20241202Comment_1.pdf

From: Courtney White<[e-mail]>
Sent: Monday, December 2, 2024 4:09 PM
To: secretary
Subject: Public Comment Submission for IPC-E-24-07
Please find attached my public comment submission for IPC-E-24-07.
I acknowledge that submitting a comment in an open case constitutes a public record
under Idaho Code § 74-101 (13) and all information provided by me on this form is available
for public and media inspection. My comment may be reviewed by the utility.
I am an Idaho Power customer.
Thankyou,
Courtney White
[e-mail]
Mailing Address:
3778 N Plantation River Dr, # 102
Boise ID 83703

To: The Idaho Public Utilities Commission
From: Courtney White
Re: IPC-E-24-07 Public comment submission
Date 12/2/2024
With an interest in decelerating the need for future rate increases, Clean Energy Opportunities (CEO)
agreed in the Settlement to IPC-E-23-11 (Idaho Power's 2023 General Rate Case) to lead workshops on
certain topics such as hourly informed rate design. Attached for visibility is the IPC-E-23-11 Follow-Up
Report on Hourly Informed Rate Design, which CEO shared with those parties in association with a
November 2024 workshop. On this page are a few high-level findings followed by a recommendation:
• Supply-Side costs: It is getting spendier to control the hourly shape of supply-side resources, thus
costs are increasingly associated with the timing at which load occurs.
• Demand Flexibility: The opportunities to modify the hourly shape of demand-side load curves are
growing. Nationally, the potential for cost-effective load flexibility is projected to grow to a magnitude
representing -20% of peak loads by 2030.
• Savings Potential: Correspondingly, the financial savings achievable via time-varying rates and other
demand-side programs is huge, as reported by the Department of Energy (DOE):
Managing all available flexible demand represents potential savings of nearly $13B per year.
These benefits come from managing flexible demand DERs through mechanisms such as
smart thermostat demand response, commercial demand response, and time-varying rates
that reshape load curves. (DOE 2023 Report, p32)
Given Idaho represents -1% of U.S. electricity, as a rough indicator of magnitude, the potential
savings above would scale to $130 million per year for Idaho if proportionate.
• Capturing that value requires better price signals. Per Brattle, "New regulatory incentives will be a
primary driver of growth in load flexibility, due to renewed industry-wide interest in regulatory models
that encourage utilities to pursue demand-side initiatives rather than capital investment in
infrastructure."
• High cost AND Low cost windows: In addition to on-peak time windows associated with high costs,
a low cost time window is emerging. From -10am to 2pm throughout the year, the marginal cost of
serving load is exceptionally low. Other utilities are introducing "Super Saver" or"Matinee" rates to
attract load into low cost hours.
Recommendation
Idaho Power's load growth is accelerating, and so should the use of demand-side opportunities to influence
the timing of loads and thereby decelerate the cost additions which lead to future rate increases. Cost
effective load shifting is not encouraged by flat rates, high monthly service charges, demand charges set by
a customer's monthly peak, or when a time-of-use tariff offers too little difference between on-peak and
off-peak (such as the -'/z cent difference in current non-residential TOU rates). I recommend that the
Company's next General Rate Case filing reflect steps forward to improve the long-term affordability of
electricity via rate designs that provide effective, time-varying price signals across hourly loads.
Respectfully,
Courtney White
Attached: IPC-E-23-11 Follow-Up, CEO Report on Hourly Informed Rate Design
Clean Energy Opportunities for Idaho

IPC-E-23-11 Follow-up
CEO Report on Hourly Informed Rate Design
Distributed to parties in advance of 11/13/2024 Workshop
Please note that Section II directly ties to topics proposed for interactive discussion Nov 13, 2024.
PREFACE 3
Cut to the Chase - What exactly would CEO like to see happen? 3
I. Big Picture: Momentum toward demand-side load shaping 4
A. Demand Flexibility & "Rate-Based DR" are increasingly important (NARUC, DOE) 4
B. Two Sectors with notable potential for Demand Flexibility -
Data Centers & Buildings 5
C. Emergence of a low-cost time window 7
D. TOU Trends: More initiatives, more "Super Saver," more default, more choices 8
II. TOU Rate Design: Issues & options for discussion 9
For reference: TOU tariffs and price ratios for Idaho Power customers 9
A. What is the opportunity for a Super Saver time window? 10
B. Non-Residential On Peak v Off Peak Rates: Opportunities to improve? 13
1. Is the current price difference motivating? 13
2. How does the price difference compare to forecasted market prices? 13
3. How does the price difference compare to other utilities? 13
C. Options for moving toward more meaningful price signals in non-residential tariffs 14
D. Should Irrigators have access to an opt-in Time of Use rate? 19
III. Evidence informing issues previously raised regarding TOU 21
A. How big a problem is it that customers might save $ under TOU w/o changing behavior? 21
B. What are common approaches to ensuring cost recovery under TOU rates? 22
C. What is the status of Performance Based Regulation (PBR) in the context of DSM? 22
D. Do customers respond to price signals? Is the scale of impact material? 23
Clean Energy Opportunities for Idaho

PREFACE
Cut to the Chase - What exactly would CEO like to see happen?
We've heard the request for CEO to speak specifically to our own objectives, which have been shaped by
what we've heard and learned. In sum, the evidence strongly shows that price signals play an increasingly
critical role in achieving both clean and affordability goals. Below are near-term priorities we envision:
1. Expand Demand Side Management to include load shifting opportunities. As NARUC describes,
"While traditional EE [Energy Efficiency] program design generally encourages customers to reduce
electricity consumption at any and all times, advanced EE and DF [Demand Flexibility] applications
offer signals to shift when electricity is consumed."' [bold added]. For example -
a. In the IRP: In addition to demand-side options for lowering overall loads and reducing peak loads,
the Company's Integrated Resource Planning should also model programs which capture the
benefits of shifting load into lower cost to serve hours.
b. Responsibility for proactively crafting and evaluating the Company's rate-based demand side
management and demand flexibility programs should be clarified.
2. The Company should systematically define low-cost "Super Saver" hours in conjunction with its
process for reviewing "On Peak" hours. This would inform rate design. Among utilities, many
emerging tariff options are purposed not only to shift load out of"On Peak" hours but to attract load
into exceptionally low-cost hours when marginal costs are low given ample solar on the grid. These
are referred to as Super Saver, Matinee, or Super Off-Peak rates.
3. In the next General Rate Case the Company should propose more meaningful TOU tariffs for
commercial, industrial, Special Contract and potentially for irrigator customers.
a. Such tariffs should include a "Super Saver" time window with below-average volumetric prices.
b. Such tariffs should include a greater difference between the highest and lowest volumetric prices
(the current difference is -1/2 ¢ per kWh).
c. In the absence of improvements to the high-to-low price differential in existing non-residential TOU
rates, any rate increase requested in the next GRC for special contracts, Schedule 9, or Schedule
19 customers should be solely allocated across load occurring during On-Peak hours.
d. No special contract should be entered or renewed without meaningful price signals to reflect high
cost/ high risk time windows as well as low cost time windows.
4. Cost Recovery. If moving forward with more meaningful price signals is impeded by concerns
regarding revenue collection for the Company, we suggest the launch of a collaborative process for
considering Performance Based Regulation (PBR) with regard to Demand Side Management. There is
an early yet growing momentum toward PBR as an instrument to better align the utility's financial
motives and the public benefits of DSM. The groundwork for PBR can take years to develop.2 If existing
mechanisms for ensuring cost recovery are insufficient, we recommend intentional steps forward to
consider PBR.3
Demand Flexibility within a Performance Based Regulatory Framework, NARUC 2023
2 For example, in the NARUC report, lessons from experience recommend that time is needed to collect data and consider a wide
number of potential metrics so commissions can determine the most appropriate.
3 For example, a Working Group or Task Force might be assigned with specific objectives.An early step could be a series of 1-hour
lunch webinars offering Q&A with subject matter experts.
Clean Energy Opportunities for Idaho

