20251112Comment_1.pdf

From: Mike Heckler<[e-mail]>
Sent:Wednesday, November 12, 2025 12:12 PM
To: secretary<[e-mail]>
Cc: Courtney White <[e-mail]>; kelsey
<[e-mail]>
Subject: CEO comments IPC-E-25-23
Please accept the attached comments from Clean Energy Opportunities for Idaho (CEO)
regarding the Idaho Power Company 2025 Integrated Resource Plan.
Thank you for your time and attention to this matter.
Sincerely,
Mike Heckler

wClean Energy Opportunities fortdaho
November 12, 2025
Reference: Case No. IPC-E-25-23, Idaho power's 2025 IRP
Subject: Comments of Clean Energy Opportunities for Idaho
Clean Energy Opportunities for Idaho ("CEO") appreciates having had an opportunity to serve on the 2025
IRP Advisory Council. CEO also appreciates the commitment of Idaho Power's IRP team to thoughtfully
inform the IRPAC and respectfully receive input throughout the process of developing this IRP. CEO offers
our congratulations to the IRP Team on submission of its continuously improved 2025 plan.
CEO strives to put forward win-win solutions that advance clean energy and to serve the long-term interests
of Idahoans. From our perspective, the size of some new very large customers, the magnitude of their
combined load growth and the availability of new resources types warrant continued adaptation of traditional
IRP methods in the next IRP. With that focus in mind we offer the following comments to address
opportunities we see for continuing to improve the resource planning process in the 2027 IRP iteration.
Table of Contents
Solar and Batteries have changed resource cost patterns. "Flat"loads are no longer the lowest
costto serve...................................................................................................................................................................... 1
Energy costs are now lower at mid-day,higher at night................................................................................................................................1
Ample capacity exists mid-day all year long,lowest cost to serve is mid-day......................................................................................3
Implications for improvements in the 2027IRP. ................................................................................................ 4
Implications for organizational interplay and price-based DSM.................................................................................................................4
Implications for load reduction benefits analysis-tighten the focus on the highest risk periods..............................................5
Implications for price-based DSM opportunities-an hourly vs seasonal orientation.....................................................................5
Implications for the use of IRP related models for rate design and pricing inputs.............................................................................6
Both the capacity and energy benefits of price-based DSM should be modeled...................................................................................7
Solar and Batteries have changed resource cost patterns.
"Flat" loads are no longer the lowest cost to serve.
Energy costs are now lower at mid-day, higher at night.
One fundamental implication of the growing level of solar on the grid relates to how new solar resources
have changed the traditional cost to serve analysis, with implications on how the 2027 plan process should
address opportunities and values for shifting the timing of load.
1

1P Clean Energy Opportunities for fdaho
Key insights gained from the 2023 and 2025 IRP analyses show that load flattening can result in higher
costs while load shifting into certain day hours can lower costs. In preparing the 2023 IRP,the Company
modeled a "Load Flattening" scenario to compare costs if demand shifted from peak demand hours into
lowest demand hours. That scenario shifted load to night-time hours and resulted in higher portfolio costs.
In the 2025 IRP,the Company modeled a "Load Shift" scenario that moved load out of the 6-10pm hours in
summer and into the 10am - 2pm hours when the supply of solar on the grid relative to demand creates an
ultra-low cost window. That scenario resulted in lower portfolio costs. The 2025 IRP projects a substantial
increase in reliance on market purchases in 2031, which augments the exposure to solar induced time
variation in market prices.
With Idaho Power's existing generation and transmission system resources, new "flat" loads are no longer
the lowest cost to serve load shape.' Figure 1 displays how forecasts of the 2027 marginal energy prices at
the Mid-C market vary significantly by hour. The energy component of the cost to serve incremental load is
clearly lower during mid-day than at any time overnight, in the evening or early morning hours.
Shifting load to mid-day can lower overall system costs, with lower energy costs as shown in Figure 1 and
available underutilized capacity during the mid-day as explained below.
2025 IRP estimates of 2027 Mid-C energy prices show lowest prices occur mid-day
Mid-C energy price$/MWh
to $100.00
a, $80.00
L
O
t
$60.00
t
$40.00
a
as
" $20.00
Gl
N $_
O
N E E E E E E E E E E E 0 E E E E E E E E E Et
N N M � 11 tD 00 M O N 0 rl N M -T Ln l0 11 00 C1 O '4
.4 .4 z
Hour Ending
Figure 1—2027 annual average energy prices at the Mid-C market, split out by hour of the day, as estimated in the 2025 IRP
'The Regulatory Assistance Project has published similar findings, stating "High penetrations of nondispatchable but
variable renewable generation means that a 100% load factor is unlikely to be, from a system perspective, the most
desirable load shape." (2020, June 16). Demand charges: What are they good for?
https://www.raPonIine.org/knowledge-center/demand-charges-what-are-they-good-for/ (p4)
2

