirst, the Company did not include any forecasted PURP A projects in its base planning conditions in the 2023 IRP, because there has not been any new !RP-based PURPA projects in Idaho over the past five years. 2023 IRP at 128; also see Response to Staff Production Request No. 27. Staff believes this justification is not reasonable, because the Company should not focus only on IRP-based PURP A projects in Idaho without considering Surrogate A voided Resource­based ("SAR-based") PURP A projects in Idaho and PURP A projects in Oregon. For example, since 2018, there have been three new SAR-based projects in Idaho and five new PURPA projects in Oregon. See Response to Staff Production Request No. 27 (b) and (c). b.Use the Most Recent PURP A DataSecond, the Company conducted a 10-year PURPA trend analysis from 2012 through 2021. IRP at 128. However, the most recent data from 2022 and 2023 were not used in the analysis. Staff believes this data should not be excluded in the analysis. Staff recommends that the Company include the most recent data in future analyses. c.The New Forecasted PURPA ScenarioThird, the results of the PURPA analysis were applied in the New Forecasted PURPA Scenario only after the Action Plan window in 2029. The 10-year analysis showed an average of 57 MW of new PURPA projects each year. Id. at 128. However, this trend was only applied after the Action Plan window. Staff believes that this defeats the purpose of exploring different future scenarios, which is to "compare the resources selected in the Preferred Portfolio, developed under planning constraints and conditions, to resources selected in other possible scenarios." Id. at 126. The IRP further states that "[t]his is especially useful for near-term resources. The goal of the comparisons is to understand how resources would need to shift if STAFF COMMENTS 25 FEBRUARY 15, 2024
various scenarios materialized." Id. at 126. If a similar PURP A scenario is run in future IRPs,
Staff recommends that PURP A resources be brought on line starting the first year of the planning
horizon.
2.Planning Assumptions
Staff adds the following comments about other planning assumptions used in the 2023
IRP.
a.BESS Degradation
While reviewing prudence of BESS capital investments in Case No. IPC-E-23-11, Staff
did not believe the Company included the full cost of a BESS over its lifecycle in comparison
with other resource alternatives due to battery degradation. Staff could not determine if this
oversight was addressed in the 2023 IRP. To ensure BESS resources are evaluated on an
equivalent basis with other resource alternatives, Staff recommends the co·mpany include
degradation incremental costs and be able to reflect them explicitly in its cost analysis in its
supplemental filing, future IRPs, and in future prudence reviews.
b.Electric Vehicle ("EV'') Adoption
The Company provided minimal information on the planning assumption used for EV
adoption within the 20-year planning horizon. The Company assumed that EV adoption will
have a compound annual growth rate of 5.6 percent, an overall twenty-fold increase from 2022 to
20438. Staff believes this assumption is reasonable based on the Idaho forecast data from
Moody's Analytics and trend growth established using Department of Energy's Annual Energy
Outlook forecast applied to Idaho's EV share of total vehicle registrations.
c.Customer Generation Adoption
The Company also provided minimal information on the planning assumption used for
customer generation adoption. For the Residential Class, the Company forecasted a rapid growth
trend until 2033, then a decreased growth trend until end of 2043. For the Irrigation Class, the
8 See the Attachment 1 in the Company's response to PR 16.
STAFF COMMENTS 26 FEBRUARY 15, 2024
Company forecasted a rapid growth trend until 2029, then forecasted a decreased growth trend
until end of 2043. The Company used terminal saturation forecasts for the Residential class until
2034 and the Irrigation Class until 2029, then switched to month-over-month growth due to the
Company determining the terminal saturation growth trend exceeded reasonable growth. See
Company's Response to Production Request No. 47. For the Commercial Class, the Company
forecasted a declining growth trend year-over-year. The Company did not forecast additional
customer generation adoption for the Industrial Class due to current limited participation. Staff
believes the assumption for the initial rapid growth trend is reasonable based on current available
incentives. Additionally, Staff believes the leveling of the adoption rate in later years of the
planning horizon is reasonable as it reflects customer generation saturation in the classes. Staff
recommends the Company monitor the Residential and Irrigation Class adoption rates as a result
of changes to the Company's Export Credit Rate starting in 2024 and adjust the IRP forecast as
necessary based on actual adoption rates.
d.Transmission Capacity
Within the IRP, the Company modeled increased transmission capacity within its
Preferred Portfolio. Staff has the following comments on the assumed transmission capacity
availability.
i.B2H
The Company modeled the transmission capacity of750 MW west-to-east and 182 MW
east-to-west in the base case portfolio assumptions. See Response to Production Request No. 51.
