20211001Nesbitt Direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
APPROVAL TO MODIFY ITS DEMAND
RESPONSE PROGRAMS.

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CASE NO. IPC-E-21-32

IDAHO POWER COMPANY

DIRECT TESTIMONY OF

QUENTIN NESBITT

NESBITT, DI 1
Idaho Power Company
Q. Please state your name and business address. 1
A. My name is Quentin Nesbitt and my business 2
address is 1221 West Idaho Street, Boise, Idaho 83702. 3
Q. By whom are you employed and in what capacity? 4
A. I am employed by Idaho Power Company (“Idaho 5
Power” or “Company”) as the Customer Research and Analysis 6
Leader in the Customer Relations and Energy Efficiency 7
Department. I am responsible for overseeing the Company’s 8
analysis and reporting of all Demand-Side Management 9
(“DSM”) programs. I have been directly involved in the 10
operation of the Company’s Demand Response (“DR”) programs 11
in prior roles and was tasked to lead the team to redesign 12
them for the future based on my prior experience. 13
Q. Please describe your educational background. 14
A. I earned a Bachelor of Science degree in 15
Agricultural Engineering from the University of Idaho in 16
1989 and received my Professional Engineering license in 17
1992. 18
Q. Please describe your work experience with 19
Idaho Power. 20
A. I began my employment with Idaho Power in 1991 21
as an Agricultural Representative in the Company’s Energy 22
Management Department where I was responsible for providing 23
customer service to irrigation and agricultural customers. 24
Later in 1991, I was promoted to an engineering position 25
NESBITT, DI 2
Idaho Power Company
where I provided technical support for Idaho Power 1
Agricultural Representatives. This involved DSM program 2
design and operation, pump testing, new service requests, 3
investigation of high bills, and irrigation system 4
evaluation and consultation. In 2002, the department was 5
reorganized as the Customer Relations Department, and I 6
took on additional duties as the agricultural customer 7
segment advocate/expert where I coordinated Company 8
activities that affected agricultural customers. In October 9
of 2014, I was promoted to Energy Efficiency Program Leader 10
and was responsible for overseeing the Company’s Commercial 11
and Industrial (“C&I”) and Irrigation DSM programs. In June 12
of 2020, I accepted my current position as Customer 13
Research and Analysis Leader. 14
Q. What is the purpose of your testimony? 15
A. The purpose of my testimony is to explain the 16
Company’s proposed modifications to its DR programs that 17
will allow them to more effectively meet system needs. This 18
is based on updated analyses and methodologies used in the 19
Company’s 2021 Integrated Resource Plan (“IRP”) planning 20
process and discussed in further detail in Mr. Ellsworth’s 21
testimony. 22
My testimony will (1) provide a history and 23
background of the current DR programs, (2) discuss the 24
proposed program changes to meet the highest-risk hours 25
NESBITT, DI 3
Idaho Power Company
identified in the Loss of Load Expectation (“LOLE”) and 1
Effective Load Carrying Capability (“ELCC”) analyses 2
adopted for use in the upcoming 2021 IRP, and (3) outline 3
the Company’s proposed method for evaluating the cost-4
effectiveness of DR. 5
I. CURRENT DEMAND RESPONSE PROGRAMS 6
Q. How does Idaho Power design its DR programs? 7
A. The Company’s DR programs are designed to 8
minimize or delay the need to build new supply-side 9
resources. The DR programs are intended to reduce peak-hour 10
electricity demand, thus minimizing the need for selecting 11
supply-side alternatives that would only be needed for a 12
few hours. These potential hours typically occur during low 13
hydro generation and high load events, and the programs are 14
designed to be available to meet potential system capacity 15
deficits during these hours. The deficits are expected to 16
be relatively large in magnitude but short in duration. 17
Therefore, Idaho Power has determined it can be cost-18
effective for its customers to utilize DR programs rather 19
than building a supply-side resource that would only be 20
required to operate for a small number of hours. 21
Q. What are the DR programs the Company offers 22
and when were they established? 23
A. Idaho Power offers three DR programs available 24
to each of the three major customer classes. The first 25
NESBITT, DI 4
Idaho Power Company
program is the residential Air Conditioner (“A/C”) Cool 1
Credit Program that was started as a pilot in 2002 and 2
