20220602Comments.pdf

DAYN HARDIE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 9917
't ,: tti --_ i-;i i: l3
Street Address for Express Mail:
1 1331 W CHINDEN BLVD, BLDG 8, SUITE 2OI-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S 2O2I INTEGRATED
RESOURCE PLAN
CASE NO. IPC.E-2I-43
COMMENTS OF THE
COMMISSION STAFF
STAFF OF the Idaho Public Utilities Commission ("Staff'), by and through its Attomey
of record, Dayn Hardie, Deputy Attorney General, submits the following comments.
BACKGROUND
The Integrated Resource Plan ("IRP") is Idaho Power's (the "Company") status report
explaining how the Company plans to adequately and reliably serve customers over the next 20
years. The Commission requires the Company to file an IRP every two years, and to allow the
public to participate and comment as the IRP is being developed. See Order Nos. 22299 and
25260.
On December 30, 2021, the Company filed its 2021 IRP requesting Commission
acknowledgement. By acknowledging the IRP, the Commission is acknowledging the
Company's ongoing planning process, not the conclusions or results reached through that
process. Order No. 33441.
Further, the Commission has stated it
STAFF COMMENTS I JI-]NE 2,2022
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does not approve the IRP or any resource acquisitions referenced in it, endorse any
particular element in it, opine on Idaho Power's prudence in selecting the IRP's preferred
resource portfolio, or allow or approve any form of cost recovery. The appropriate place
to determine the prudency of the IRP or Idaho Power's decision to follow or not follow it,
and the validation of predicted performance under the IRP, is a general rate case or other
proceeding where the issue is noticed.
Order No. 34959
The Commission required that a utility's IRP explain its current load/resource position, its
expected responses to possible future events, and the role of conservation in its explanations and
expectations. The IRP should also discuss:
any flexibilities and analyses considered during comprehensive resource planning, such
as: (1) examination of load forecast uncertainties; (2) effects of known or potential
changes to existing resources; (3) consideration of demand- and supply-side resource
options; and (4) contingencies for upgrading, optioning and acquiring resources at
optimum times (considering cost, availability, lead time, reliability, risk, etc.) as future
events unfold.
Order No.22299
The tRP should separately address:
o "Existing resource stack" by identiffing all existing power supply resources;
o "Load forecast" by discussing expected2O-year load growth scenarios for retail markets
and for the federal wholesale market including "requirements" customers, firm sales, and
economy (spot) sales. This section should be a short synopsis of the utility's present load
condition, expectations, and level ofconfidence; and
. "Additional resource menu" by describing the utility's plan for meeting all potential
jurisdictional load over the 2}-year planning period, with references to expected costs,
reliability, and risks inherent in the range of credible future scenarios.
rd.
The Company's primary goals of its *2021 IRP are to: (l) identify sufficient resources to
reliably serve the growing demand for energy within Idaho Power's service area throughout the
2}-year planning period (2022-2041); (2) ensure the selected resource portfolio ("preferred
portfolio") balances cost and risk, while including environmental considerations; (3) give
balanced treatment to both supply-side resources and demand-side measures; and (a) involve the
public in the planning process in a meaningful way." Application at 3.
2STAFF COMMENTS JUNE 2,2022
Based on the Company's preferred portfolio, the IRP contains a short-term action plan that
would: (1) add 120 megawatts ("MW") of solar photovoltaic ("PV") capacity in2022; (2) convert
Jim Bridger units 1 and 2 to natural gas by sufllmer 2024; (3) seek acquisition of significant
resources to meet energy and capacity needs in2023 through 2027; (4) exit Jim Bridger unit 3 and
Valmy unit 2 by year-end 2025; and (5) energize Boardman to Hemingway ("82H") in2026.
STAFF RE,YIEW
Staff recommends acknowledgment of the Company's 2021 IRP while recognizing
substantial efforts by the Company to improve its methods and how it conducted its public
engagement process. Compared to the Second Amended 2019IRP (*2019IRP"), Staff believes
the Company's efforts have improved the credibility of the 2021 IRP results.
Staff is encouraged by the progress the Company has made in evaluating its own process
and the number of improvements implemented in the 2021 IRP. Key improvements
implemented in the 2021 IRP include:
l. Implementation of a reliability model integrated with the Company's overall IRP
methodology that builds portfolios based on a Loss of Load Expectation
("LOLE") target and provides closed-loop verification that portfolios meet the
target over the 21-year planning horizon;
2. Determination of the peak-serving capability or Effective Load Carrying
Capability ("ELCC") of renewable and time-limited resources using probabilistic
best practice processes and based on historical output data;
3. The ability of the Long-Term Capacity Expansion ("LTCE") software to cost
optimize the mix of resources within the Company's system;
4. Methods to veriff that the Company's models operated as expected and validated
that the model produced cost optimized portfolios for the Company's system; and
5. Modifications to the Company's Demand Response ("DR") programs as a result
of its reliability evaluation processes and identification of the hours when capacity
needs are the greatest.
In addition to improvements that the Company implemented in the 2021 tRP, Staff
identified additional concerns it believes need to be addressed in the 2023 IRP (Items l-7) and in
its current action plan (ltems 6 and 7). Staff recommends:
JSTAFF COMMENTS JUNE 2,2022
l. lncorporating acceleration of extreme weather events and variability of water
availability through its load and resource input assumptions, rather than
compensating by changing the LOLE reliability target;
2. Only including market access backed by firm transmission reservations in the
Load and Resource Balance ("L&R");
3. Evaluating the risks and inaccuracies from employing a single benchmark year
(2023) to determine the LOLE-based Planning Reserve Margin ("PRM");
4. Providing a comprehensive Quality Assurance ("QA") plan to veriff and validate
its models by describing the purpose of each test, how the test was conducted,
and the result;
5. Including a study of the costs and benefits of implementing a flexible resource
strategy;
6. Developing a Bridger exit agreement with PacifiCorp that determines potential
costs of extending or exiting operations early like the exit agreement developed
for the closure of Valmy and incorporate those costs into its coal plant exit costs
to properly value different exit dates in the Company's portfolios;
7 . Not including acquisition of specific types of resources in its action plan where a
broadly-scoped RFP is appropriate.
The improvements in this IRP have sharpened focus on the shortcomings in the 2019 IRP
and the impacts it is having on the Company's immediate need for resource procurements and
the need to find ways to acquire resources inside of resource acquisition lead time. Evidence of
these shortcoming include:
l. Shifting the first capacity deficit date from 2029 as reflected in the 2019IRP to
2023 inthe202l IRP, with even earlier deficits occurring in202I and2022 that
cannot be addressed due to resource acquisition lead times;
2. A delay in the results of the 2019 IRP by 15 months and the need for two major
2019 IRP amendments due to less than optimal results;
4STAFF COMMENTS JUNE 2,2022
3. The Company requesting a waiver from its obligations to use Oregon Public
Utilities Commission ("OPUC") Resource Procurement Rules adopted in Order
No. 32745, listing time constraints as one of the primary justifications;l
4. The need to obtain firm transmission contracts to alleviate potential shortages to
obtain market access to meet potential shortages starting in202l;
5. lssuance of a2021Request for Proposal ("RFP") for immediate need of capacity
starting in the summer of 2023 and the inability to obtain a rich pool of
competitive bids that qualiff due to timing. See Case No. IPC-E-22-13;'
6. The possible issuance of a2022 all-source RFP for capacity needs starting in the
summer of 2024. See 2021IRP at 172.