1p Clean Energy Opportunities for fdaho
Ample capacity exists mid-day all year long, lowest cost to serve is mid-day
This 2025 IRP again demonstrates that as incremental load growth increases the need for capacity
resource these capacity constraints occur during a limited number of hours of the year Such capacity
constraints are negligible during most hours of the year.
In Figure 2 below, the estimated 2027 LOLE peak hourly risk values for each day were sorted by month and
then displayed showing the distribution of those hours of peak loads across each month. For example,
looking at the month of January the value of"10" in hour ending 8 means that of all the 31 days in January
the peak hourly risk occurred ten times during the 7:00-7:59am hour. Green cells show hours when no daily
peak occurred. Note that in no month of the year did any peak load risk occur between 10:00am and
4:59pm.
CEO interprets this lack of peak load occurrences between 10:00am and 4:59pm to suggest that, not only
are energy prices low at mid-day all year long, there is also available capacity to serve more load during
some mid-day hours all year long. The ability to serve more load during periods with the lowest incremental
energy costs and without needing to add generation and/or transmission capacity to do so has substantial
implications for the value of load shifting that CEO explores in the implications section further below.
Month of the year
Jan Feb Mar Apr May Jun Jul Aug SEP OCT NOV DEC
1 2 1 1
2 2 1 1
3 1 1 1
4 2 2
5 1 3 3
6 1 1 1 2 1 1
7 2 2 6 5 1 1 1
8 4 5 5 4 2 5 n 5
9 4 7 7 4 1 2 8 3
bA 10 1 1 4 1
C
11
12
13
14
15
16
17 1 1 1
18 1 1 3 4
19 5 7 1 1 1 6
20 3 2 1 1 3 1 3
21 3 2 2 1 1 1 1 7 5 5
22 1 1 6 3 3 1 6 23 10 3 3 2
23 1 1 5 1 2 1 1 1
24 3 5 5 1 7 4
Figure 2—Shows daily peak 2027 loss of load estimates sorted by the hour of the day when they occurred in each month. Red
values show hours when the daily peak risks were most concentrated, occurring in that hour 8 or more times during the month.
3

`0" Clean Energy Opportunities for idaho
Implications for improvements in the 2027 IRP.
Implications for organizational interplay and price-based DSM.
CEO notes that Salt River Project expanded their IRP perspective from a resource planning to an Integrated
System Planning2 level-
"Given the rapid pace of disruptive change in the power sector, planning decisions across the
system must be coordinated from end to end to identify the best path forward for customers."
Among those disruptive changes, the third is:
"As the share of solar generation in SRP's portfolio increases over time, daytime energy will become
increasingly abundant and lower the value of conservation during this period. This will have direct
impacts on how we think about the value of future customer programs and the design of our future
time-of-use price plans."
As outsiders, it is unclear to CEO what organizational team is accountable for recommending the IPC-
specific, price-based instruments that are the best demand-side candidates for improving portfolio costs.
CEO has been told that "the IRP Team does not consider rate design matters" although the IRP process
has previously modeled TOU as a selectable demand-side resource. The regulatory team has led
implementation of TOU options for customer classes, but these TOU rate designs seem unrelated to the
price-based DSM programs recommended by EEAG for modeling.
CEO is not proposing any specific means for addressing cross-functional interplays. That said, CEO
encourages the [PC team to utilize Company-wide expertise in the 2027 planning process to ensure that the
portfolio of options modeled reflect the most significant and feasible demand-side opportunities for
minimizing future customer cost increases.
Based on CEO's observations, the most recent AEG report was poorly suited for recommending price-
based DSM options that will prove the most likely to be cost effective for inclusion in a system-wide
resource planning process. CEO believes future analyses by AEG or other consultant could be improved
by providing the contractor with a different set of cost and benefit assumptions. The AEG report also
excluded TOU opportunities for Irrigators, Commercial, Industrial, or large load customers. CEO sees this
exclusion as a significant deficiency.
If presented with adequate time-of-use pricing incentives Irrigators could decide whether to size a pump to
run 24/7 vs a larger pump that could avoid running in high cost periods. Residents could weigh whether to
pay more for programmable EV chargers. Businesses could make tradeoffs regarding cooling equipment,
and customers evaluate whether behind-the-meter storage and/or back-up generation is merited.
Given the growing potential for demand flexibility and behind-the-meter storage, all customer classes should
be evaluated for their ability to shift load timing from periods of high system costs to periods where that load
would cause fewer system costs.
2 Integrated System Planning
4