I. Big Picture: Momentum toward demand-side load shaping
As summarized in a recent report to NREL, "Demand flexibility is an increasingly important but
underutilized capability for utilities and wholesale market operators to use in balancing electricity supply
and demand.114 While it is getting spendier to control the hourly shape of supply-side resources, there are
increasing opportunities to modify the demand-side shape of the load curve. The section below first
describes the scale and national emphasis on demand flexibility then delves into a few trends of interest.
A. Demand Flexibility & "Rate-Based DR" are increasingly important (NARUC. DOE)
"Demand Flexibility" (DF) is defined as the capacity of demand-side loads to change their consumption
patterns hourly or on another timescale. Per the National Association of Regulatory Utility Commissioners
(NARUC):'
A system with more variability on the supply-side can be supported by more responsive
demand-side resources. Specifically, leveraging [Demand Flexibility] technologies can enable
customers to reduce, increase, shift, or modulate electricity usage to support grid stability, to lower
costs, and to create a more efficient system.
Brattle estimates the potential for cost-effective load flexibility to grow to a magnitude representing
-20% of peak loads by 2030.E The financial potential is substantial, as reported by the Department of
Energy (DOE):'
Managing all available flexible demand represents potential savings of nearly $13B per year. These
benefits come from managing flexible demand DERs through mechanisms such as smart
thermostat demand response, commercial demand response, and time-varying rates that reshape
load curves.
Given Idaho represents -1% of U.S. electricity, as a rough indicator of magnitude, the potential savings
above would scale to $130 million per year for Idaho if proportionate. The savings are only projected to
occur if regulatory frameworks adapt to leverage demand flexibility.
An expanded definition of DR. In our research, we often saw Demand Response (DR) categorized into
two categories: "Rate-based" DR, and "Dispatchable" or"Direct Load Control" DR. NARUC notes that
demand side management programs are advancing to include load shifting:'
While traditional EE [Energy Efficiency] program design generally encourages customers to reduce
electricity consumption at any and all times, advanced EE and DF [Demand Flexibility] applications
offer signals to shift when electricity is consumed.
a Incentive Mechanisms for Leveragina Demand Flexibility as a Grid Asset,by Guidehouse, prepared for NREL, p5
' Demand Flexibility within a Performance Based Re ulg_atory Framework, NARUC 2023
s The National Potential for Load Flexibility:Value and Market Potential Through 2030 (brattle.com), p2
'Pathways to Commercial Liftoff:Virtual Power Plants(energy.gov), p32
s Demand Flexibility within a Performance Based Regulatory Framework, NARUC 2023
Clean Energy Opportunities for Idaho

B. Two Sectors with notable potential for Demand Flexibility -
Data Centers & Buildings
Data Centers. "Data centers could consume up to 9% of U.S. electricity generation annually by 2030."9
This rapid growth is creating challenges at a state and national level. Fortunately, the demand flexibility
potential for data centers is high if incentivized. As E3 reports:10
Data centers can commit to flexible load plans to accommodate grid limitations and avoid lengthy
upgrade timelines. For example, facilities can leverage the temporal and spatial flexibility of certain
Al workloads (e.g., model training) and schedule batch data processing to optimize power usage
around renewable energy availability and total system load.
Google actively deploys load-shifting in order to manage costs as well as use cleaner energy":
Since 2020, we've used our carbon-intelligent computing platform to shift compute tasks and their
associated energy consumption to the times and places where carbon-free energy is available on
the grid.
...Now, we can use this task-shifting capability for demand response —temporarily reducing power
consumption at our data centers to provide valuable flexibility when it is needed, to help local grids
continue operating reliably and efficiently.
Workload Management
Meta is active in initiatives regarding load flexibility as a (Section4)
means of addressinginterests in both clean & Energy Storage
(Section 3)
affordable energy.12 Research co-authored by Meta, Renewables
Stanford, Harvard, et.al. describes opportunities to (Section 2)
manage computational load data in ways that align Future of Sustainable
Datacenters(Section S)
with time-varying supplies of renewable energy.13 The
paper notes that hourly tracking and workload Renewable Utilization
management are the "Future of Sustainable Annual Energy Matching
Datacenters," as illustrated to the right. carbon Offsets Hourly Tracking
Figure 1: Sustainability solutions are interdependent with
each other and a coordinated solution with fine grained mea-
surements(hourly tracking)is necessary to reach a carbon-
optimal solution and to improve renewable utilization.
To harness this potential demand flexibility, appropriate tariffs are essential. A DOE report,
Recommendations on Powering Artificial Intelligence and Data Center Infrastructure, includes the
following:"
1) analysis to demonstrate the benefits and costs of flexibility, 2) the flexibility taxonomy, 3) policy
and contractual advances to enable and support flexibility, and 4) model tariffs for data centers and
other large loads that incentivize both efficiency and flexibility/demand response capabilities. Due to
accelerating investments in data centers, the sooner the better for standard requirements.
9 EPRI launches data center flexibility initiative with utilities, Google, Meta, NVIDIA. Utility Dive Oct 30, 2024
10 Load Growth is Here to Stay but are Data Centers, p23.
11 Using demand response to reduce data center power consumption I Google Cloud Blog
12See also, EPRI Launches Initiatives to Enhance Data Center Flexibility to explore"how data center flexibility can support the
electric grid, enable better asset utilization, and support the clean energy transition."
13 Carbon Dependencies in Datacenter Design and Management, p1
14 Recommendations on Powering Artificial Intelligence and Data Center Infrastructure, Presented to Secretary of Energy 7/30/24
Clean Energy Opportunities for Idaho

Buildings (Residential & Commercial)
Over the next two decades,national adoption of GEBs could
The Demand Flexibility of buildings, both be worth between $100-200 billion in U.S. electric power
residential and commercial, is widely noted. system cost savings. By reducing and shifting the timing of
To scope the magnitude of potential, the electricity consumption,GEBs could decrease CO2 emissions
DOE evaluated the electric power savings
by 80 million tons per year by 2030,or 6%of total power sector
potential of Demand Flexibility and
Grid-Interactive Efficient Buildings (GEB) co emissions.That is more than the annual emissions of SO
given a range of assumptions related to medium-sized coal plants,or 17 million cars.
adoption rates and demand flexibility
programs. The DOE found15 (to the right):
D•E's National Goalfor • the
-
Given Idaho represents -1% of the energy efficiency and demand - • of
electricity consumed in the U.S., this DOE buildings s- . by - - to 2020 levels.
estimate would scale to $1-2 billion in
potential savings for Idaho if proportionate.
A report from Guidehouse to NREL emphasized that capturing the value of Demand Flexibility was
particularly driven by state regulators.16
State regulators hold substantial power in how the grid operates, and approaches vary widely
across the country. Where demand flexibility and DERs are valued by regulators and policymakers,
grid operators and utilities are expanding how and where they leverage demand flexibility
The DOE highlights the role of both price-based programs and resource planning to capture the benefits of
demand flexibility, as reflected from this excerpt of DOE recommendations 17:
Develop innovative incentive-based programs
Expand price-based program adoption
Introduce incentives for utilities to deploy demand-side resources
Incorporate DF into resource planning
The evidence suggests that for Idaho Power's Integrated Resource Planning:
• The demand response potential for special contracts, which includes data centers, is greater than zero
• There are opportunities for rate-based demand side management that could be further explored.
1s A National Roadmao for Grid-Interactive Efficient Buildings(Ibl.aov), DOE, May 2021, p1
16 Incentive Mechanisms for Leveraging Demand Flexibility as a Grid Asset, by Guidehouse, prepared for NREL, p2
An Implementation Guide for Utilities and Policymakers, by Guidehouse for NREL, May 2021
17 A National Roadmap for Grid-Interactive Efficient Buildings(Ibl.govl, p18
Clean Energy Opportunities for Idaho