The above issues serve as a reminder of the importance of the IRP. Staff believes that
when the Company reacts to acquire resources inside of resource acquisition lead times, the
number of resource options and alternatives become limited resulting in increased cost to
customers and potential for reliability issues.
The Company stated the immediate need for resources was due to "several dynamic and
evolving factors" including: (l) increased load growth in the Company's service tenitory; and
(2) changes in the Company's assumptions regarding market purchases due to lack of availability
of 3'd party transmission.2 See Application, Case No. IPC-E-21-41 at2. Increased extreme
weather events occurring in the Pacific Northwest and uncertainty in year-to-year water
availability affecting hydro generation have also led to the need for immediate resources. See
2021 IRP - Appendix C at99. It is these types of dynamic factors and risks that the IRP is
intended to identiff to prevent the resource acquisition lead-time issues that the Company is
currently facing.
As a result, Staff s engagement during the 2021 IRP development cycle and its review of
the final report was heavily focused on improvements to the Company's IRP processes, and the
need to ensure system reliability. Stafls review for the 2021 IRP includes an analysis of the
Company's methods to
I The case (IPC-E-21-41) was later withdrawn opting instead to file and quali$ for an exemption with the OPUC to
meet near term capacity shortfalls and filing for a Certificate of Public Convenience and Necessity ("CPCN") in
Case No. IPC-E-22-13.
2 The Company also stated changes in how the Company modeled reliability of its system that have been
implemented in this IRP as an additional reason. The changes affected the amount of contribution of its resources,
including its current Demand Response programs and how it identifies the hours critical for the need of additional
capacity.
STAFF COMMENTS 5 JI.INE 2,2022
I.
il.
il.
IV.
V.
VI.
vII.
VI[.
Measure and assure reliability of the Company's system;
Identifr deficits through its L&R;
Develop resource portfolios and select the least cost least risk preferred portfolio;
Determine the Company's natural gas forecast;
Veriff assumptions for existing and future supply-side resources;
Veriff assumptions for existing and future demand-side resources;
Include public participation in the Company's IRP process; and
Develop the Company's Action PIan.
I. Assurance of Reliability
The Company improved how it measures and ensures the reliability of its resource
portfolios and how it determines the capacity contribution of current and future resources within
its system. Reliability is the primary constraint that the Company's resource plan must meet.
Staff believes that the Company has improved the credibility of the timing and amount of future
resource deficits reflected in its L&R and the ability of future resource portfolios to resolve
future resource deficits. However, Staff has identified two concerns that the Company should
address in the 2023 IRP:
l. The appropriateness of changing the LOLE reliability target to compensate for more
frequent extreme weather events and uncertainty in year-to-year water availability
affecting hydro generation availability;
2. Risks and inaccuracies caused by using a single benchmark year (2023) to determine
the LOLE-based PRM.
A. Improvements to Assure Portfolio Reliabilitv
In the 2019 IRP, the Company assumed that a l5% PRM was sufficient based on North
American Electricity Reliability Corporation ('NERC") requirements and on PRMs used by
6STAFF COMMENTS JUNE 2,2022
other regional utilities.3 It was not derived from a LOLE target like in this IRP. However, the
Company performed a verification step in the 2019 IRP to determine if the preferred resource
portfolio met a 1 day in l0-year ("1-in-10") LOLE,4 but only verified it for the year 2025 without
verifuing any other years across the planning horizon. See Second Amended 2019 IRP at 126.
For the 2021 IRP, the Company developed and implemented reliability modeling
functionality that was integrated with the Company's overall IRP methodology providing closed-
loop verification that all high performing portfolios meet the Company's reliability target every
year over the 20-year planning horizon. Instead of assuming a PRM is suffrcient, the Company's
new process allows the Company to determine a PRM from a LOLE target established at the
beginning of the IRP cycle. Staff believes that these modeling improvements have improved the
likelihood that the Company's resource portfolios will meet reliability requirements based on the
LOLE goal.
To understand the new reliability modeling functionality, it is necessary to understand the
overall process before the new functionality was added in this year's IRP. The backbone of the
Company's IRP process uses two modules built into the Aurora modeling software: the LTCE
module and the production cost simulation module. Both Aurora modules are integrated,
allowing the Company to build a common model that represents the topology of the Company's
current system. After a model of the Company's current system has been built, the LTCE
functionality fills capacity deficits with resources selected from a pool of potential resources to
produce a cost-optimized resource portfolio within a set of constraints; the most important
constraint ensures that the portfolio has suffrcient resources to meet customer load plus an
additional PRM as a safety factor. By changing the inputs in the LTCE model, the Company can
generate multiple alternative resource portfolios, which are cost optimized for a given set of
inputs.
After resource portfolios have been produced, they are simulated through the production
cost module. This module performs a time-step simulation that simulates the operation of the
portfolio, dispatching the resources in the most cost-effective manner and within operational
constraints of the resources included in a resource portfolio. As the production cost module steps
3 The planning margin is an adjustment factor for the level of reserves needed to reliably meet load. It is added to
the peak load forecast that determines the level of resources needed overall. The 2019 IRP used a PRM of l5Yo
because it is consistent with the NERC's N-l Reserve Margin criteria, which is similar to the planning margins used
by other utilities in the same region. Page 103 of the Second Amended 2019 IRP.
4 LOLE or Loss of Load Expectation is measured in days per year. A I -day in t 0-year LOLE is equivalent to 0. I
days of electricity outage that customers will experience each year.
STAFF COMMENTS 7 JUNE 2,2022
through the 20-year planning horizon in simulated time, the software collects cost and
performance data for a given portfolio and set of input assumptions. It is through the production
cost module that the net present value ("NPV") for each portfolio is determined to inform the
selection of a least-cost, least-risk portfolio.
The new reliability model developed for this year's IRP was integrated into Aurora by
designing it to provide the PRM and ELCC5 of variable renewable resources and time-limited6
resources as inputs into the Aurora LTCE model. The PRM and the ELCCs generated as outputs
by the new model are probabilistically determined to meet a desired LOLE reliability target.
After the portfolios have been generated in the LTCE, the reliability model is used to veriff that
portfolios have met the LOLE target for all 20 years of the planning horizon as closed-loop
verification.