fully implemented in 2003. Customers’ A/C units, or heat 3
pumps, are controlled using switches that communicate via 4
powerline carrier, and the units are cycled by the Company 5
during an event to reduce load. 6
The second program is the C&I Flex Peak Program 7
(“Flex Peak”) that started in 2009 and was originally 8
managed by a third-party contractor. Idaho Power took over 9
full administration of the program in 2015, and C&I 10
customers that can offer load reduction of at least 20 11
kilowatts (“kW”) are eligible to participate. Participants 12
manually reduce their nominated load when Idaho Power calls 13
an event since direct load control devices are not utilized 14
within this program. 15
Last is the Irrigation Peak Rewards Program offered 16
to Schedule 24, Agricultural Irrigation Service, customers 17
in the Company’s service area. This program was established 18
in 2004 and allows the Company to interrupt irrigation 19
pumps during called events. It is Idaho Power’s largest DR 20
program in terms of capacity, and customers can participate 21
with either a manual or automatic dispatch option based on 22
the configuration of their equipment. 23
Q. Please summarize the recent demand reduction 24
and associated program costs of the Company’s DR programs. 25
NESBITT, DI 5
Idaho Power Company
A. Idaho Power’s DR portfolio capacity and costs 1
for the last five summer seasons are found in Table 1 2
below. As reported in the DSM Annual Reports since 2016, 3
the individual DR programs and the overall DR portfolio 4
have been cost-effective each year. 5
Table 1: 5-Year Summary of Demand Response Load Reduction, 6
Capacity and Cost by Jurisdiction 7
Year 
System 
Max Load 
Reduction 
(MW) 
Idaho 
Capacity 
(MW) 
Oregon 
Capacity 
(MW) 
System 
Capacity 
(MW) 
Idaho Total 
Cost 
Oregon 
Total Cost 
Total 
System 
Cost 
2020 336 346 20 366 $7,296,376 $418,536 $7,714,912 
2019 333 376 21 397 $7,808,979 $467,217 $8,276,196 
2018 359 367 16 383 $7,887,176 $282,243 $8,169,419 
2017 383 374 20 394 $8,339,892 $477,637 $8,817,529 
2016 378 372 20 392 $8,960,263 $511,104 $9,471,367 
8
Q. Please provide an overview of how the current 9
framework for the DR programs was established. 10
A. In December of 2012, prompted by the lack of 11
potential near-term peak-hour deficits identified in the 12
load and resource balance analysis prepared for the 2013 13
IRP, Idaho Power filed a request in Idaho (Case No. IPC-E-14
12-29) for authority to temporarily suspend two of its 15
three DR programs (A/C Cool Credit and Irrigation Peak 16
Rewards). In February of 2013, the Company filed the same 17
request in Oregon (Tariff Advice No. 13-04). The Flex Peak 18
program (previously called FlexPeak Management) was not 19
impacted by the Company’s request because it was under 20
contract with a third-party administrator at the time. 21
NESBITT, DI 6
Idaho Power Company
During the suspension of the two Idaho Power DR 1
programs, the Company worked with stakeholders in both 2
Idaho and Oregon through a collaborative workshop process 3
to evaluate and identify the best long-term solution for 4
either continuation or discontinuation of all three of 5
Idaho Power’s DR programs. This process resulted in 6
settlement agreements being reached in both states.1,2 7
The settlement approved by the Idaho Public 8
Utilities Commission (“Commission”) in Order No. 32923 will 9
be referred to as the Settlement Agreement. 10
Q. How does the Settlement Agreement dictate how 11
the DR programs currently operate? 12
A. Most notably, the Settlement Agreement 13
includes several program specific requirements, including 14
marketing limitations, the method for determining cost-15
effectiveness, and the Term of the Stipulation, as outlined 16
below.3 17
This Agreement shall be in effect 18
beginning on the date it is approved by 19
the Commission and shall apply to Idaho 20
Power's DR Programs for 2014 and beyond 21
until a change occurs in Idaho Power's 22
system operations or cost-effectiveness 23
of a DR Program that would warrant 24

1 In the Matter of the Continuation of Idaho Power Company’s (A/C Cool
Credit, Irrigation Peak Rewards, and Flex Peak Demand Response Programs
for 2014 and Beyond, Case No. IPC-E-13-14, Order No. 32923 (Nov 12,
2013).
2 In the Matter of Idaho Power Company Staff Evaluation of the Demand
Response Programs, Docket No: UM 1653, Order No. 13-482 (Dec 19, 2013).
3 Case No. IPC-E-13-14, Motion to Approve Settlement Agreement,
Attachment 2, pp. 2-3 (Oct 2, 2013).