C. Emergence of a low-cost time window
The rising portion of solar on the grid is CAISO Fuel Mix across 24 hours a o
creating daily time windows which are low cost 8/14/2024
to serve. A recent example of CAISO fuel mix
across 24 hours on an August day (2024) 0-1 Batteries
illustrates the ample solar during mid-day hours Imports Solar
and the dispatch of batteries in the eve as solar _ Wind
drops off:18
IO GW
°aw
14 ..A I/1'M Y'M AuU
eN,cka,eGiioth—al/Bromass*3,ogas @lasga Hydro•Small Hydro•Coal�NaW,ai Gas @W.nd 6Battmes/Imports Irl
Looking ahead, the supply of
solar relative to demand is 2023 Summer Peak Day 2038 Summer Peak Day
forecasted to row during 16,000
g g ■ Storage resources Surplus renewables
mid-day hours as illustrated 14,000 Battery storage charge storage Energy storage
Y ■ resources during discharges in
_ Variable resources daytime evenings
in this excerpt to the right 12,000 Wind,solar,distributed energy,energy efficiency
from APS 2023 Integrated Firm resources
Nuclear,coal,natural gas,microgrids
Resource Plan. In that IRP, 10,000 _ oenmnd
Variable resources
meet large shares of
APS introduces the goal of 4 8,000 daytime energy needs
Demand Side Management T 6,000
by highlighting load shifting o 4,000
into peak solar hours:19 =
2,000
By focusing efforts to 0 PM11
shift customer energy 1 Hour of Day 24 1 Hour of Day 24
usage from high
demand hours to parts of the day where resources are more plentiful, the Company can save
customers money and further support the efficient operation of the grid.
The above load patterns correlate with a window of exceptionally low market prices around 10am-3pm. The
chart below (left) from an October 2024 Brattle report on BPA Day-Ahead Market Participation illustrates
this pattern across multiple markets as forecasted for 2032. The chart to the right presents forecasted
Mid-C market prices based on Idaho Power's IRP analysis for the period 2026 through 2030, for which
we've calculated averages by hour and season.20
BPA Day-Ahead Weighted Average Sales Price by Hour of Day
$/Mwh —BAU —EDAM —Markets+ Mid-C Forecast Prices for 2026-2030 averages by Hour and Season
$70 " $/MWh "Winter"
$60 8o Nov/Dec/Jan/Feb
$50 '° rummer
$40 6° Jun-Sefi r
$30 %
$20 r `�---
°
$10 Spring:
l° Mar/Apr/May
$0
to
12:00 2:00 4:00 6:00 8:00 10:0012:00 2:00 4:00 6:00 8:00 10:00
AM AM AM AM AM AM PM PM PM PM PM PM °
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
brattle.com 1 12 Hour
'$https://www.gridstatus.io/graph/fuel-mix?iso=caiso&date=2024-08-14
19 APS 2023 IRP, P21
20 IPC-E-24-23 Attachment 4 IRP Mid-Columbia forecast, CEO calculation of averages
Clean Energy Opportunities for Idaho 7

D. TOU Trends: More initiatives, more "Super Saver," more default, more choices
More Initiatives: The deployment of time-varying price signals is accelerating. In 2021, there were over
150 rate design policy initiatives in addressing new time-of-use (TOU) tariffs.21 That acceleration is most
typically attributed to the rise of low-cost windows, though other factors include:
• The growth in Electric Vehicles is prompting both customers and utilities to take more interest in
TOU rate options.
• The deployment of AMI smart meters has enabled time varying rates
• The investment in AMI has been viewed by some as creating an obligation to better leverage the
investment
More Super Saver rates: "More and more utilities are beginning to offer TOU rates with exceptionally low
off-peak rates.1122 The time windows for these exceptionally low rates are evolving and varies across the
country with some incentivizing loads into overnight hours while others incentivizing hours of high solar
production. For example, APS defines super off-peak hours as 10 AM-3 PM on weekdays during the winter
months (November—April), while "SRP's Daytime Saver Pilot allows customers to access cleaner, more
affordable energy when they shift their electricity use to super off-peak hours— between 9 a.m. and 3 p.m.
every day."23
More default TOU: The shift toward default or opt-out TOU was noted in Brattle's 2019 Survey of
Residential Time-Of-Use (TOU) Rates:`
Historically, TOU rates have been offered to residential customers on an opt-in basis
However, with the deployment of smart metering, there has been a gradual shift toward default or
mandatory TOU offerings
Opt out TOU tariffs are not as common as opt-in, though the trend has continued. Countries such as
Canada, Italy, and Spain have implemented default TOU. Utilities or states with - or on a track to
implement - default TOU include California IOUs, SMUD in California, Xcel Energy & Fort Collins in
Colorado, the two biggest IOUs in Michigan, Hawaiian Electric, and PSEG Long Island in New York.
In Missouri, the Commission's order to implement default residential TOU rates reflects a dissatisfaction
with the low enrollment for opt-in TOU:25
Evergy's opt-in approach is based on the recommendation to provide its customers with the option
of selecting the rates that work for them. Under this approach, Evergy's base default rates would be
the standard flat rates. One of the primary benefits of AMI is the ability to provide customers with
TOU rates. Given eight years of experience with AMI, millions of dollars invested in AMI across
Evergy's footprint and many studies regarding TOU rates, the Commission is concerned with taking
the status quo approach that currently reflects only minimal (1.1%) residential adoption of TOU
rates.
With regard to the appropriate price differentials for an opt-out TOU, Faruqui recommends:21
21 Utility Dive, 2022 Outlook:A new recognition is coming of rate design's critical role in the energy transition. This figure includes
time varying EV tariffs.
22 Ahmad Faruqui and Ziyi Tang, Time-varying rates are moving from the periphery to the mainstream,August 2023, Draft chapter
of forthcoming Handbook on Electricity Regulation, p21
23 SRP Website-Price Plans
21 A Survey of Time of Use Rates, Brattle, slide 15
25 https://efis. sp c.mo.gov/Document/Dis laay/114242, In the Matter of Evergy Metro, Inc. d/b/a Evergy Missouri Metro's Request for
Authority to Implement a General Rate Increase for Electric Service, November 21, 2022, File No. ER-2022-0129, p66.
26 March 2024 Post to Utility Management Group, Should Time-of-Use Rates Be Made the Standard Tariff?,
Clean Energy Opportunities for Idaho