In addition to the new reliability modeling functionality, the Company verified and
updated the ELCC assumptions it used for its dispatchable resources. The Company utilized the
Equivalent Forced Outage Rate ("EFOR") method to perform its updates which is based on the
availability of the resources without forced downtime, like the methods used in past IRPs. The
Company used recent historic data and incorporated recent upgrades to its facilities in its
updates.
Staff believes the new functionality and steps the Company took to verifl, the load
serving assumptions of resources improves the Company's ability to ensure an accurate
measurement for the reliability of its resource portfolios in this year's IRP. However, Staff is
concerned the Company's method uses only a single year (2023) as a benchmark to calculate the
15.5% PRM for all years of the planning horizon. Staff recommends the Company provide
justification and additional analysis of other years to verifr using only a single year in the 2023
IRP is appropriate.
5 ELCC or Effective Load Carrying Capability is becoming the industry standard term used to describe the peak
serving capability of resources. However, the method used to determine it depends on the type of resource.
6 Time-limited resources includes energy storage and demand reduction which required additional functionality to
model its ELCC.
STAFF COMMENTS 8 JUNE 2,2022
B. Establishment of the Reliability Target
The Company applied a 15.5o/o PRM to its load forecast to develop the Company's
portfolios. This 15.5% PRM was derived using a one day in twenty years ("1-in-20") or 0.05
days per year LOLE reliability target using the new reliability modeling capability described
above. However, the Company changed its target from a l-in-I0 LOLE target that was used
throughout most of the 2021 IRP cycle to the more stringent l-in-20 target toward the end of the
cycle. According to the Company, this reliability target was changed to account for the extreme
weather events that are becoming more frequent and adding increased uncertainty in year-to-year
water availability impacting hydro generation.T See 2021 IRP, Appendix C at99.
A 1-in-10 LOLE target is the industry standard for resource planning as established by
the NERC. See Response to Staff Production Request No. 14 in Case No. IPC-E-21-43. In
addition, a l-in-10 LOLE is used as the reliability standard for the California Independent
System Operator Corporations and for the Northwest Power Pool's Resource Adequacy
Program.e
Staff believes 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. Instead of using a
more stringent target to compensate for the variability of weather, it is more appropriate to
incorporate year-to-year variability in both the Company's load forecast and availability of hydro
generation in its resource assumptions rather than assuming average weather conditions in the
IRP.
Staff does not believe changing the LOLE target affected the overall results. The
development of the Company's IRP can require the Company to rework its analysis as issues are
discovered. The IRP is a serial process with many of the initial steps occurring several months
before results can be obtained. When issues are discovered late in the process, options to make
adjustments before the IRP is due may be limited.
7 In Response to Staff s Production Request No. 15, the Company stated that Northwest Power and Conservation
Council used a I day in 2}-year LOLE in its Seventh Power Plan (htps://www.nwcouncil.org/reports/seventh-
power-plan) and in its Resource Adequacy site (https :llwww. nwcouncil.org/energy/energy-topics/resource-
adequacy).
8 http://www.caiso.com,{Documents/\4arl4-2022-ApeningComments-Loss-LoadExpectationStudy-LCR-
FCRSchedule-LocalCapacityRequirements-WorkingGroupReport-R2l - 10-002.pdf
e https://www.westernpowerpool.org/private-media/documents/2021-08-30 NWPP RA 2B Design_v4_final.pdf
STAFF COMMENTS 9 JUNE 2,2022
In a meeting with Staff, the Company illustrated how weather variability over a historic
four-year period had an impact on the resources needed to ensure reliability. By comparing the
2023 benchmark year resource requirement with average weather to the resource requirement for
2023 adjusted for weather over a recent four-year period, the Company demonstrated shortages
could occur in two out of the four years. See Response to Production Request No. 20 in Case
No. IPC-E-21-32. This indicates that the load forecast may be underestimated, or hydro resource
capacity contribution overestimated (or some combination of both) during certain years over the
IRP planning horizon by not accounting for year-to-year variability in weather. Given that the
resulting 15.5% PRM is close to thel5Yo PRM used in previous IRPs, Staff believes that using a
more stringent l-in-20 LOLE target achieves approximately the same result and does not harm
the overall results of the IRP. Although Staff does not believe that changing the reliability target
is proper to compensate for adjustments needed in its model input assumptions, the change
effectively ensured sufficient resources in the Company's final portfolios and allowed the
Company to meet its schedule. Staff recommends the Company determine an alternative, other
than changing the reliability target, to adjust for year-to-year variability in weather and water and
to identift a reliability target based on customer tolerance of outages at the beginning of the2023
IRP cycle.
tt. 2021IRP L&R
Because of the significant change in the first deficit dates between the 2019 IRP and the
2021 IRP, Staff compared the L&R in each IRP to understand drivers of the changes to
determine if the L&R in this IRP is reasonable. The 2019 IRP had a first deficit date of August
of 202910 , while the 2021 IRP stated a first deficit date of July of 2023 with deficits also
occurring in202l and2022 in the Company's L&R.lr Staff s analysis identifies the primary
causes for the shift broken down by changes in the Load Forecast and in the existing resources.
r0 See Response to Staff s Production Request No. 92 in Case No. IPC-E-19-19. Based on this response, the first
deficit based on the Second Amended 2019 IRP will occur in August of 2029 with a deficiency of 5 MW. However,
the Application in Case No. IPC-E-21-09 (the first capacity deficiency case after the acknowledgement of the
Second Amended 2019 IRP) stated that the first deficit will occur in August of 2028 with a deficiency of 14 MW.
For the purpose of Staffs comments, the L&R with the first deficit year of 2029 is used to represent the results of
the Second Amended 2019 IRP.
I I See Table I 0.7 in the 2021 IRP. The table also shows deficits in 202 I and 2022. Response to Staff s Production
Request No. 32 in Case No. IPC-E-21-09 states that the deficits amounts in these two years were determined using
the same method as the later years, but the202l IRP did not add resources in these years because the AURORA
model was prevented from selecting resources due to the lack of lead time.
STAFF COMMENTS IO JT]NE 2,2022
After reviewing of the Company's L&R, and quantiffing the drivers causing the changes in the
deficit dates, Staff believes that the L&R in the 2021 IRP is reasonable.
A. Load Forecast
The Peak Load Forecast in the L&R is the same forecast used to determine future
resources in the preferred portfolio. The Peak Load Forecast was derived from the four main
drivers impacting the load forecast in the 2021 IRP: (l) a higher migration of customers into the
Company's service territory, (2) growth in the number of industrial customers, (3) a higher PRM,
and (a) lower capacity contribution of existing DR programs.
During and after 2020, approximately 30Yo more people moved into the Company's
service territory than expected. 2021IRP at 170. Several industrial customers have also made
binding investment and/or expressed interest to expand their operations in the Company's service
territory.l2
The Company's new reliability modeling functionality also highlighted the need to
change the design of the Company's DR programs. The capacity contribution of existing DR
programs was 390 MW for the entire planning horizon in the 2019 IRP. See Response to Staff s
Production Request No. 92 in Case No. IPC-E-19-19. However, by measuring the capacity
contribution of existing DR programs using the new reliability model, the Company discovered
that the contribution of capacity was only 176 MW. See 2021 IRP (Table 10.7).