NESBITT, DI 7
Idaho Power Company
reevaluation of the Agreement’s terms. In 1
such event Idaho Power will consult its 2
Energy Efficiency Advisory Group 3
("EEAG") and then make an appropriate 4
filing at the Commission. Similarly, a 5
party to this Agreement, may petition the 6
Commission to open a docket to reevaluate 7
the terms of this Agreement if Idaho 8
Power experiences a change in system 9
operations or the cost-effectiveness of 10
a DR Program so warrants. 11
As more fully described in Mr. Ellsworth’s 12
testimony, the Company believes it has experienced a change 13
in system need and operations since the Settlement 14
Agreement in 2013 and is therefore opening this case to 15
make necessary modifications to the DR programs. 16
Q. Have there been any major changes to the 17
Company’s DR programs since the Settlement Agreement in 18
2013? 19
A. There have not been significant changes to the 20
three DR programs in terms of how they operate from a 21
dispatchability perspective. However, a major change 22
occurred in 2015 when the Company took over the 23
administration of the Flex Peak Program from a third-party 24
administrator.4 This was done to increase administrative 25
efficiency, reduce the program’s cost to customers, and 26
provide transparency into the incentives paid to customers. 27

4 In the Matter of Idaho Power Company’s Application for Approval of New
Tariff Schedule 82, a Commercial and Industrial Demand-Response Program
(Flex Peak Program), Case No. IPC-E-15-03, Order No. 33292 (May 7,
2015).
NESBITT, DI 8
Idaho Power Company
II. Proposed Program Changes 1
Q. What are the overall parameter changes being 2
proposed to the Company’s three DR programs? 3
A. As informed by the LOLE and ELCC analyses 4
explained in Mr. Ellsworth’s testimony, the proposed 5
changes to the DR program parameters are meant to align the 6
programs to more effectively meet high-risk hours. Table 2 7
below summarizes the primary program components and 8
highlights the overall proposed parameter changes to the 9
Company’s DR portfolio. The available event days and 10
available event times vary slightly between individual 11
programs, but the table includes the full windows for all 12
programs combined. 13
Table 2: General Summary of Proposed DR Program Parameter 14
Changes 15
Parameter Current Program Proposed Program Change 
Season June 15th to August 15th  June 15th to September 
15th 
Season end date extended 
1 month to September 
15th 
Available Event 
Days
Weekdays and Saturdays 
No Sundays or Holidays 
(July 4th)
Weekdays and Saturdays
No Sundays or Holidays 
(July 4th & Labor Day)
No Change 
Includes the additional 
Labor Day Holiday under 
the expanded season 
Available Event 
Times  1:00pm to 9:00pm 3:00pm to 11:00pm Shifted start and end 
times by 2 hours 
Event Maximum Maximum 4 Hours per 
Day
Maximum 4 Hours per 
Day No Change 
Weekly 
Maximum
No More than 15 Hours 
in a Week
No More than 16 Hours 
in a Week
Increased weekly 
maximum by 1 hour 
Minimum 
Season Events 3 Events 3 Events No Change 
Season 
Maximum
Maximum 60 Hours for 
Program Season
Maximum 60 Hours for 
Program Season No Change 
16
NESBITT, DI 9
Idaho Power Company
Q. Please explain the rationale for each of the 1
overall changes. 2
A. The ELCC analysis showed that the program 3
season and the available event times were the variables 4
that had the largest impact on increasing the effectiveness 5
of the DR programs. Therefore, the program season was 6
extended one month from August 15th to September 15th to 7
capture high-risk hours later in the summer, and the 8
available event times were shifted two hours to capture the 9
shift in the highest-risk hours occurring later in the 10
evening. It is expected that as renewable resources, such 11
as solar, are added to the system, high-risk hours will 12
occur later in the day. 13
The weekly maximum hours the DR programs are 14
available were adjusted by one hour (from fifteen hours per 15
week to sixteen hours per week) to increase effectiveness 16
and to better align with the event duration maximum of four 17
hours. This change maximizes the availability of weekly DR 18
dispatch that Idaho Power’s Load Serving Operations (“LSO”) 19
group can utilize. 20
The available event days, the event maximum, the 21
minimum season events, and the season maximum are all 22
parameters that remain unchanged, as specified in Table 2. 23
Modifying these parameters were found to have a minimal 24
impact on increasing the ELCC of DR. 25
NESBITT, DI 10
Idaho Power Company
Q. Did the Company engage any stakeholders during 1
the development of the proposed changes? 2
A. Yes. The Company has held ten formal 3
touchpoints, plus several informal conversations with 4