Ideally, the ratio should range between 2 and 3 to provide customers an opportunity to save money
but it should not go above 3.
Growth in Commercial, Industrial, & Irrigator TOU rates
We do not have a comprehensive survey of TOU for non-residential customers, though it may exist. The
deployment of TOU for non-residential is neither rare nor universal. First hand, we've come across
commercial TOU rates in 15 states. Examples of utilities with default TOU for certain commercial customers
includes -
• Pacific Gas & Electric
• Southern California Edison
• Con Edison
• Florida Power& Light
• Xcel Energy
• Duke Energy
In general, we observe the ratio of peak to off peak prices for non-residential TOU tariffs tend to be less
than for residential and higher than Idaho Power current non-residential TOU tariffs.
More choices. When one peruses tariffs across utilities, it's notable that many are offering expanded
choices. Many readings speak to the logic that customers are more satisfied and likely to respond to price
signals when they are not constrained to a one-size fits all. Given Faruqui's prolific publications regarding
rate design, this comment was striking:27
If you were to ask me, what is the most important advice I have about reforming tariffs, I will say it's
giving customers choice of tariffs.
II. TOU Rate Design: Issues & options for discussion
For reference: TOU tariffs and price ratios for Idaho Power customers
For context, below is a brief summary of current access to TOU rates among Idaho Power customers. In
this report, we use TOU to refer to rates which vary by hour of the day.
Sched Customer Class TOU is TOU No On-Peak/Off-Peak
Default Option TOU Price Ratio,
Summer
5 Residential TOU ✓ 4
9P Large General Service - Primary ✓ 1.1
9S Large General Service - Secondary ✓ 1.1
19P Large Power Service - Primary ✓ 1.1
19S Large Power Service - Secondary ✓ 1.1
24 Irrigators ✓ n/a
26, 29, 30, 32 Micron, DOE, Simplot ✓ n/a
33 Brisbie ✓ 1.1
27 Faruqui Linked In Post
Clean Energy Opportunities for Idaho

A. What is the opportunity for a Super Saver time window?
Currently, Idaho Power tariffs include On-Peak and Mid-Peak hours, with all other hours set at an Off-Peak
rate. Some utilities are offering Matinee pricing, Mid Morning discounts, Super Off Peak or Super Saver
windows. Objectives include -
• Better align with marginal costs
• Encourage beneficial load shifting
• Improve customer satisfaction and enrollment by enabling more options to manage energy costs28
An important note with regard to rates and cost causation: A customer class's share of costs for the
purpose of cost recovery is usually based upon an historical test year- a backward looking perspective. A
forward looking perspective is needed to inform price signals and to correlate how future customer
behaviors affect both cost recovery and future cost causation.
The seasons and hours for a TOU tariff are informed by marginal energy costs and capacity requirements
often estimated via Loss of Load Probability (LOLP) analyses. These future capacity requirements drive
future resource additions. LOLP analyses have been deployed by the Company in determining TOU time
windows. We would highlight that an opportunity for improvement is to systematically define a Super Saver
time window, which could inform rate design. For example, a super saver window could be useful in moving
toward a greater differential between the lowest and highest price windows for commercial, industrial, and
special contracts.
The following charts intend to inform these considerations. Our assumptions include:
• Given the degree of difference in hourly future marginal costs is substantially different than historic,
Mid-C Market prices by hour better reflect the range and pattern of future marginal costs than the
traditional marginal energy cost analysis the Company has used.
• The Mid-C Market price forecast of 2026-2030 is a relevant time window.
• The pattern of average LOLP by hour is indicative of the fluctuation in risks which drive future
capacity needs. For this, we calculated average LOLP by month and hour using the six years of
8760 test data (Source: Response to Staff PR request 34b, IPC—E-23-14).
• We did not account for holidays or Sundays in our calculations.
• All data is from Idaho Power, all averages are calculated by CEO and are not weighted by loads.
28 Faruqui, 2020, Moving Ahead with TVR, Lessons Learned - "Unless new rates have savings opportunities, customers will either
not join or not alter their usage habits to respond. Savings opportunities can be maximized by discounting off-peak prices
substantially compared to the existing rate"
Clean Energy Opportunities for Idaho

Market Prices & LOLP by Hour and Month
Before collapsing data into seasons, the following two charts illustrate patterns across 24 hours of the day
for all 12 months. Observations include:
• Both market prices and LOLP are relatively low every month of the year from mid-morning to mid
afternoon
• A Spring season stands out with exceptionally low market prices and negligible LOLP
• LOLP is exceptionally high in July &August
• Lowest loads, which occur at night, do not correlate with lowest marginal costs. This suggests Demand
Side load-shifting should strive to shift load into low-cost hours rather than low-load hours.
Mid-C Forecast Prices for 2026-2030 average by hour by month
90 $/MWh u----------II
u
Winter = II
80 IF
"Double Lines 11
11 Dec 11
70 �1 Feb I �t --------------
II Jan _ ; Summer=
60 ILNol q / ;Qash-Lines
------- - --50
Spring:
40 �� - _�� Mar/Apr/May
30 _ 1 ����� / Jan Feb
� J
® Mar —Apr
20 �� -_ - May Jun
Jul Aug
10 Sep —Oct
—Nov —Dec
0
2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 16 19 20 21 22 23 24
Hour ending
Source:8760 Mid-C data from 20231RR sourced from IPC-E-24-23,CEO calc of averages
LOLP by average by hour by month
°
0 —Jan
_Feb
0 —Mar July
- Apr Summer
0 May Months =
--Jun Dash Lines
Jul Spring:
0 Aug Mar/Apr/May
Sep Negligible LOLP
Aug
0 —Oct
Nov N� D2C Sep
0 —Dec 1 1
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour ending
Source:8760 LOLP data from IPC response to Staff PR 34b,IPC-E-23-14;CEO ca/c of avg for 6 testyears
Clean Energy Opportunities for Idaho 11

Market Prices and LOLP by Hour & Season
IPC Tariffs typically define Summer as Jun- Sep and Non Summer as all other months. For purposes of
illustration with more granularity, these carts present data for Winter (Nov-Feb) and Spring (Mar-May).29
The first chart below illustrates forecasted Mid-C market prices (2026-2030) by hour of the day for these
three seasonal divisions, which are indicative of hours of low margin costs. A relatively low price window is
evident every season of the year. The chart further below suggests capacity is sufficient during this Super
Saver time period as indicated by Loss of Load risks.
This presents an Low-Price Windows given Mid-C Forecast Prices for 2026-2030 averages by Season
opportunity for
90 ..........................................:
seasonally defined
Within 24 hours of
Super Saver rates or 80 Winter: the day,9am-3pm= _
Relatively low price
for a shorter Super 70 Nov Dec/Jan/Feb :
' yearround
Saver time period that
........................................................
remains consistent all 60
....................................................................
year. So — Winter Lowest price /
Summer
e H rs:9am-4pm
40 ® .....................................................
f
Spring:
30 Mar/Apr/May Summer Lowest price —Winter Dec/Jan/Feb
H rs:8 a m-3pm —Spring Mar/Apr/May
20 ...................................................................
......................................................................................... ——Summer
Spring Lowest-price Hrs:
8am-5pm
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hourending
Source:20231RP Data,sourced from IPC-E-24-23,CEO calculation ofaverages
LOLP average by Season (avg for 6 test years,IPC-E-23-11)
Time Windows for Summer and Non-Summer(N/S)TOU
0 $/MWh Summer SummerOn
Winter MidPeak Peak
0 3-7pm 7-11 pm
—Spring
—————
Mar/Apr/May lh\
0 \
Summer r-------------- --------- � \
N/S On 10am-3p i m is N/S On \ Summer
\
Peak relatively low Peak rI \ r
6-9am LOLP year round j 5-8pmam
Winter LOLP:
Spring LOLP: `
Nov/Dec/Jan/Feb Mar/Apr/May \
(negligible) \\
2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour ending
Source:8760 LOLP data from IPC response to Staff PR 34b,IPC-E-23-14;CEO calc of avg for 6 testyears
CEO proposes that a Super Saver (or otherwise named) time window be systematically defined and
monitored in conjunction with Idaho Power's periodic review of On-Peak hours.
29 For purposes of illustration, these three seasons do not include October, which has low LOLP similar to spring yet
relatively higher market prices. Those months might be combined into a Shoulder Season.
Clean Energy Opportunities for Idaho