B. Resources in the L&R
On the resource side, Staff identified two primary factors that contribute to an earlier first
deficit year: (1) reductions of capacity contribution of coal and natural gas plants (including
Bridger, Valmy, and natural gas peakers); and (2) reductions in assumed market availability due
to transmission capacity.
The 2021 IRP modeled dispatchable resources using a monthly outage table based on the
resource's monthly capacity and EFOR. The use of EFOR and additional refinements made to
the peaking capabilities of coal and natural gas resources resulted in reductions of capacity
contribution of coal and the natural gas peaker resources.l3 See Response to Staff s Production
12 For example, Brisbie, LLC's Data Center Facilities ("Brisbie") load is included in the L&R.
13 Not all dispatchable resources reduced its capacity contribution under the new ELCC method. For example, the
Hells Canyon Complex's capacity contribution increased by 60 MW under the new method. The method also
STAFF COMMENTS 1l JLrNE 2,2022
Request No. 9 in Case No. IPC-E-21-43. Table No. I reflects the change of capacity
contribution for these resources.
Table No. L: Comparison of Capacity Contributions between 2021 IRP and 2019 IRP
Bridger (MW)Valmy (MW)Gas Peakers (MW)
2O2I IRP 663 1 2 1 36s
20I9IRP 703 136 416
Difference -40 -15 -51
The second factor contributing to an earlier first deficit year was the reduction in market
availability due to transmission capacity assumptions. In previous IRP's, the Company only
constrained market availability by transmission capacity within its own system. It had always
assumed firm transmission to market hubs could be obtained outside of its service territory. In
addition, the Company assumed Valmy Unit2 could be replaced with market purchases from the
southem market in its 2019 IRP. As will be discussed in more detail later, firm transmission
capacity became strained due to California's energy emergency in2020. 2021 IRP at 168.
Because of these developments, the Company constrained market availability by market hub
access limited by third-party firm transmission reserved by contract. Response to Staff s
Production Request No. 32 in Case No. IPC-E-21-09. Changes in assumptions for market
availability due to changes in transmission assumptions contributed to an earlier first deficit year.
Table No. 2 shows the change in market purchases (without B2H) from2023 through 2029 based
on the changes to transmission assumptions in this year's IRP.
changed how intermittent resources' capacity contribution is calculated. For example, solar contribution was
calculated using the 8,760-based method developed by the National Renewable Energy Laboratory in the 2019 IRP,
but now it is calculated by the ELCC method in the 2021 IRP. 2021 IRP at 5l. Despite the method change, the
capacity contribution of total PURPA resources (including solar, wind, and others) did not change much for the first
half of the planning horizon.
STAFF COMMENTS 12 JUNE 2,2022
Table No.2: Comparison of Market Purchases in 2019IRP and 2021 IRP
III. Development of Portfolios and Selection of the Preferred Portfolio
Staff believes the Company identified a preferred portfolio that (1) resolves deficits in its
L&R; (2) informs key resource decisions that need to be made within the next ten years; and (3)
strikes a reasonable balance between cost and risk. Staff came to this conclusion by reviewing
how the Company:
1. Verified its models were operating as expected and validated that the models
produced cost-optimized portfolios for the Company's balancing area ("BA");
2. Developed and compared different resource portfolios based on key resource
decisions; and
3. Evaluated the risk of competing portfolios.
The resulting preferred portfolio included in the Company's 2021 IRP was the Base with
B2H portfolio. It projects the following changes in the Company's resources over the next ten
years:
o Conversion of Bridger Units I and2 from coal to gas-fired generation by the end of
2024;
o The addition of approximately 700 MW of windin2024;
o The addition of I105 MW of solar from 2023 tbrough2029;
o The addition of 650 MW of storage from2023 through 2031;
o The addition of 500 MW of market access through the B2H transmission line in2026;
o About 340 MW of DR capacity with implementation of the new programs starting in
2022;
o Removal of 308 MW and 175 MW of coal plant capacity through exit of Valmy Unit
No 2 at the end of 2025 and Bridger Unit No. 3 at the end of 2028, respectively; and
o The addition of about 256 MW of capacity contribution from Energy Efficiency
("EE").
2021 IRP atl52.
STAFF COMMENTS 13 JTINE 2,2022
Market Purchases (MW)2023 2024 202s 2026 2027 2028 2029
2021 IRP 710 709 707 705 704 703 702
2OI9IRP 923 923 923 1054 1054 1054 1054
Difference -2t3 -2t4 -216 -349 -350 -351 -352
A. Verification and Validation of the Company's Models
Because of the extensive use of computer models involved in producing the Company's
IRP, it is necessary for a comprehensive QA plan to perform both verification and validation to
ensure that the models are behaving as conceptually designed and that the results produced are
accurate. The Company made significant improvements in its QA efforts for both verification
and validation in this year's IRP; however, Staff recommends the Company produce a
comprehensive QA plan in its next IRP that lists all the items the Company verifies or validates
in its models.
One of the most significant improvements was the verification and validation of the
Aurora LTCE optimization module used in the 2021 IRP. In the 2019 IRP, the Company could
only produce cost-optimized resource portfolios for the Western Electricity Coordinating
Council ("WECC") interconnection and was not able to produce cost-optimized portfolios for the
Company's BA. This issue caused the 2019 IRP to be delayed by 15 months and required the
Company to perform manual steps to determine cost optimal portfolios for its system. However,
because WECC-optimized results were used as a starting point for the manual adjustments, Staff
was not assured that the manually adjusted portfolios were optimal.
The Company has since worked with Energy Exemplar, developers of the Aurora
software, to make modifications that ensure the resource portfolios are optimized for the
Company's BA. Staff believes that the LTCE module now produces results optimized for the
Company's BA. See Company Response to Audit Request No. 2.
As described above, the Company also developed a process for veriffing the reliability of
the Company's portfolios back to the LOLE target used to establish the PRM used as an input in
the LTCE models. The results of these tests found several capacity shortfalls in the last five
years of the 2}-year planning horizon that did not meet the LOLE reliability target. To ensure
the NPV cost of all the portfolios were comparable, the Company added the cost of capacity to
make up for any shortfalls in reliability using the cost per kilowatt-year of a Simple Cycle
Combustion Turbine ("SCCT") capacity resource. Staff believes this was an appropriate
adjustment because of the size and timeframe of the adjustments. See 2021 IRP, Appendix C at
99.