`0" Clean Energy Opportunities for idaho
Before starting the formal 2027 IRP process, thoughtful principles should be reviewed to guide what price-
based DSM options are modeled as selectable resources, load forecast modifiers, or sensitivities analyses.
Sensitivities could inform ad hoc decisions, such as valuing a revenue-neutral default TOU for residents or
commercial customers, or valuing the benefits of greater enrollment in an existing program. Incremental and
incentivized programs might continue to be best modeled as selectable resources. The interplay between
rate design and load forecasts may call for modeling price-based DSM as a load modifier (e.g., if a load
forecast assumes rapid EV growth, that should be paired with efficient price signals to incentivize low-cost
time windows for EV charging).
Implications for load reduction benefits analysis — tighten the focus on the highest risk
periods.
Again in this IRP iteration the Company has used a 0.1 loss of the ability
to serve load events per day per year as its reliability hurdle value. To Table6. Monthly LOLE percentage
calculate these LOLE values the 8760 individual hourly loss of load Month LOLE Percentage
estimates are first sorted into 365 individual daily groupings and then the January 5.9%
highest risk hour is selected for each day. This stratified sampling February 0.7%
approach can obscure the substantial differences in loss of load risk March 0.0%
across different seasons. By giving an equal weighting to each day of the April 0.0%
year one could conclude that capacity adequacy risks are more or less May 0.0%
equally distributed across all months of year. That is clearly not the case. June 9.0%
July 69.6%
August 4.4%
In examining LOLP hourly data estimated in the 2025 IRP for the year September 0.3%
2027 CEO found that by sorting the 8760 hourly risk estimates from high October 0.0%
to low, the 365th observation has a higher risk level than the risk level November 8.6%
estimated for any hour in January, February, March, April, May, August, December 1.5%
September, October or December. Most months risk estimates are not Total 100.0%
relevant to analyses of incremental capacity needs
Figure 3—Shows monthly distribution of reliability
risk as estimated by the LOLE method.
The data shown in Figure 3, taken from page 16 of Appendix D of the 2025 IRP, show that 2/3rds of the
total year's risk of loss of load occurs in July. If you add in the risk estimates from June and November the
total for those three months approaches 90% of the annual risk exposure.
The adequacy of existing generation and transmission resources to serve rising loads is most highly tested
in just three of the twelve months of the year. Stated another way, incremental load increases during
certain hours in July (and to a lesser extent in June and November) are likely to cause a need for additional
generation and/or transmission resources. Similar load increases in other months are not likely to require
resource additions.
Implications for price-based DSM opportunities — an hourly vs seasonal orientation.
As displayed in Figure 4 below, the current perspective on how marginal costs vary is largely oriented on a
seasonal basis. CEO suggests that AEG or other consultant be given a different or, at least an alternative,
perspective on how marginal energy and capacity costs are spread across the hours of the year.
5