B. Non-Residential On Peak v Off Peak Rates: Opportunities to improve?
Currently, the differential in volumetric charges between summer on-peak and off-peak for commercial,
industrial, and Brisbie Time of Use rates is about '/2 cent per kWh, or a ratio of 1.1 between the highest and
lowest rates. We propose that a greater differential would be beneficial, either in standard or optional tariffs.
Below we speak to:
1. Is the current price difference motivating?
2. How does the price difference compare to forecasted market prices?
3. How does the price difference compare to other utilities?
1. Is the current price difference motivating?
After reaching out to customers and running some numbers, we find that the current '/z cent differential
between on-peak and off-peak does not provide a meaningful economic incentive for load shifting. For
example, consider that - in order to save $100 - a customer would need to shift 20,000kWh. On average,
Schedule 9S customers consume 85,000 kWh/yr ( Source: IPC-E-24-07, pdf p74).
2. How does the price difference compare to forecasted market prices?
As described earlier, we used 2023 Mid-C price forecasts for 2026-2030 as an indicator of the future
marginal cost differences by hour. These prices are not intended to represent today's cost per hour, they
are indicative of the pattern and degree of difference across hours. For summer, across a 24 hour
weekday, the chart below illustrates two sample C&I TOU rates (Large General Service Secondary 9S, and
Schedule 33 Brisbie/ Meta) relative to average forecasted hourly Mid-C prices.
Comparison of sample summer rates relative to Avg Hourly Mid-C Prices for 2026-2030,
Summer(Jun-Sep)
90
80 =h$/MW
Schedule 9S
70 Commercial Opt-In
60 TOU rate, Summer
50
40 a
30 —Meta(Sched 33) ` -------- f Brisbie / Meta
20 —Sched 9S TOU ;------------------t Summer Energy
Mid-C Avg ; Summer Rates
Mid-C Avg prices
Hourending --------------------
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Source:8760 Mid-C data,2023 IRP Data,sourced from IPC-E-24-23;CEO calc of averages
3. How does the price difference compare to other utilities?
Clean Energy Opportunities for Idaho 13

The bar chart to the right below provides a sampling of business tariffs with on-peak and off-peak
volumetric rates30. This is not a comprehensive review of tariffs. It does, though, suggest that where there
are TOU of rates there tends to be a higher difference in on to off peak prices.
One opportunity is to include a Sample Ratios of On-Peak to Off-Peak Energy Rates,C&I
Super Saver window of lower 1.0=Flat Rate
than average prices. For scoping ' _ 4
purposes, the bottom bar reflects Avista TOU w/Morning Discount NonRes-WA(93) 4.2
a ratio of forecasted Mid-C prices XCELCommercialSchadC-CO 2.7
for summer On-Peak hours DukeEnergy-Commercial-FL -1.8
divided by forecasted Mid-C RMP-Optional IrrigationTOU-UT 3.5
prices for a potential "Super RMP Large General Service Default-LIT(8) -2
Saver" window of 1Oam-3pm. PGE Large Nonresidential General Service-OR(85) -j:q
This results in a ratio of 2.3 for APS Large General Service E-32 TOU-AZ M1 3
summer, 1.7 for winter. ■Summer
IPC Large General Service Optional TOU(9S) '
IPC Industrial(1 9S) '�:� ■Winter or N/S
IPC Meta(Schad 33)
IPC Irrigators(Sched 24)
Avg Mid-C for On Peak(7-11 pm)/Super Saver(10am-3pm) 2.3
1.7
C. Options for moving toward more meaningful price signals in non-residential tariffs
For purposes of discussion, we pose four options (not mutually exclusive) -
a. Revise the Company's Marginal Cost study methodology to use forward looking data such as
forecasts of future energy market prices.
b. Incorporate a Super Off-Peak window, in some or all months.
c. Allocate costs currently classified as Production & Transmission Demand to volumetric rates
occurring on-peak.
d. As a transitional step: For any customer class requiring a revenue increase in the next General
Rate Case, only increase the on-peak volumetric rates for the purposes of meeting the increased
revenue requirement.
Options a, b, & c are addressed below.
Option a: Revise the Marginal Cost study methodology
Currently Idaho Power uses a ratio derived from its marginal cost study to augment On-Peak energy
charges (x 1.07) and discount Off-Peak energy charges (x 0.94). This is described in the excerpts below
from their 1/4/2024 presentation and in the rate design workpapers submitted in IPC-E-23-11.
so Sources:XCEL, Duke, RMP, APS, IPC, PGE,Avista
Clean Energy Opportunities for Idaho

Time-of-Use Rate Design `I PO11�R
Cost-of-Service Informed Rates
Schedule 19 Unit Cost Sheet Schedule 19 Non-Summer TOU Rate Derivation
Non-Summer Energy 3.1574¢/kWh ___ __ _ __ _____
On-Peak 22% ;1.0129¢; ;3.4397¢14.45260
Marginal Cost ' ' Mid-Peak 22% ;1.0129¢1 13.211501 4.22440
Off-Peak 57% 11.212 i i.. ..... 4.0414¢
On-Peak:Mid-Peak 1.07x Weighted Average 100% 1.01290 3.15740 4.17030
Off-Peak:Mid-Peak 0.94x
Demand-Related Collection Energy-Related Collection
through Energy Charge through Energy Charge
Note:Residential • Average non-summer energy rate- CCOS non-summer unit cost
• CCOS unit cost weighted for billing determinants
general,,- •, ,!• TOU price signal forand marginal cost differentials to
optional • , largerlartificial 4.1703-3.1574=1.01290 send price signal per marginal cost
differentials were used to create a price signal study
18
NPSE-Marginal Price Differentials Scheduleand 19
Summer(June-September) Total Hours %of Total $/MWh Price Ratio
Off-Peak 2,001 68% $ 37.42 1 0.839
Mid-Peak 515 18% 44.60 i 1.000
On-Peak 412 14% 44.80 i 1.004
..................
Summer Average 2,928 100% $ 39.72
Non-Summer(October-May) Total Hours %of Total $/MWh I Price Ratio
Off-Peak 3,396 58% $ 45.44 0.94-3
Mid-Peak 1,218 21% 48.18 1.000
On-Peak 1,218 21% 51.61 1.071
..................
Non-Summer Average 5,832 100% $ 47.30
The forward looking ratio of Mid-C On-Peak summer prices relative to 10am-3pm prices is 2.3 or a delta of
-4 cents/kWh. Though not an apples to apples equivalent, we believe revising the methodology for
calculating marginal price differentials would result in higher differentials.
Option b: Incorporate a Super Off-Peak window, in some or all months.
As described earlier, the marginal costs of serving loads during mid morning to mid afternoon are low and
declining, prompting utilities to introduce Super Saver tariffs. In this section we provide examples of the
impact on Schedule 9S tariffs to incorporate a Super Saver rate in a revenue neutral manner. These reflect
the following assumptions:
• Establish a Super Saver time window. Three examples are provided to illustrate impacts, including a 4
hour window in Summer, a 6 hour window in Summer, and a 6 hour window year round.
• Set the Super Saver rate at 3 cents/kWh (the energy portion of Off-Peak energy costs)
• The decline in revenue requirement associated with a Super Saver window is spread across On-Peak
kWh such that the change is revenue neutral.
• Revenue requirements and loads were sourced from Exhibit No.2 (p13 of 36) in the IPC-E-23-11
Settlement Agreement.
• These analyses focus on Schedule 9S TOU for illustration.
Clean Energy Opportunities for Idaho