stakeholders, to solicit feedback on the proposed DR 5
programs. The Company also conducted a customer survey with 6
current and potential DR program participants, which will 7
be discussed in further detail later in my testimony. Table 8
3 below shows the dates the Company engaged with Staff, 9
EEAG, the Integrated Resource Plan Advisory Council 10
(“IRPAC”), and customer groups during the process. Please 11
reference Exhibit No. 2 to my testimony for the invitations 12
to the customer seminars that were sent to all existing 13
Flex Peak and Irrigation Peak Rewards participants. 14
Table 3: Formal Stakeholder Engagement Touchpoints 15
Stakeholder Group Date 
IRPAC Meeting April 8, 2021 
Energy Efficiency Advisory Group Meeting May 5, 2021 
Idaho Public Utilities Commission Staff Discussion July 7, 2021 
Idaho Public Utilities Commission Staff Discussion August 9, 2021 
Oregon Public Utility Commission Staff Discussion August 9, 2021 
IRPAC Meeting August 10, 2021 
EEAG Meeting  August 12, 2021 
Flex Peak Program Customer Seminar August 31, 2021 
Irrigation Peak Rewards Customer Seminar August 31, 2021 
Idaho Irrigation Pumpers Association (“IIPA”) Meeting September 10, 2021 
16
Throughout the meetings, Idaho Power explained the 17
need for modifications to the DR programs, presented the 18
program parameters the Company was proposing to change, and 19
provided opportunities for stakeholder questions and input 20
NESBITT, DI 11
Idaho Power Company
regarding the changes the Company was considering. The 1
Company also discussed the proposed approach to evaluating 2
cost-effectiveness with both Idaho and Oregon Commission 3
Staff. 4
Q. What feedback did the Company receive from 5
customers at the seminars held on August 31, 2021? 6
A. Generally, customers indicated they understood 7
the need for the program changes during the Flex Peak 8
seminar. One Flex Peak participant shared that their 9
ability to provide load reduction may be less during later 10
hours, because their operations wind down at the end of the 11
day, indicating it may be more difficult to achieve the 12
same amount of reduction they have historically provided 13
during the earlier hours. Another participant indicated 14
that other utilities offer shorter windows for events 15
(i.e., two hours instead of four hours), and one 16
participant asked clarifying questions about the day-of-17
adjustment component of the baseline calculation. The 18
reasoning behind the minimum number of events was also 19
discussed. 20
The Irrigation Peak Rewards participants asked 21
several clarifying questions in their seminar about the 22
program parameters, whether they can opt into certain 23
participation time blocks, if time blocks will vary 24
throughout the season, how the incentives are calculated 25
NESBITT, DI 12
Idaho Power Company
and provided to participants, whether new pump sites will 1
be allowed to participate, and clarifying questions about 2
program notice requirements. 3
Program Dispatch Hours 4
Q. Did the Company receive additional feedback 5
from participants after the August 31, 2021 customer 6
seminars? 7
A. Yes. The IIPA contacted the Company and 8
requested an additional meeting to be held on September 10, 9
2021. After the Company presented its proposed program 10
approach, the IIPA suggested the Company look at the 11
effectiveness of having Irrigation Peak Rewards 12
participants split into groups based on dispatch times. 13
This included a group that would have a defined end time 14
and another group that would be available for all hours of 15
the proposed event time period. The suggestion was based on 16
the IIPA indicating that certain customers may prefer to 17
have a more defined time block due to their specific 18
irrigation equipment setup. 19
Q. Based on the IIPA’s suggestion, did Idaho 20
Power evaluate other dispatch design options? 21
A. Yes. The Company conducted an analysis using 22
three different scenarios that incorporated irrigation 23
groups in three additional ways. These scenarios were all 24
different from the original scenario the Company evaluated 25
NESBITT, DI 13
Idaho Power Company
in its ELCC analysis described in Mr. Ellsworth’s testimony 1
but were evaluated using the same methodology. The three 2
alternative design concepts were (1) all irrigation groups 3
being available from 6:00pm to 10:00pm, (2) a large portion 4
of the program capacity being available from 6:00pm to 5
10:00pm with a smaller portion occurring for four hours 6
sometime between 3:00pm and 11:00pm, and (3) a large 7
portion of capacity being available for four hours sometime 8
between 3:00pm and 9:00pm with a smaller portion occurring 9
for four hours sometime between 3:00pm and 11:00pm. 10