Finally, the Company performed sensitivity analyses by changing the resources in
optimized portfolios to determine their effect on the cost of the portfolios. If the changes caused
a decrease in the NPV cost of the portfolio, the Company could conclude that the original
STAFF COMMENTS t4 JUNE 2,2022
portfolio was not optimized. The Company tested key resource decisions such as: (l) different
transfer capacities of B2H; (2) different exit dates of coal plants; (3) exiting Bridger Units I and
2 instead of a natural gas conversion; (4) replacement of solar plus storage with natural gas
generation; (5) replacing dispatchable resources with geothermal and biomass; and (6) increased
amounts of Demand-Side Management. In all cases, the LTCE optimized portfolios were least
cost. Staff believes that these tests were key to validating the model results and improved the
credibility of the IRP. Staff recommends the Company document all verification and validation
QA steps in the same way these tests were documented in the 2021 IRP by describing the
purpose of the test, how the test was conducted, and the results.
B. Development and Evaluation of Portfolios
The Company built six Base portfolios targeting important resource questions that needed
to be answered in the202l IRP, the most important being whether or not to build the B2H
transmission line. The Company included three Base portfolios with B2H and three without
B2H. Within those two sets of portfolios, the Company generated portfolio variations on
whether it was beneficial to align Bridger exit dates with PacifiCorp, and whether Gateway West
was economical. Beyond these resource alternatives being forced into portfolios, all the
remaining deficits were filled with resources that were the most economical by using planning
conditions for all key inputs such as load growth, natural gas price, and carbon price. The
Company then ran each Base portfolio through the production cost model to determine their
NPV cost over the 2}-year time horizon using different natural gas prices (planning and high)
and carbon prices (2erc, planning, and high). Staff believes this analysis was appropriate and
informs of the need for the B2H transmission line given planning case input assumptions. The
NPV results of the Company's Baseline analysis is duplicated from the Company's IRP as
shown below.
STAFF COMMENTS l5 JUNE 2,2022
2021 IRP portfolios, NPV years 2OZL-2O4O ($ x 1,000)
Portfolio Planning Gas, Planning
Carbon
57,gLs,702
57,999,347
Planning Gas, Zero
Carbon
57,t86,76L
57,ts2,gss
57,784,s45
57,s88,228
High Gas, High Carbon
s9,832,001
59,932,92s
$9,474,983
s9,652,891
59,424,93s
Base with B2H
Base B2H PAC Bridger
Alignment
Base without B2H
Base without B2H without
Gateway West
Base without B2H PAC
Bridger Alignment
Base with B2H-High Gas
High Carbon Test
s8,192,830
58,44t,474
s8,18s,334
57,997,339
The NPV results show that the portfolios with B2H were least cost for planning gas and
planning or zero carbon; however, the production cost simulations show that B2H may not be the
most economical choice with high natural gas and carbon prices. Based on these results, the
Gateway West transmission line without B2H may be more economical because Gateway West
would provide better access to renewable energy. To counter this contention, the Company
produced additional base portfolios including B2H (as shown on the bottom row of the table).
Instead of using planning gas and carbon to develop the portfolios, it used high gas and carbon.
Because of this analysis, the Company concluded:
[The] "Base with B2H-High Gas High Carbon (HGHC) Test" portfolio includes total renewables
equivalent to the "Base without B2H" portfolio and was evaluated to test B2H as an independent variable.
The results indicate that B2H remains cost effective, independent of gas price and carbon price and that a
pivot to even more renewables in a future with a high gas and carbon price would be appropriate.
2021 IRP at 130, fn 36.
However, Staff does not agree with the Company's conclusion since these results are not
comparable to any of the results in the table. To make it comparable, the Company would need
to generate portfolios for all Base scenarios using the high gas and carbon price inputs and then
simulate them through the production cost model using the same planning gas and carbon prices
to compare against the $7,997,339 amount and high gas and high carbon prices to compare
against the$9,424,935 amount. Until the Company runs this analysis, Staff believes that
increasing gas prices and legislating carbon restrictions may make B2H less economical.
C. Evaluation and Mitisation of Risk
The Company performed three general types of analysis to evaluate risk: (1) the
generation of different portfolios given different alternative future scenarios; (2) a qualitative
STAFF COMMENTS 16 JLINE 2,2022
analysis of all the Base portfolios across several risk factors; and (3) a stochastic risk analysis
where all Base portfolios were simulated through the production cost model and subjected to
randomized values within a reasonable range of gas prices, loads, and hydro generation. See
2021 IRP atl2l,l34,and 136. Based on the scoring of these risk evaluation methods, the
Company determined the Base with B2H preferred portfolio has a comparatively low level of
risk when compared to the Company's other Base portfolios. However, Staff has two concems
related to risk:
1. How much the Company is relying on B2H to meet its future capacity needs due to it
being the largest and most expensive resource in the Company's preferred portfolio;
and
2. The lack of risk mitigation and flexibility strategies included in the Company's IRP.
The Company analyzed several sensitivities of risk associated with (l) how much
capacity the Company will be able to obtain through the B2H transmission line, (2) increases in
B2H construction costs that would make the preferred portfolio no longer economic, and (3) the
impact of not being able to meet the B2H in-service date by the end2026. Because B2H
represents the largest and most expensive single resource included in the preferred portfolio,
there is additional risk if it does not meet budget and schedule and would likely cause serious
impacts to both customer cost and reliability. According to the Company's analysis on
construction costs, a cost overrun of more than30Yo would need to occur for the Base with B2H
portfolio to no longer be the lowest cost portfolio. In addition, if the in-service date extends by
one year, the Company will need to acquire additional resources to fill capacity gaps estimated to
cost an additional $69 million. 2021IRP at 145-146. Staff does not believe that a cost ovemrn
of 30Yo or a slip in schedule of one year is unrealistic given current rates of inflation and supply
chain issues that may persist into the future, as well as, transmission siting issues that have
historically been diffrcult for the Company to resolve.
Staff is also concerned that the Company's IRP does not examine a strategy of resource
flexibility that could proactively mitigate a rapidly changing energy environment. The Company
included plans to convert Bridger Units I and2 to natural gas. However, the facility was not
consciously designed for rapid conversion requiring extensive downtime and cost. Staff believes
the Company should study ways to include resources that provide flexibility to changes due to
regulations, fuel costs, customer behavior, economic drivers, electricity markets, and other
STAFF COMMENTS t7 JUNE 2,2022
factors. These solutions could include: resource diversity,la multi-fuel thermal plant designs
(i.e., plants that can burn hydrogen, natural gas, coal gas, etc.), scalable/modular approaches to
decreasing or increasing capacity, mobile generation that can be moved to constrained load
pockets until more permanent solutions are constructed, mothballing coal plants instead of
decommissioning, and improving access to multiple market hubs, are just a few examples.
Proactively designing a flexible supply chain carries additional cost, which is why Staff
recommends it should be studied in the 2023 IRP.
IV. Natural Gas Forecast
Historically, natural gas price forecasting within the Company's IRP has been
controversial. For the 2013 and 2015 IRP natural gas price forecasts, the Company used the
EIA's Henry Hub reference case forecast, adjusted for Sumas basin pricing. This method
reflected the Company's city gate price for natural gas. In 2017, the Company departed from
using the EIA's Henry Hub reference case and used the EIA's Henry Hub High Oil and Gas
Resource and Technology Case. This method produced low natural gas prices throughout the
IRP 2O-year planning period and prompted intense discussions within IRP stakeholder meetings
calling for improvement in how the Company forecasts IRP natural gas prices.