Summer Super Saver Illustrations: Two charts below isolate the impact of a 4 hour or a 6 hour Super
Saver window relative to current Schedule 9S TOU summer volumetric rates to rates. The 4-hour Super
Saver window results in a -3¢/kWh increase during the On-Peak window, the 6-hour Super Saver window
results in a -4.5¢/kWh increase. The ratios of On-Peak to Super Saver prices are 2.8 and 3.3 respectively.
Illustrative TOU Options for Scoping&Discussion:
Option b1: Create a Super Saver Rate, Shift revenue requirement to On-Peak kWh
Schedule 9S Summer TOU Rates
$/MWh — — — — — — -
$so
$70 Delta in revenue —30 increase
requirement is allocated
$60 to On-Peak kWh
Current Summer per kWh Rates
$50
$40 Change =Create a Super —20 decrease
$30 Saver Rate at 3¢ ------ - — — — — — — -
$20 Super
Saver
$10 Off Peak 10am-2pm Mid Peak On Peak
$0
1 2 3 _ 6 7 8 9 6 '. _ -. 9 20 21 22 23 24
Illustrative TOU Options for Scoping&Discussion:
Option b2: Create a Super Saver Rate, Shift revenue requirement to On-Peak kWh
Schedule 9S Summer TOU Rates
$/MWh
S,,o — — — — — — -
s80 Delta in revenue —4.50 increase
requirement is allocated
s60 from to On-Peak kWh
Current Summer per kWh Rates
s,0 Change =Create a Super —26 decrease
Saver Rate at 3¢ ----1 — — — — — — — — -
Super
Off Peak Saver Mid Peak On Peak
9am-3pm
s 9 10 - - - - 19 20 22
These illustrations are intended to benchmark singular changes and represent no change to demand
charges or mid-peak rates. CEO would suggest that only three price tiers would be appropriate: the lowest
(Super Saver here), middle (combining Off-peak & Mid-peak), and highest (On-Peak).
Year-Round Three Price Approach: An alternative revenue neutral approach for Schedule 9S would be to
define three price levels applied year round - Super Saver, Average, and On Peak. Below is an illustration
assuming a Super Saver window of 9am-3pm all year, On-Peak rates in Winter (Nov-Feb, rather than
Non-Summer) at 6am-9am & 5pm-8pm, On-Peak rates 7pm-11 pm in Summer, and Average rates all other
hours.
Clean Energy Opportunities for Idaho

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
6aF
c\�0 5.1 cents/kWh 5.1 cents/kWh
5.1 cents/kWh
gaF
9.2 cents/Kwh 9.2 cents/Kwh
ba
3.1 cents/kWh
aF
A
eye
5.1 cents/kWh 5.1 cents/kWh 5.1 cents/kWh
5-6pm
6-7pm 9.2 cents/Kwh 9.2 cents/Kwh
7-8pm
8-9pm
9-10pm 9.2 cents/Kwh
10-11pm 5.1 cents/kWh 5.1 cents/kWh
11-Midnight 5.1 cents/kWh
Winter Shoulder Summer Shoulder Winter
Option c: Allocate costs currently classified as Production & Transmission Demand
to volumetric rates occurring on-peak
CEO favors rate design that allocates costs currently classified as Production & Transmission demand to
volumetric rates occurring on-peak. The strawman below is a benchmark analysis of the impact of
allocating 25% of revenue requirements associated with demand to on-peak kWh. This 25% results in a 2:1
ratio of On-Peak to Off-Peak prices per kWh.
Illustrative TOU Options for Scoping&Discussion:
Option c: Spread 25% of Demand Requirement across On-Peak kWh
Schedule 9S Summer TOU Rates
$/MWh
Demand Charges decrease by 25%,
On-peak rates increase from 5.5 to—10O/Mi � —
Highest to lowest price ratio=2 255 — — —
%of
Demand
Spread
across On-
Peak/kWh
Current Summer Energy Rates
$20
Off Peak Mid Peak On Peak
$0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour
The merits of recovering generation and transmission capacity costs via on-peak volumetric charges are
further explained below.
Clean Energy Opportunities for Idaho

Currently, for most of Idaho Power's non-residential tariffs, the customer's singular measure of peak load
during a month drives demand charges, which are intended to recover certain distribution, transmission,
and generation capacity costs. The changing dynamics of cost to serve by hour and the availability of more
granular data indicate an opportunity for more meaningful price signals. Issues with the current approach of
recovering generation and transmission capacity costs via monthly demand charges include:
• To align price signals with cost causation, the hour at which demand occurs is relevant. Customer
peaks do not necessarily occur
during system on-peak windows What hours does demand drive capacity costs?
and thus are not accurate LOLP by hour by month for Spring(negligible)&Summer July
indicators of bulk power system
cost drivers. LOLP, which
correlates with capacity cost
drivers, is illustrated to the right by Aug
Spring:
hour during summer& spring Mar/Apr/May ,Sep
months. Customer demand at Negligible f
^�.lun
9pm in summer, for example 1 ,-%_
Hour ending % _
------------------------------------• --_
drives transmission or generation , 2 3 q 5 6 8 9 11 12 13 14 15 10 17 1 Ito 20 21 22 23 24
capacity costs in a manner unlike I
Source:8760 LOLP data from/PC response to Staff PR 34b,IPC-E-23-14;CEO calc ofavg for 6 testyears
demand at 10am.
• The "ratchet" effect in Demand charges can be a disincentive to beneficial load shifting. E.g., consider
if a customer could ramp up production mid morning in order to shift load out of peak. That would
improve LOLP and could take advantage of times when marginal costs are exceptionally low, yet could
increase the customer's demand charge.
As described in Smart non-residential rate design:Aligning rates with system value31:
With today's technology, non-residential customers are rapidly becoming a distribution and bulk
power system resource that can mitigate system stress, offer services that help meet system needs,
and reduce costs for all customers, while also reducing the non-residential customers' own electric
bills. Whether it's a supermarket allowing its freezers to "coast through" a few key hours, or an office
building using an ice storage air-conditioning system, the value of flexible load is critically important
to today's utilities.
The primary impediment to unleashing non-residential resources is obsolete rate design. A
non-coincident peak demand charge and a flat all-hours energy charge (typically modified by a flat
all-hours fuel and purchased power adjustment rate) send a perverse price signal that deters
non-residential resources from becoming valuable grid resources.
A lesson drawn from the 2023 IRP was that load flattening did not improve costs because the scenario
shifted load into night time with no low-cost solar on the grid. Industry cost dynamics have changed such
that incentives to flatten loads are less appropriate than incentives to shape loads.
31 Carl Linville &Jim Lazar, The Electricity Journal. Jan 2018.
Clean Energy Opportunities for Idaho