The results showed that each different scenario 11
reduced the overall effectiveness of the program in a 12
significant way. The third option had the least impact but 13
still had a reduction in effectiveness of approximately 10 14
percent. However, it is important to note that the 15
effectiveness of the third option would likely get worse 16
over time as more variable resources are added to Idaho 17
Power’s system, causing the hours from 9:00pm to 11:00pm to 18
become more critical. For this reason, Idaho Power is 19
proposing Irrigation Peak Rewards customers participate in 20
one of two possible options: (1) four hours sometime 21
between 3:00pm and 10:00pm, or (2) four hours sometime 22
between 3:00pm and 11:00pm. Having two options is 23
consistent with the current Irrigation Peak Rewards program 24
NESBITT, DI 14
Idaho Power Company
where participants can elect to participate until 8:00pm or 1
9:00pm. 2
Q. What were the results of the customer survey? 3
A. Idaho Power conducted a survey with current 4
and potential DR participants to gauge their ability to 5
participate in the DR programs with modifications to 6
certain program parameters. 7
For example, the survey sought to understand how 8
moving the dispatch hours later into the day would impact 9
customers’ ability or willingness to participate. Table 4 10
below outlines the results by customer class for one of the 11
questions asked in the survey. 12
Table 4: Percentage of Survey Respondents Able to 13
Participate During Proposed Program Hours (No Incentive 14
Consideration) 15
Percentage of Respondents Able to Participate 
Time Period A/C Cool Credit Irrigation Peak 
Rewards Flex Peak 
5pm – 9pm 87% 88% 79% 
6pm – 10pm 80% 59% 71% 
7pm – 11pm 77% 30% 67% 
16
The percentage of respondents for each program 17
answering in the affirmative that they would be able to 18
participate decreased as the time period requested shifted 19
into the later hours of the day. The most dramatic decrease 20
came from the Irrigation Peak Rewards participants where 21
only 30 percent of survey respondents said they were able 22
to participate between 7:00pm and 11:00pm. While the 23
NESBITT, DI 15
Idaho Power Company
Company anticipates there will be an impact to DR 1
participation as a result of the parameter changes, it is 2
difficult to quantify the exact capacity impact on the DR 3
portfolio at this time. 4
Participant Compensation 5
Q. How are specific program design items being 6
modified to address these participation concerns? 7
A. To help minimize a potential decrease in 8
customer participation, customers will earn more for their 9
participation under the proposed programs as compared to 10
the current program parameters and incentives. Table 5 11
below shows the proposed changes for each of the three 12
programs. 13
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NESBITT, DI 16
Idaho Power Company
Table 5: Summary of Proposed Demand Response Program Design 1
Changes 2
3
The Company is proposing an increase in the variable 4
incentive after four events for the Flex Peak program, 5
recognizing it may be more difficult for some customers to 6
participate in the later evening hours. Because the Flex 7
Peak program pays its participants weekly based on 8
Nominated kW regardless of whether an event is called, 9
participants will see an increase in the overall fixed 10
incentive they receive due to the proposed program being 11
extended by one month. 12
The A/C Cool Credit program participants will 13
receive an additional fixed incentive payment with the 14
Event 
Duration 
Event 
Window 
Minimum 
# of 
Events 
Event 
Notification Fixed Incentive Variable 
Incentive 
Incentive 
Adjustment 
Fl
e
x
 Pe
a
k

Existing 2‐4 
hours 
2:00 to 
8:00pm 3 events 2 hours prior 
to event 
$3.25 per kW per week =  
$29.25 per kW per season 
$0.16 per kWh 
after 3rd event 
$2.00 per kW not 
achieved per 
event & $0.25 
after 3rd event 
Proposed 
Option 
2‐4 
hours 
3:00 to 
10:00pm 3 events 4 hours prior 
to event 
$3.25 per kW per week = 
 $42.25 per kW per season 
$0.20 per kWh 
after 4th event 
$2.00 per kW not 
achieved per 
event 
A/
C
 Co
o
l
 Cr
e
d
i
t

Existing Up to 4 
hours 
Not 
defined 3 events None $5.00 per month =  
$15.00 per season None None 
Proposed 
Option 
Up to 4 
hours 
Not 
defined 3 events None $5.00 per month =  
$20.00 per season None None 
Ir
r
i
g
a
t
i
o
n
 Pe
a
k
 Re
w
a
r
d
s

Existing Up to 4 
hours 
1:00 to 
9:00pm 3 events 4 hours prior 
to event 
$5.00 per kW & 0.76¢ per 
kWh, 2 months =  
$16.00 per kW per season 
$0.148 per kWh 
after 3rd event & 
$0.198 for 
9:00pm option 
$5.00 per kW per 
opt out & $1.00 
per kW after 3rd 
event 
Proposed 
Option 