Staff believes this assumption is reasonable as B2H has been permitted, contracted, and
construction is soon to begin.
ii.GWW Phases
The Company included the three phases of GWW to support resource additions in its
Preferred Portfolio. The Company assumed GWW Phase 1 capacity in 2029, GWW Phase 2
capacity in 2031, and GWW Phase 3 capacity in 2040. The Company assumes both Phase 1 and
Phase 2 will each provide 667 MW of capacity, while enabling 1,000 MW of incremental
resources on the system. The Company anticipates it will own all capacity in Phase 3, which
STAFF COMMENTS 27 FEBRUARY 15, 2024
will enable 2,000 MW of incremental resources. Although the Company modeled the
transmission capacity, the Company does not have formalized contracts with PacifiCorp for
construction and capacity allocation of the GWW phases. Staff reiterates its concern for likely
transmission project construction delays, underestimation or inflation of construction costs, and
availability of capacity.
iii.Capacity Benefit Margin ("CBM'')
The Company reduced the planning capacity of an original 330 MW energy emergency
transmission to 200 MW in summer and to O MW in the winter. The Company cites that the
planning reduction is due to continued transmission market limitations in both seasons.
However, the Company will continue to operationally set aside 330 MW of transmission
capacity for CBM. IRP at 82. Staff believes it is reasonable to lower the CBM capacity from the
330 MW level due to the transmission market limitations in the summer and the wholesale
energy market depth in the winter.
VII.COMPLIANCE WITH PRIOR ORDERS AND REVIEW OF 2021
RECOMMENDATIONS
Lastly, Staff reviewed the 2023 IRP for its compliance with Commission Order No.
35837 from Case No. IPC-E-23-17, and for its alignment with Staff recommendations from the
2021 IRP.
1.Compliance with Order 35837
To ensure on-time submittal of the 2025 IRP, Order No. 35837 directed the Company to
submit a plan and schedule in the 2023 IRP filing to ensure timely delivery of the 2025 IRP.
Staff concurs that the Company complied with the Order. The 2023 IRP proposes a reasonable
timeline for the 2025 IRP, with a final filing date of June 2025. The schedule reflects that the
Company will collect model input data, hold 8 to 12 IRP Action Committee meetings, conduct a
public review, and then file the IRP.
Staff notes that the 2025 IRP schedule could be in jeopardy due to the supplemental 2023
filing recommended herein. Staff recommends the Company plan accordingly to ensure that it
files the 2025 IRP on time.
STAFF COMMENTS 28 FEBRUARY 15, 2024
2.Review of Staffs 2021 IRP Recommendations
Staff reviewed the 2023 IRP for its alignment with Staffs 2021 IRP recommendations.
a.Extreme Weather LOLE
In the 2021 IRP case, Staff recommended the use of a 1-in-10 LOLE in the 2023 IRP
analysis instead of a 1-in-20 LOLE. Staff believed that the LOLE should be set as a matter of
public policy, and the Company should account for weather events and variability elsewhere in
the model's input assumptions. The l-in-10 LOLE threshold was more consistent with the
industry standard and the Company's historical practices.
Staff concurs that the 2023 IRP analysis used the l-in-10 LOLE threshold.
b.Market Access
Staff recommended that the Company only include market access backed by firm
transmission reservations in its load and resource balance for the 2023 IRP. Staff believed that
relying on market access without firm transmission exposes the Company to reliability risks.
Staff concurs that the 2023 IRP adhered to this recommendation. However, Staff notes
that CBM is included in the Load and Resource Balance ("L&RB"), but it does not have any
firm third-party reservation. Staff discussed this in detail in Staff Comments in Case No. IPC-E-
23-27. In the next IRP filing, Staff recommends that the Company provide justification for why
the CBM should be included in the L&RB.
c.Model Validation and Verification
Staff recommended a comprehensive analysis plan to verify and validate the models used
in the 2023 IRP analysis. Staffs request was for the Company to describe the purpose of the
test, how the test was conducted, and the results of the test.
Staff concurs that the Company generally followed the requested validation and
verification process. However, Staff does not believe that the verification and validation tests
adequately tested the model output, as explained in the Preferred Portfolio section.
STAFF COMMENTS 29 FEBRUARY 15, 2024
d.Evaluating Risks and Inaccuracies
Staff recommended that the Company evaluate the risks and inaccuracies from
employing a single benchmark year (2023) to determine the LOLE-based Planning Reserve
Margin ("PRM"). Staff was concerned about the accuracy of the reliability model used to verify
the portfolios by using a static PRM value over the entire planning period.