D. Should Irrigators have access to an opt-in Time of Use rate?
To inform that ongoing consideration, we add the following observations of sample TOU offerings.
In Oregon, Pacific Power offers irrigators an opt-in July-September
TOU for which, "You receive a credit for the number All Days
of kilowatt-hours of electricity you use during off-peak
hours and an additional charge for the electricity you
use during on-peak hours." The peak charge addition
12
is 4.989¢/kWh, the off-peak credit is -0.992¢/kWh.
Off-Peal< —off——off-P-1k
6a.m. �, :6' 2p.m. 6p.m..�';, 10p.m. 6a.m.
In Utah, Rocky Mountain Power33 offers
IRRIGATION SEASON RATES:
irrigators an opt-in TOU tariff with a
relatively high on-peak to off-peak price The Power Charges set forth below are for power costs related to the service drop
and the distribution system.
ratio of 3.5. On-peak hours are 9am to
Customers Not Participating in Time-of-Day Program
8pm. We believe this 11-hour definition of
on-peak hours is inconsistent with low Power Charge:
$7.14 per kW
mid-day marginal costs and also would
Energy Charge:
be less appealing to Idaho irrigators. 7.11260 M kWh first 30,000 kWh
5.25730 per kWh all additional kWh
The Monthly Customer Service charge Voltage Discount: Where Customer provides and maintains all transformers and
other necessary equipment,the Voltage Discount will be:
for RMP above is $14. $2.05 per kW
Minimum: The Monthly Customer Service Charge plus the Power and Energy
Charges.
Time-of-Day Program
Power Charge:
$7.14 per kW
Energy Charge:
On-Peak: 14.05200 per kWh
Off-Peak: 4.04920 per kWh
Voltage Discount: Where Customer provides and maintains all transformers and
other necessary equipment,the Voltage Discount will be:
$2.05 per kW
In California, though different dynamics are at play, there's a longer history of offering TOU as standard for
agricultural rates. For large utilities such as PG&E, several rate choices have evolved as customers have
provided ongoing feedback. For example":
AG-F (Flex) is a flexible rate option available for agricultural businesses that can limit
operating hours to two off-peak days per week (Wednesday and Thursday, Saturday and
Sunday or Monday and Friday). This rate plan has peak hours from 5 p.m. to 8 p.m. on five
days per week instead of seven.
32 https://www.pacificl2ower.net/savinas-energy-choices/time-of-use.html
33 Irrigation and Soil Drainage Pumping Power Service, RMP UT, Schedule 10
34 PGE Brochure for Agricultural Customers
Clean Energy Opportunities for Idaho

In Arizona, APS offers Irrigators a TOU rate with a high-to-low price ratio of 1.5 in Summer. In Arizona,
Super Off Peak time period occur in winter, 10am - 3pm.
APS TOU for Agricultural Water Pumping
tl aps RATE SCHEDULE E-221 AG TOU
CLASSIFIED RATE
AGRICULTURAL WATER PUMPING SERVICE—TIME-OF-USE
Summer Winter
Energy Charge On-Peak $0.11298 $0.11298 per kWh
Energy Charge Off-Peak $0.07760 $0.07760 per kWh
Energy Charge Super Off-Peak $0.03577 per kWh
Bundled Charges
Basic Service Charge(only one applies)
Self-Contained Meter $ 1.286 per day
Instrument Rated Meter $2.238 per day
Primary Meter $5.484 per day
Demand Charge—On-Peak $4.762 per kW
For reference: Idaho Power Schedule 24 excerpt26
SECONDARY SERVICE In-Season Out-of-Season
Service Charge,per month $30.00 $6.00
Demand Charge,per kW of
Billing Demand $14.06 n/a
Energy Charge
All kWh 5.72650 6.72880
TRANSMISSION SERVICE In-Season Out-of-Season
Service Charge,per month $415.00 $6.00
Demand Charge,per kW of
Billing Demand $13.27 n/a
Energy Charge
All kWh 5.48490 6.42150
Among Idaho Power irrigator customers, interests vary. For some, crops with needs for 24-hour irrigation
provide little latitude for load shifting. Some growers, however, have expressed an interest in a TOU rate as
an option to improve the costs for crops with more flexible irrigation requirements and in general to allow a
new means of managing electricity costs which represent a high portion of production costs.
-------------------------------------------------
3eAPS Schedule E-221 AG TOU Agricultural Water Pumping Service
36 https://docs.idahopower.com/pdfs/aboutus/ratesregulatory/tariffs/42.pdf
Clean Energy Opportunities for Idaho

In sum, several changes prompt a need to adapt tariff structures. The proportion of energy on the grid from
solar is rapidly growing, which drives up the relative cost of serving certain hours while also creating time
windows which are lower cost to serve and for which new loads could improve utilization of sunk costs.
Meanwhile, technologies are increasing the ability of customers to modify the timing of their loads. As the
company adds new costs to serve rapid growth, steps forward are needed such that price signals reward
the customer demand-side behaviors that align with near-term and long-term system benefits.
III. Evidence informing issues previously raised regarding TOU
A. How big a problem is it that customers might save $ under TOU w/o changing behavior?
Evergy, a vertically integrated IOU operating in Kansas and Missouri, was asked to evaluate this question
about a recently implemented TOU program. Direct testimony for the utility reports the following and
references analysis by Guidehouse:37
Q: How has Evergy demonstrated that participants changed behavior as a result of transferring to
the TOU rate and that they are not merely "free-riders"?
A: Evergy has demonstrated that participants did adopt behavior changes as a result of transferring
to the TOU rate and that participants (in general) were not free-riders. A free-rider is a term often
used in a context of energy efficiency— it means that a participant would have undertaken the
measure anyway without any incentive. In the case of TOU, a free-rider can be described similarly—
a participant that benefited by switching to the TOU rate with no behavior change influenced by the
utility.
As supported by Guidehouse on Page 7 of the final EMW
"Evergy's Stipulation Agreement specifies that Evergy must demonstrate that customer enrollment in
the TOU rate is not driven entirely by customers whose load profiles enable them to realize windfall
gains by simply transferring to the TOU rate without effecting any additional changes in behavior.
Such a situation would be easily identifiable in the results of Guidehouse's evaluation: if customers
only enrolled in the program in anticipation of windfall gains without any intention to undertake
behavioral changes, the evaluation would report material bill impacts without any commensurate TOU
period energy impacts. In fact, as shown in this report, participants in nearly all segments in both
jurisdictions demonstrated behavioral response to the TOU pricing in line with the incentives it
provides, specifically: average reductions in consumption during the highest price on-peak periods.
Enrolled participants have exhibited behavioral response to the TOU rates in line with the incentives
embedded in that rate."
CEO would further suggest that derogatory terms like "free rider" or"gaming" should not be used with
regard to who does or does not benefit from a TOU tariff. On the contrary, it is arguable that customers with
load profiles that are less favorable than average and that remain on flat rates are being subsidized by
other class members.
37 htti2s://efis.12sc.mo.gov/Document/Display/82717, Exhibit 82, p10-11, ER-2022-0129 Winslow Direct, Jan 7, 2022
Clean Energy Opportunities for Idaho