Up to 4 
hours 
3:00 to 
11:00PM 3 events 4 hours prior 
to event 
$5.25 per kW & 0.80¢ per 
kWh, 3 months =  
$25.20 per kW per season 
$0.18 per kWh 
after 4th event & 
$0.25 for 
11:00pm option 
$6.25 per kW per 
opt out 
NESBITT, DI 17
Idaho Power Company
extension of the program to September 15th with no change to 1
the monthly incentive amount. 2
For the Irrigation Peak Rewards program, the Company 3
is proposing a higher monthly fixed incentive credit along 4
with an increased variable incentive after the fourth 5
event, again recognizing it may be harder for customers to 6
participate in the later evening hours. 7
Number of Program Events 8
Q. Does the Company propose to keep the 9
requirement of three minimum events? 10
A. Yes. As previously approved by the 11
Commission, the three minimum events per season help the 12
Company test and improve program operations and execution 13
to ensure reliable capacity reduction is achieved when DR 14
is called upon. 5 This minimum requirement also keeps 15
customers engaged with DR program terminology, rules, 16
processes, notifications, opt-outs, and performance. In 17
addition, more events leads to better customer 18
relationships. Without minimum events, the programs could 19
go years without being utilized or tested. When programs 20
are not used consistently, equipment and systems may not 21
work as planned, and as a result, the demand reduction 22
could be less than expected. 23

5 Case No. IPC-E-13-14, Motion to Approve Settlement Agreement,
Attachment 2, pp. 6-8.
NESBITT, DI 18
Idaho Power Company
Q. Why is the Company proposing to increase the 1
threshold for the variable incentive payment for the Flex 2
Peak and Irrigation Peak Rewards programs from after three 3
events to after four events? 4
A. The variable incentive event qualification 5
moving to after four events is to align with the extension 6
of the season and the overall increase in fixed incentives 7
customers will receive. 8
Opting Out of Program Events 9
Q. Why is the Company changing the amount of the 10
incentive adjustment when customers opt out of program 11
events? 12
A. The change to the incentive adjustment, or 13
opt-out fee, for both the Irrigation and Flex Peak programs 14
is to align with the season’s fixed incentive and to send 15
customers a proper disincentive signal for opting out of 16
any event. The proposed incentive adjustment will 17
approximately nullify a customer’s fixed incentive if the 18
customer opts out of four events throughout the program 19
season. The Company feels this properly creates a 20
disincentive for customers to opt out except under extreme 21
conditions. This also removes the possibility of a customer 22
signing up with the intention of opting out of all events 23
and minimizes the likelihood of customers planning to only 24
participate in the first three or four events before opting 25
NESBITT, DI 19
Idaho Power Company
out of the rest. 1
Q. Are there any other updates to the program 2
tariffs being proposed that are outside of the adjustments 3
being made to address the high-risk hours? 4
A. Yes. The updated tariffs are included as 5
Attachment 1 to the Application and explained more fully 6
below. 7
Removal of Program Marketing Limitations 8
Q. What modification is Idaho Power proposing in 9
Schedule 23? 10
A. The Company is proposing to remove the 11
restriction outlined in Schedule 23 requiring that 12
participation is only available to customers that have an 13
existing dispatchable Load Control Device installed on 14
their equipment or existing participants under the Manual 15
Dispatch Option. By removing this provision, the Company 16
will have the ability to market the program to maintain 17
and/or grow DR capacity to meet high-risk hours identified 18
in the 2021 IRP analysis. Based on the results of the 19
customer survey explained earlier in my testimony, the 20
Company anticipates there may be an initial decrease in 21
participation due to the proposed parameter changes. 22
Opening up participation to new irrigation customers by 23
removing the current marketing restrictions can help 24
mitigate a potential decrease in DR capacity. 25
NESBITT, DI 20
Idaho Power Company
Adjusted Flex Peak Program Baseline kW Calculations 1
Q. What is the current Adjusted Baseline kW 2
calculation for the Flex Peak program? 3
A. The current Adjusted Baseline kW calculation 4
for the Flex Peak program is the sum of the Original 5
Baseline kW and the Day of Load Adjustment (“DOA”). The 6
Original Baseline kW is calculated using the industry 7
standard “3 and 10 method.” The 3 and 10 method utilizes 8
the three highest energy use days during the event 9
availability window from the 10 previous non-event or 10