Staff concurs with Company's implementation of LOLE-based seasonal PRM
calculations performed at different points along the planning horizon for the AURORA LTCE
model. The Company provided the AURORA model with independent summer and winter PRM
values to account for seasonal fluctuation. In addition, the Company updated both PRM values
in select years to capture the effects of significant changes in the resource buildout.
e.Development of a Bridger Exit Agreement
Staff recommended that the Company develop a Bridger exit agreement with PacifiCorp
that would determine the potential cost of extending or exiting operations. The exit costs could
then be used in the 2023 IRP analysis to accurately assess the costs and benefits of different coal
exit dates.
At the time of the 2023 IRP filing, Staff believes that the Company had not developed an
exit agreement. However, Staff has indications that the Company is working with PacifiCorp on
the matter. Staff reiterates its recommendation (from the Preferred Portfolio section) that the
Company provide separate filings for each proposed conversion or closure ofValmy and
Bridger.
STAFF RECOMMENDATION
Staff recommends that the Commission acknowledge the 2023 IRP. In addition, Staff
has identified several other recommendations as outlined below.
1.Staff recommends that the Commission order the Company to submit a supplemental
filing for the 2023 IRP that addresses the Preferred Portfolio concerns. This process
should include the following:
a.Establish a meeting of interested Parties to resolve concerns about model cost
inputs and the selection algorithms. Include BESS degradation incremental costs;
STAFF COMMENTS 30 FEBRUARY 15, 2024
b.Re-run the most prominent existing scenarios with recommended changes to the
baseline planning assumptions;
1. Modify the forced coal exits to allow the model to choose between coal
continuation, exit, or conversion to gas, for Valmy and Bridger;
11.Eliminate the forced exit from Bridger in 203 7. If the Company justifies an end­
of-life closure, allow the model to choose between an exit or a service-life
extension;
c.Cost test at least one new portfolio that has a preponderance of dispatchable fossil
fuel resources;
d.Confirm the 2023 DSM avoided cost data; and
e.Allow for comments from Parties on the Supplement.
2.Staff recommends that the Commission order the Company to submit separate filings
for approval of each proposed conversion or exit of Valmy and Bridger.
3.Staff recommends the following changes to future IRPs:
a.Display the assumed peak and energy CFs for each selectable resource;
b.Display both nominal LCOCs and CF-adjusted LCOCs for each resource;
c.Display the underlying estimates used to determine interconnection costs;
d.Provide more detailed information about the scope and cost of the SWIP-N project;
e.Clarify how the Company selects between distribution-connected and transmission­
connected battery projects;
f.Meet with Staff to determine the method for selecting the load probability profile;
g.Use the P50 in the dispatch model to calculate IRP portfolio costs and IRP marginal
avoided costs;
h.Include BESS and DR resources in analysis of seasons and hours of highest risk;
1.Provide analysis that supports the percentage of total risk hours threshold used to
select seasons of highest risk;
J.Provide analysis that supports the percentage of total risk hours threshold used to
select hours of highest risk;
STAFF COMMENTS 31 FEBRUARY 15, 2024
k.Conduct a PURP A trend analysis that includes the most recent data and apply theanalysis results in the base planning conditions starting the first year of the planninghorizon in the next IRP; and1.Include BESS degradation incremental costs.m.Justify why the L&RB should include the CBM.Respectfully submitted this 15th day of February 2024. Chris Burdin Deputy Attorney General Technical Staff: Matt Suess Dylan Moriarty Jason Talford Kimberly Loskot Yao Yin l:\Utility\UMISC\COMMENTS\IPC-E-23-23 _ Comments.docx STAFF COMMENTS 32 FEBRUARY 15, 2024
·CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 15TH DAY OF FEBRUARY 2024, SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF TO IDAHO POWER COMP ANY, IN CASE NO. IPC-E-23-23, BY E-MAILING A COPY
THEREOF, TO THE FOLLOWING:
LISA D NORDSTROM
MEGAN GOICOECHEA ALLEN
IDAHO POWER COMPANY PO BOX70 BOISE ID 83707-0070 E-MAIL: [e-mail]@idahopower.com
[e-mail]
TIMOTHY E TATUM
ALISON WILLIAMS
IDAHO POWER COMP ANY PO BOX70 BOISE ID 83707-0070 E-MAIL: [e-mail]
[e-mail]
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SECRETARY
CERTIFICATE OF SERVICE