B. What are common approaches to ensuring cost recovery under TOU rates?
We acknowledge that maintaining a financially healthy utility is in the public interest. A common challenge
with rate design is when the utility's financial motives do not align with rates designed to defer costs as well
as allow customers bill savings. Brattle enumerates the options:38
Opt-in deployments create a revenue loss issue which has to be dealt with either through
decoupling (California), a Lost Revenue Adjustment Mechanism (Oklahoma), or building the
revenue loss into the TOU rate structure (Xcel Energy Colorado).
For opt-out rates, Evergy describes that the utility does meet revenue requirements yet there is typically
some regulatory lag requiring a periodic true-up to ensure rates align with revenue requirements.39
As described in APS 2012 Settlement Agreement4o:
In signing this Agreement, the Signatories intend that a Lost Fixed Cost Recovery ("LFCR")
mechanism with residential opt-out rates shall be adopted that allows APS relief from the financial
impact of verified lost kWh sales attributable to Commission requirements regarding EE and DG
while preserving maximum flexibility for the Commission to adjust EE and DG requirements, either
upward or downward, as the Commission may deem appropriate as a matter of policy.
The LFCR shall recover a portion of distribution and transmission costs associated with residential,
commercial and industrial customers when sales levels are reduced by EE and DG. It shall not
recover lost fixed costs attributable to other potential factors, such as weather or general economic
conditions. The LFCR mechanism shall exclude the portion of distribution and transmission costs
that is recovered through the Basic Service Charge ("BSC") and fifty (50) percent of such costs
recovered through non-generation/non-TCA demand charges.
Another approach described in the next section is Performance Based Regulation.
C. What is the status of Performance Based Regulation (PBR) in the context of DSM?
There is a growing momentum toward PBR as an instrument to better align the utility's financial motives
and the public benefits of DSM. NARUC refers to the nexus between demand management technologies
and PBR, concluding in its 2023 report41:
Implementing [Demand Flexibility] through an effective regulatory framework can lead to lower
customer costs, enhanced system stability, and reduced GHG emissions. PBR, combined with AMI
and advanced [Measurement &Verification], can advance effective DF models that encourage
customers to alter their electricity usage by reducing or shifting consumption.
NARUC characterizes the challenge (p7):
A traditional cost-of-service (COS) structure results in a "throughput incentive": a reduction in
volumetric retail sales by the utility negatively impacts profits.This paradigm can motivate a utility to
38 https://www.er)electric.com/files/html/Brattle-AMS%2OAdvisory%2OGroup°/`20Presentation 10052023.Ddf
31This is consistent with the reply of an Evergy representative when asked about impacts of TOU on revenue
ao httos://www.sec.gov/Archives/edgar/data/7286/000110465912012301/al2-3670 4ex10d17.htm, p10
41https://pubs.naruc.ora/pub/2A466862-1866-DAAC-99FB-EO54ElC9AB13? Ql=1*1k4kzaq* as*MTM1NDc0MzAxOS4xNzl5NDM2
NTQ2* ga_QLH1N3Q1NF*MTcyOTQzNiUONS4xLiEuMTcyOTQzNiY00S4wLiAuMA
Clean Energy Opportunities for Idaho 22

overinvest in capital resources to maximize opportunity for additional profits. Accordingly, the COS
structure can conflict with policy goals to advance [Energy Efficiency] and [Demand Management].
Per that report, 19 states and the District of Columbia have initiated—or are in the process of initiating—a
PBR framework for utility compensation. Hawaii, Vermont, and Colorado are at various stages of
exploration and implementation. Rather than further cite the report, we encourage any interested party to
review it. A relevant recommendation worth noting is that it can take years to adequately establish baseline
performance measures, thus the opportunity to implement PBR mechanisms in the future relies on
near-term steps forward.
D. Do customers respond to price signals? Is the scale of impact material?
The elasticity of response to price signals is well evidenced for residential customers. Per Brattle:42
We have shown beyond the shadow of a doubt that customers do reduce their peak load in
response to higher peak to off-peak price ratios. Price-based demand response is real and
predictable. It can be relied upon by utilities, regulators, independent system operators and other
market participants to plan their activities.
Brattle has built a database with meta analysis of 400 observations which correlates, for example, that a
TOU with a Peak to Off-Peak Ratio of 4:1 correlates with a peak demand reduction of 10%.43
As shown in figure_ below, responsiveness is greater when paired with technology such as programmable
communicating thermostats and information feedback.
The Arc of Price Responsiveness by Rate Design and Technology
40% (n=382)
c
CPP:Price With Technology
m TOU:Price With Technology
a 30% _
a`,
a PTR:Price With Technology
c
v 20% CPP:Price Only
0
TOU:Price Only
a
PTR:Price Only
loco 0 CPP = Critical Peak Pricing
TOU = Time of Use
PTR = Peak Time Rebate
0%
0 2.5 5 7.5 10 12.5 15
Rate Design Peak to Off-Peak Price Ratio
—TOU:Price Only(n=153) -----TOU:Price with Tech(n=52)
—CPP:Price Only(n=57) CPP:Price With Tech(n=50)
—PTR:Price Only(n=38) PTR:Price With Tech(n=32)
As an example, one utility recently scaled the potential for residential TOU as comparable to eliminating a
power plant. New York's Long Island Power Authority is following the lead of California, Colorado,
Michigan, and Missouri by shifting residents to an opt-out TOU. CEO Tom Falcone described41:
42 Ahmad Faruqui, Sanem Sergici, Cody Warner.Arcturus 2.0:A meta-analysis of time-varying rates for electricity, The Electricity
Journal, 30:10, December 2017, p68
43 Do Customers Respond to Time-Varying Rates:A Preview of Arcturus 3.0, Brattle, Jan 2023
44Brattle Q&A: Energy Leaders&Innovators Long Island Power Authority CEO Tom Falcone on Modernizing Residential Rate
Design, February 2024.
Clean Energy Opportunities for Idaho

As we add significant renewables to our supply and pursue high levels of beneficial electrification,
can we really do all we need to do with flat rates? In the future, we may need to do even more than
TOU, with managed charging or other programs. But these are very simple, easy-to-understand
TOU rate designs that move us in the right direction, and it's hard for me to see why this wouldn't be
a tool in the toolkit of every utility. We estimate that, if nothing else, we'll be able to reduce our peak
demand and the associated power plant capacity cost, by over 300 megawatts by 2030 —the
equivalent of getting rid of a power plant.
Idaho Power's 2024 peak load was 3.8 GW, LIPA's peak load is estimated to be 4.9 GW. LIPA is
implementing a TOU program estimated to reduce peak demand by 300+ MW by 2030, while in its 2025
IRP Idaho Power has suggested that the potential for TOU to reduce peak load is a mere 4 MW.45
Evaluations of numerous pilots are available. Brattle's evaluation of Maryland TOU pilots, for example,
reports that "TOU rates reduce peak demand in the summer season from 9.3% to 13.7% and by 4.9% to
5.4% for the non-summer season," adding "These results are comparable to the impacts estimated in other
pilots for similar peak to off-peak price ratios.1146
45 Slide 32, Energy Efficiency and Demand Response for the 2025 IRP, Idaho Power
46 piii, PC44 Time of Use Pilots-End of Pilot Evaluation, Brattle
Clean Energy Opportunities for Idaho