The Company continued efforts toward making improvements to its IRP natural gas price
forecasting. In20l9, the Company decided to use a third-party vendor for its IRP natural gas
price forecast and selected S&P Global Platts North American Gas Analytics ("Platts") and used
Platts again in the 2021 IRP.
Through analysis of the impact of higher gas prices on the IRP, the Company used the
EIA's Low Oil & Gas Supply forecast from EIA's Annual Energy Outlook 2021. The EIA's
Low Oil & Gas Supply assumes lower oil and gas production, which creates a higher natural gas
price.
ra Because of the optimization algorithms in the LTCE model, the model tends to select the lowest cost resource
available for selection by the model to fill deficits that can dominate portfolios.
STAFF COMMENTS 18 JUNE 2,2022
The Company stated:
To veriff the reasonableness of the third-party vendor's forecast, Idaho Power compared
the forecast to Moody's Analytics, the United States Energy Information Administration
(EIA), and the New York Mercantile Exchange (NYMEX) natural gas futures
settlements. Based on a thorough examination of the forecasting methodology and
comparative review of the other sources (i.e., Moody's, EIA, and NYMEX), Idaho Power
concluded that the third-party vendor's natural gas forecast is appropriate for the planning
case forecast in the 2021 IRP.
2021 IRP at 105.
Staff believes the Company's analysis and utilization of EIA, NYMEX, and Moody's
data to verifu that Platts' forecast is appropriate for planning purposes and use of the forecast in
the IRP is reasonable. Given current natural gas price volatility, Staff encourages the Company
to continue to monitor its natural gas price forecasts and market conditions. Staff supports the
Company's natural gas forecasting improvement efforts and believes changes to generation
resources and portfolio selections are important considerations in further development of
forecasting methods to minimize fuel price risk and operating costs.
V. Supply-Side Resources
A. Transmission and Market
Staff recognizes the potential benefit of the Company's transmission system for
providing interconnecting capacity and for accessing low-cost energy from the market. But
unless the Company has secured firm access through interconnecting transmission, the benefit to
its system can disappear quickly. This can be seen following the recent events in 2020. As a
result, the Company opted to reduce its access transmission capacity for the years 2023 through
2025 from 900 MW in the 2019 IRP to 700 MW in the202l IRP, resulting in immediate need
for new generation resources by 2023.
Staff believes its reasonable for the Company to expand its share of B2H to 45o/o. The
Company states that it continues to expand its transmission resources to bring low-cost hydro
and renewable variable energy resources ("VERS") into its service area. In this IRP, the
Company expanded its share of the B2H transmission, planned for completion in 2026,from
2lo/oin2019to45o/ointhe202lIRP. TheCompany'sincreaseisreflectedthroughits
absorption of Bonneville Power Administration's previously assumed ownership share. Given
this addition and its associated cost, the inclusion of B2H in the 2021 IRP analysis showed a
STAFF COMMENTS 19 JI-INE 2,2022
NPV benefit of $270 million compared to the next least-cost altemative portfolio which did not
include B2H.
1n2020, the Company's transmission system allowed it to purchaseT.4Yo of its energy
need through the market at lower relative cost. Although transmission can provide significant
economic benefit when low-cost energy is available, Staff believes there are certain risks to the
system. As external factors evolve, the risk for the Company's investment in transmission
becomes more apparent.
In the 2019IRP, the Company assumed Valmy Unit2 could be replaced with capacity
purchases from the south, but market conditions changed after the August 2020 California
energy emergency event. The event caused a ripple effect limiting the Company's ability to
secure third-party firm transmission to import energy. While the Company directly maintains its
ability to reserve its own transmission, it must rely on transmission interconnections from
adjacent BAs to benefit from lower cost market purchases.
B. Hydro Resources
The Company has a stated goal for sourcing 100% of its electricity through clean
generating resources. Staff is concemed that as the Company relies more heavily on hydro
generation and renewables to step away from more traditional dispatchable resources increasing
reliability risk to the system.
Idaho Power plans to utilize hydropower generation as its main tool for meeting the
Company's goal of selling 100% clean energy by 2045. Idaho Power's hydroelectric generation
currently comprises 42o/o of the Company's total generating capacity. Any significant yearly
reduction in hydroelectric generation or a change in the timing of yearly runoff can negatively
affect system reliability and would create upward pressure on rates during low hydro periods
especially as the Company moves toward more intermittent renewable resources. As noted in
the202l IRP climate study, change and specific risks are an evolving category that include
changes in customer usage and hydro generation from changing weather conditions.
The climate change study indicates natural hydrographs could see lower summer base
flows, an earlier shift of the peak runoff, higher winter baseflows, and an overall increase in
annual natural flow volume. For Idaho Power's hydro system, the findings support that upstream
reservoir regulation, if available, could significantly dampen the effects of this shift in natural
flow to Idaho Power's system. Staff believes it is unlikely that additional upstream reservoir
STAFF COMMENTS 20 JI.INE 2,2022
regulation will occur. Further, the studies indicate Idaho Power could actually see July through
December regulated streamflow relatively unaffected, and January through June regulated stream
flows increase over the 2}-year planning period.
For the 2021lRP, the Company showed no reduction to the available capacity or
operational flexibility of its hydroelectric plants, although over the long term, the variability of
stream flows may or may not support the trend in hydro generation during peak summer load.
C. Coal Generation
Staff believes existing coal generation is an effective resource for providing dispatchable
generation, and currently provides system reliability. Coal contributes about 2lYo of the energy
delivered to the Company's customers. As the Company transitions towards its clean energy
goal, the Company needs to be strategic in the timing of coal unit exits. The timing of coal unit
exits and replacement with new resources significantly impact customer rates and without proper
planning may impact system reliability.
In the 2021 IRP, Idaho Power continued to analyze exiting from coal units before the end
of their depreciable lives. These coal units continue to deliver generating capacity and energy
during high-demand periods and/or during periods of high wholesale-electric market prices.
The 2021 IRP reflects different thermal resources exit dates with the Company exiting all
coal generation by 2028 -- two years earlier than the final coal exit date in the 2019 IRP.
PacifiCorp and the Company concluded through their IRPs, it would be cost-effective to convert
Bridger Units I and2 to natural gas beginning in 2024 while continuing to operate Units 3 and 4
as coal units. This would be the only natural gas addition in the 2021 IRP -- compared to 411
MW of new gas generation added in the 2019 IRP.