IP Clean Energy Opportunities for fdaho
CEO believes that many businesses may have more capability to change when during the day the business
performs energy intensive processes than to try to change the season of the year when such process
adjustment occurs.
Figure 4 shows a comparison of two methods for distributing marginal energy and capacity costs across the
year. Both use color to display relative cost levels, with green showing the lowest cost hours, yellow
intermediate costs, orange showing periods with both an energy as well as an allocated capacity cost but at
a lower risk (and thus a lower cost) level and red with both energy and high capacity risk cost.
The left in Figure 4 displays the traditional avoided cost allocation method, which first sorts the year into
summer, winter and offseason periods and then looks to how costs vary by time of day. On the right in the
figure is an alternative distribution which CEO believes better reflects the marginal energy and capacity
costs in this new "solar and batteries" environment.
CEO believes any analysis recommending DSM alternatives should, at the least, model price-based TOU
alternatives using the alternative diurnal cycle focused cost distribution in any report used in the 2027 IRP
Traditional seasonl cycle Alternative diurnal cycle
focused cost distribution focused cost distribution
Month of the Year Month of the Year
J F M A M J J A S O N D J F M A M J J A S O N D
1
2
3
4
� 5
6
7 7
8 8
buo 9 9
10 10
11 11
12 12
13 13
14 14
2
15 15
16 16
17 17
18 18
19 19
20 20
21 21
22 22
23 23
24 24
Figure 4—In both images hours colored green are lowest marginal cost,yellow show intermediate cost levels, orange are lower
capacity risk periods and red are high capacity risk periods.
Implications for the use of IRP related models for rate design and pricing inputs.
The 2025 IRP headliner would be that new large load customers are changing the magnitude and
composition of resource additions. Like many stakeholders, we are disappointed that the 2025 IRP adds
new fossil fuel resources to meet the accelerated growth of new special contracts. Here, we'd like to focus
on points related to special contract terms going forward.
6

40 Clean Energy Opportunities fortdaho
With regard to new large load additions, mitigation of future costs requires anticipation of demand flexibility
options in the evaluation and negotiation of terms for those new additions.3 IRP analyses might better
inform those negotiations. One improvement for the 2027 IRP iteration would be to clearly display the hours
where there remains existing capacity to serve additional load without pushing LOLP to unacceptable
levels. This IRP output could be used to help design load and rate alternatives that could allow the new
customers to either interconnect sooner or receive lower energy and demand rates to reflect the lower
incremental energy and capacity costs they are causing.4
Marginal energy and capacity costs vary by hour of the year such costs clearly are not "flat" in all hours of
the year. Including in the 2027 IRP data outputs showing forecasted marginal energy price seasonal and
diurnal patterns could help inform rate schedules with marginal energy costs.
Also, IPC's policy has been to exclude revenue-neutral price-based DSM programs for consideration in
resource planning. Revenue reduction associated with successful load shifting from high cost to low cost
hours is treated as a cost of the program. CEO believes any revenue impacts can be very short-term (they
can be remedied in the next GRC) while the load shifting mechanism may involve a capital expenditure that
could provide benefits for multiple years. A short-term reduction in revenue should not be used to exclude
consideration of programs that could reduce system costs over a multi-year period. Further, we suggest—
when modeling price-based DSM alternatives—that the design and assumptions for such programs be
clearly presented.
Both the capacity and energy benefits of price-based DSM should be modeled.
Finally, when modeling the cost/benefits of load-shifting on the supply side, e.g. batteries, the IRP portfolio
costs reflect not only peak reduction but also the frequent benefit of charging during low-cost hours and
discharging during high-cost hours. Load-shifting on the demand side also yields energy cost benefits which
should be reflected in IPC's modeling of price-based DSM alternatives.
Thank you for your consideration of these comments. Respectfully submitted,
Courtney White Michael Heckler
Managing Director Policy Director
"'E.g., a 2025 Harvard Law School publication describes: [C]utting peak consumption can reduce costs for everyone if
utilities build their systems for a lower peak that accounts for a data center's ability to turn off or self-power. The
problem is that utilities are expanding based on an assumption that data centers will operate at full power with utility-
delivered power during peak periods. When a data center uses its own generation during peak periods to avoid
demand charges, it is shifting the costs of an overbuilt system to the public." Martin, Eliza, and Ari Peskoe. Extracting
Profits from the Public:How Utility Ratepayers Are Paying for Big Tech's Power. (p19).
https://eelP.law.harvard.edu/wp-content/uploads/2025/03/Harvard-ELI-Extracting-Profits-from-the-Public.pdf
'E.g., American Electric Power(AEP)filed a contract including a substantial demand response program for Google, as
reported 8/6/2025 in Power Magazine: "When the grid is under stress, Google will reduce or shift its electricity
consumption at the Fort Wayne data center, thereby helping I&M lower peak demand, reduce its own capacity and
transmission needs, and deliver system-wide cost and reliability benefits." https://www.powermag.com/google-im-
strike-landmark-deal-to-share-clean-capacity-and-flex-ai-load/
7