weekend days to establish the original baseline. 11
The DOA is the difference between the Original 12
Baseline kW demand and the actual metered kW prior to an 13
event. The DOA is used to account for a customer using more 14
or less energy than their Original Baseline kW on a given 15
event day. The Company’s current DOA takes the difference 16
between the Original Baseline kW and subtracts or adds the 17
actual metered kW two hours before an event with a maximum 18
adjustment cap of 20 percent. This difference is then added 19
or subtracted to each hour’s Original Baseline kW to arrive 20
at a participant’s Adjusted Baseline kW. 21
Q. How does Idaho Power propose to change the 22
Adjusted Baseline kW calculation for the Flex Peak program? 23
A. The proposed Adjusted Baseline kW calculation 24
will still incorporate the Original Baseline kW and a DOA. 25
NESBITT, DI 21
Idaho Power Company
The Company is only proposing a change to how the DOA 1
portion is applied to the Original Baseline kW, and the 2
Original Baseline kW will still be calculated using the 3 3
and 10 method. 4
The proposed adjustment to the DOA is to use a scalar 5
method given a four-hour advanced notification of an event. 6
The Original Baseline kW for each event hour will be 7
divided by the Original Baseline kW for the hour preceding 8
the advanced notification to arrive at a scalar, or 9
multiplier, for each individual hour. Each hour’s scalar is 10
then multiplied by the actual kW registered during the hour 11
preceding the event notification to calculate a 12
participant’s Adjusted Baseline kW. Charts 1 and 2 below 13
give an example of how the Adjusted Baseline kW is 14
calculated using the DOA scalar method. 15
// 16
// 17
// 18
// 19
// 20
// 21
// 22
// 23
// 24
// 25
NESBITT, DI 22
Idaho Power Company
Chart 1. DOA Scalar Method 1
2
Chart 2. Adjusted Baseline vs Event Day kW Reduction 3
4
NESBITT, DI 23
Idaho Power Company
Q. Why is the Company proposing a DOA scalar 1
method to calculate a customer’s Adjusted Baseline kW? 2
A. The Company believes this method is more 3
accurate in calculating a customer’s baseline, and 4
therefore, results in more accurate calculations of 5
customer demand reduction and compensation. The Company 6
conducted an analysis based on actual customer loads during 7
peak days and determined that the four-hour DOA scalar 8
method was more accurate 86 percent of the time as compared 9
to the current DOA. 10
Advance Notice of Program Events 11
Q. Why is the Company proposing to move from a 12
two-hour advanced notification period to a four-hour 13
advanced notification period for the Flex Peak program? 14
A. The Company is proposing to move the 15
notification period to four hours based on feedback from 16
customers and to better align with the Irrigation Peak 17
Rewards program. Customers in several forums have expressed 18
their desire to have a longer lead time on event days so 19
that they can properly reduce load and minimize any 20
incentive adjustments for not meeting their Nominated kW. 21
The four-hour notification period also streamlines the DR 22
dispatch process for the LSO if Flex Peak and Irrigation 23
Peak Rewards events are called on the same day. 24
// 25
NESBITT, DI 24
Idaho Power Company
Opting Out of Program Events 1
Q. Why is the Company proposing to allow the 2
waiving of opt-out penalties in the Irrigation Peak Rewards 3
program? 4
A. The Company is proposing to add a provision 5
where opt-out fees can be waived in limited circumstances 6
where unplanned or planned outages of at least three hours 7
in duration occur up to twenty-four hours before an 8
irrigation DR event or there is a multiday outage within 9
seventy-two hours of an event. The Company is cognizant 10
that calling a DR event that turns off irrigation water on 11
peak days can potentially have an impact on crop production 12
and a participant’s livelihood. An outage can also have a 13
similar impact. The Company recognizes that a customer 14
opting out of a DR event due to already experiencing a 15
recent outage would receive an incentive adjustment when 16
they cannot reasonably participate without further risking 17
crop production. The Company believes adding this clause 18
provides additional flexibility in the execution of the 19
program, implements a tool to mitigate program attrition, 20
and will help build and maintain positive relationships 21
with customers. 22
Q. Please describe why the Company is adding 23
language that allows it to charge an opt-out fee to 24
NESBITT, DI 25
Idaho Power Company
customers who override the dispatch command on their 1
device. 2
A. This is a practice the Company currently 3
implements to prevent customers from inappropriately 4