In the 2021 IRP, the Company plans to exit coal operations for Bridger Unit 3 at the end
of 2025 and Unit 4 at the end of 2028 and completely exit the plant in 2034 while PacifiCorp
would continue to operate Units 3 and 4 through 2037. Staffunderstands that neither partner has
developed contractual terms necessary to allow for the potential earlier exit or conversion to a
non-coal fuel source. Because of the lack of a Bridger exit agreement with PacifiCorp like the
exit agreement developed for the closure of Valmy, the Company has not been able to include
potential costs of extending or exiting operations early. Without this agreement, the economic
evaluation of different exit dates is probably inaccurate in this IRP. Staffbelieves the
negotiation of an exit agreement should have been included in the Company's 2021 IRP action
STAFF COMMENTS 2l JUNE 2,2022
plan and recommends that it be incorporated into its coal plant exit costs to properly value
different exit dates in the Company's portfolios in the 2023 IRP.
Following development of the 2019IRP, the Company conducted focused system
reliability and economic analyses to assess the appropriate timing of a Valmy Unit 2 exit
between 2022 and2025. The result of the reliability and economic evaluations demonstrated
that coal-fired operations at Valmy Unit 2 through the end of 2025 is the most reliable and
economic path forward.
The obligation to deliver reliable and affordable electricity underscores its need to
continue to evaluate coal unit value for providing flexible capacity necessary to successfully
integrate the high penetration of VERs. Staff believes the Company is responsible for the
evaluation of flexible capacity and the possibility of flexible resource capacity deficiencies
arising because of coal-unit exits, which may require the Company to extend coal-unit operations
to maintain system reliability.
D. Renewable Energy and Energy Storaee
Staff is concerned by the Company's transition toward VERs and energy storage in the
2021 IRP as compared to the 2019 IRP. The202l Preferred Portfolio adds sizeable amounts of
VERs totaling 700 MW of wind and 1,405 MW of solar during the forecast period. The
Company also plans to add 1,685 MW of battery energy storage during this period. In contrast,
the 2019IRP Preferred Portfolio included no wind resources? 400 MW of solar, and only 80 MW
of battery storage. Most of the Company's renewable resources come online prior to 2030.
Staff recognizes the benefit of zero-fuel cost VERs, but as the Company works toward its
clean energy goal, it is obligated to continually assess system reliability and its need to maintain
adequate dispatchable resources whether by deferring its planned exits from coal units or its
natural gas generating resources.
E. Natural Gas Generation
The Company stated that Langley Gulch will be upgraded in2022 and the total
nameplate of the plant will increase to 365 MW. All of the Company's natural gas facilities are
used as needed to support system load. Natural gas generation provides approximately l5Yo of
the Company's electricity.
STAFF COMMENTS 22 JUNE 2,2022
The 2019 IRP included 411 MW of additional natural gas generation, but this IRP
includes no new natural gas generation additions. Notably, the Company is working with
PacifiCorp to convert Bridger Units and I and2 from coal to natural gas. The cost of conversion
is significantly less than installing Selective Catalytic Reduction ("SCR") on coal fired units to
comply with federal Regional Haze regulations. Additionally, Staff believes having two
additional dispatchable gas peaker units provides system benefits for both companies and was
shown to be cost effective compared to other alternatives for additional capacity due to the low
capital cost of conversion. The gas conversion of Bridger should be online during the summer of
2024 -- with an exit date of 2034 -- providing35T MW of electricity.
The conversion of Bridger Units 1 and2 to natural gas provides operational, reliability,
and economic benefits. However, there is a level of uncertainty regarding the Company and
PacifiCorp's implementation of the planned conversion. Uncertainties include federal and state
regulations, date of conversion, future operating cost, and costs for eventual decommissioning
and retirement.
VI. Demand-Side Resources
A, EE
In the 2019 IRP, the Company utilized the Total Resource Cost ("TRC") test resulting in
a2l-year EE potential of 234 average megawatts ("aMW"). However, the Commission denied
the Company's request to use the TRC perspective during the integrated resource planning phase
and ordered the Company to use the Utility Cost Test ("UCT") perspective for integrated
resource planning. Order No. 34469 at 9. With the change to the UCT, the Company's EE
potential increased to 300 aMW or 440 MW over the 20-year planning horizon. Staff believes
the use of the UCT perspective will result in a more accurate IRP forecast for EE and will help
align the Company's current EE programs, currently evaluated using the UCT, with IRP EE
forecast.
The 440 MW consists of 428 MW of EE determined by cost-effective measures
identified in the EE Potential Assessment, conducted by Applied Energy Group, and 12 MW of
EE selected by Aurora. The 12 MWs of EE measures selected by Aurora were considered cost-
ineffective through the Potential Assessment; however, the additional 12 MWs of EE across the
2}-year planning horizon were selected by Aurora based on economic parameters for a single
year. To allow the model to select additional EE for any given year, the Company bundled
STAFF COMMENTS 23 JUNE 2,2022
similar cost-ineffective EE measures into four groups based on their cost and peak seasonal load
shapes: (1) summer low cost; (2) summer high cost; (3) winter low cost; and (4) winter high cost.
The Company then allowed Aurora to select additional EE bundled measures as their own
resource in any given year. This resulted in EE bundles of 3 MW and 9 MW being selected in
2039 and2040. Staff believes the addition of EE bundles is an improvement to the IRP and
encourages the Company to continue refining this method of allowing additional EE selections in
the IRP to help alleviate energy constraints throughout the IRP planning horizon.
B. DR
During the development of the 2021 IRP, to better align the existing programs with
system needs, the Company modified its existing DR programs to remove marketing limitations,
adjust incentive levels, adjust hours of use, and extend the season for all three of their DR
programs. See Case No. IPC-E-21-32. The modifications resulted in the Company plaruring on
an estimated 300 MW of nameplate capacity from the modified programs in the 2021 IRP.
For estimating the potential of DR in the 2021 IRP, the Company used the "Northwest
Power and Conservation Council ('NWPCC") assessment of DR potential for the Northwest
region to determine the DR potential that may be available in Idaho Power's service arca." 2021
IRP at 68-69. After several adjustmentsls to the NWPCC assessment of DR, the Company
estimates an additional280 MWs of available DR capacity in its service territory, which was
divided into 20 MW bundles, to be selected by the LTCE model. In the 2021 IRP preferred
portfolio, the LTCE selected an additional 100 MW of DR capacity in addition to the 300 MW
from the modified programs, with 20 MW additions in 2023 and2025. Comparatively, the
Company's existing DR programs provided 390 MW of peak capacity and the LTCE selected an
additional 45 MW of DR in the 2019IRP preferred portfolio.
DR can be a valuable resource in helping the Company offlset loads during system peak.
Staff is concerned that the 20 MW threshold capping additional DR capacity in the LTCE model
may limit the addition of new DR capacity when the Company is capacity deficient, i.e., the
Company is currently forecasted to be capacity deficient in the summer of 2023. Staff
recognizes that a threshold cap is likely necessary to implement for additional DR capacity due
to ramping issues with new DR programs but recognizes the benefits DR can provide in helping
t5 For information on the Company's adjustment to the NWPCC DR potential assessment to their service territory,
See Staff Comments at 5 onlPC-E-21-32.
STAFF COMMENTS 24 JUNE 2,2022
the Company in times of capacity constraints. Therefore, Staff recommends the Company
discuss and explore adjusting the20 MW threshold cap on additional DR capacity with its
Energy Efficiency Advisory Group and the IRPAC in the development of the 2023 IRP.
With the recent modifications to existing DR programs, Staffnotes that the 300 MW
from the modified DR programs is merely an estimate and participation numbers could be highly
variable resulting in higher or lower than planned DR capacrty. Prior to the modifications, the
existing DR programs maintained consistent participation and the Company could regularly plan
on approximately 390 MW of DR potential during their IRP planning periods. With the major
changes to the DR program, expanding dispatchable hours later in the evening and extending the
program season to address higher risk hours for reliability, the participation amounts in the
modified programs could vary. Staffrecommends the Company continuously monitor existing
DR program participation and adjust estimates for available DR capacity accordingly as the
Company learns of customer's willingness to participate in the modified DR programs.
The Company is currently conducting a DR potential study for its service territory that
will be included in the 2023 IRP. The results of the DR potential study will improve the
accuracy of DR potential for the Company's service territory.
VII. Public Participation
The Company held nine virtual IRPAC meetings that were open to the public, and three
additional workshops to address questions specific to different aspects of the IRP.
The virtual format of the meetings allowed for increased levels of participation by
allowing meeting participants to ask questions during presentations. By using the chat function,
other members of the Company's IRP team were able to address a larger number of the questions
from the public.
The largest improvement Staffsaw in its engagement in the process was the level of
active listening and engagement that took place by the Company's IRP team. Input was well
received and recorded, and questions were validated with responses provided later if answers
were not immediately available.
VIII. Action Plan
The action plan from the202l IRP is developed to address actions the Company needs to
implement within the202l to2027 action plan window. Because the Commission only
STAFF COMMENTS 25 JUNE 2,2022
acknowledges the IRP, Staff believes that most of the resources included in its IRP portfolios
should be considered as proxies. To obtain Commission approval requires additional process
and subsequent filings to ensure determination of prudence of specific resources before cost
recovery occurs.
To evaluate prudence classified as proxies, Staff believes a sufficient set of altemative
resources is required to allow for competitive bidding in the Company's request for proposals
("RfP") to obtain a reasonable low-cost resource. This cannot be accomplished if the pool of
proposals is unnecessarily limited in scope. Staff encourages the Company to only limit
proposals based on a minimum and critical set of specifications and resource characteristics in
scoping its RFPs.
However, there are specific existing resources nearing end of life and specific
transmission resources included in the Company's preferred portfolio that do not fit within the
definition of a proxy resource. The action plan for these types of resources will need actions to
evaluate how to move forward rather than comparisons of proxies through an RFP.
Staff believes that most of the items within the Company's action plan are reasonable;
however, Staff cautions that some actions, such as the acquisition of solar and wind during
specific years should be re-evaluated in the context of a broadly-scoped RFP.
STAFF RECOMMENDATIONS
Staff recommends that the Commission acknowledge the Company's2021IRP and
address the following in the Company's 2021 IRP action plan:
1. Re-evaluate its action plan to not include acquisition of specific types of resources
where a broadly scoped RFP is appropriate; and
2. Develop a Bridger exit agreement with PacifiCorp that determines potential costs of
extending or exiting operations early similar to the exit agreement developed for the
closure of Valmy and incorporate those costs into its coal plant exit costs to properly
value different exit dates in its 2023 IRP.
Staff also recommends the Company address the following in the 2023 IRP:
1. Incorporate extreme weather events and variability of water availability through its
load and resource input assumptions, rather than compensating by changing the
LOLE reliability target, which should be set as a matter of public policy;
STAFF COMMENTS 26 JUNE 2,2022
2. Only include market access backed by firm transmission reservations in its L&R;
3. Evaluate the risks and inaccuracies caused by using a single benchmark yeu (2023)
to determine the LOLE-based PRM;
4. Provide a comprehensive QA plan to veriff and validate its models by describing the
purpose of each test, how the test was conducted, and the result; and
5. Study the costs and benefits of implementing a flexible resource strategy.
Respectfullysubmittedthis 2ND day of Jwrc2022
Dayn
Deputy Attorney General
Technical Staff: Mike Louis
Kevin Keyt
Taylor Thomas
Yao Yin
Rick Keller
i: umisc/comments/ipce2l.43dhmllsktgyrkjh comments
STAFF COMMENTS 27 JUNE 2,2022
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 2ND DAY OF JUNE 2022, SERVED
THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE NO.
IPC-8.21-43, BY E-MAILING A COPY THEREOF, TO THE FOLLOWING:
LISA NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-MAIL: [e-mail]
dockets@idahopower. com
KIKI LESLIE A. TIDWELL
704 N. RIVER ST. #1
HAILEY ID 83333
E-MAIL: [e-mail]
PETER J RICHARDSON
RICHARDSON ADAMS PLLC
515 N 27TH STREET
BOISE ID 83702
E-MAIL: [e-mail]
KELSEY JAE
LAW FOR CONSCIOUS LEADERSHIP
920 N CLOVER DR
BOISE ID 83703
E-MAIL: [e-mail]
TTM TATUM
ALLISON WILLIAMS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: ttatum@.idahopower.com
awilli [e-mail]
BENJAMIN J OTTO
EMMA E. SPERRY
ID CONSERVATION LEAGUE
7IO N 6TH ST
BOISE ID 83702
E-MAIL: [e-mail]
[e-mail]
DR DON READINU
6070 HILL ROAD
BOISE ID 83703
E-MAIL : [e-mail]
MICHAEL HECKLER
COURTNEY WHITE
CLEAN ENERGY OPPORTUNITIES FOR
IDAHO INC
3778 PLANTATION RIVER DR
SUITE 102
BOISE ID 83703
E-MAIL:
mike(Dcleanenersyo pportunit ies.com
com
CERTIFICATE OF SERVICE
AUSTIN RUESCHHOFF
THORVALD A NELSON
AUSTIN W JENSEN
HOLLAND & HART LLP
555 ITTH ST STE 32OO
DENVER CO 80202
E-MAIL: [e-mail]
[e-mail]
awj ensen@hollandhart. com
aclee@hollandhart. com
gl garganoamari@hollandhart. com
JACK VAN VALKENBURG
VAN VALKENBURG LAW PLLC
PO BOX 531
BOISE ID 83701
E-MAIL: [e-mail]
JIM SWIER
MICRON TECHNOLOGY INC
SOOO S FEDERAL WAY
BOISE ID 83707
E-MAIL: [e-mail]
JIM KREIDER
STOP B2H COALITION
60366 MARVIN RD
LA GRANDE OR 97850
E-MAIL: [e-mail]
-bl"Z-^SECRETARY
CERTIFICATE OF SERVICE