earning an incentive when they take action to manually opt 5
out of an event but do not contact the Company. Adding this 6
language to the tariff provides additional clarity to 7
customers. 8
Irrigation Peak Rewards Small Pump Installation Fee 9
Q. Please describe why the Company is adding an 10
installation fee for a select set of new participants in 11
the Irrigation Peak Rewards Program. 12
A. The addition of an installation fee is to 13
maintain cost-effectiveness for participants that have 14
smaller measured horsepower pumps and therefore less load 15
reduction. The Company is proposing to open the Irrigation 16
Peak Rewards program to all potential customers, and an 17
installation fee for the smaller load reduction pumps is 18
necessary given the expense of the initial setup compared 19
to the capacity benefit. This is consistent with a previous 20
requirement that was contained in Schedule 23 prior to the 21
marketing limitations implemented as part of the Settlement 22
Agreement. 23
// 24
// 25
NESBITT, DI 26
Idaho Power Company
Irrigation Peak Rewards Out-of-Demand Season Energy Credit 1
Q. Please explain the Out-of-Demand season Energy 2
Credit added to the tariff that would apply to some 3
Irrigation Peak Rewards customers. 4
A. The Out-of-Demand Season Energy Credit would 5
apply to the portion of Irrigation Peak Rewards 6
participants whose billing cycles do not align with the 7
proposed DR season end date of September 15th. The 8
irrigation season, as defined in Schedule 24, begins with 9
the meter read date of the May billing period and ends with 10
meter read date for the September billing period. Further, 11
the irrigation season (in-season) has a demand charge per 12
kW of billing demand where out-of-season does not. 13
Therefore, some customer’s billing demand could end before 14
September 15th based on their billing cycle, and they would 15
not receive a demand credit as part of the fixed incentive 16
for their participation in the DR program. 17
The Out-of-Demand Season Energy Credit is being 18
added to appropriately compensate these participants and is 19
structured so the demand portion of the fixed incentive is 20
paid using a dollar per kWh value. The Out-of-Demand Season 21
Energy Credit is calculated to be equivalent between 22
customers who will receive a demand credit, because their 23
in-season billing cycles end on or after September 15th, and 24
the customers whose out-of-season billing cycles start 25
NESBITT, DI 27
Idaho Power Company
before September 15th. 1
Timing of Incentive Payments 2
Q. Why is the Company proposing to adjust the 3
incentive payout timing? 4
A. The Company is proposing to extend the timing 5
of incentive payments for the Flex Peak program from no 6
more than 30 days after the program season concludes to no 7
more than 45 days. The Company is also proposing to extend 8
the variable incentive payment for the Irrigation Peak 9
Rewards program from no more than 45 days after the end of 10
the program season to no more than 70 days after the end of 11
the program season. 12
The calculation of the Flex Peak incentive payments 13
is handled outside of the Company’s customer relations and 14
billing system (“CR&B”). A program specialist relies on 15
hourly metered data to quantify the applicable incentive 16
payments. In preparation of the 2021 program payments, the 17
Company was found to be out of compliance with the existing 18
requirement of 30 days. This was due to the additional 19
complexity associated with the program being dispatched 20
five times, and the Company required additional time to 21
review the payments for accuracy. Extending the date by 22
which payments must be issued by an additional 15 days will 23
provide the Company adequate time to complete the initial 24
calculation and review in advance of mailing checks. 25
NESBITT, DI 28
Idaho Power Company
The calculation of the Irrigation Peak Rewards 1
variable incentive payments is also handled outside of 2
CR&B, and the program specialist relies on billing data to 3
calculate the incentive payment amounts. The current 4
requirement to issue checks within 45 days provides 5
adequate processing time for the majority of customers, but 6
in preparation of the 2021 incentive payments, the Company 7
found the billing determinants for a small number of 8
participants were not available prior to the tariff 9
deadline. These were for customers that have multiple 10
service points and have elected to receive summary billing. 11
Extending the date by which payments must be issued by an 12
additional 25 days will provide the Company adequate time 13
to compile all necessary billing components. 14
Program Use During System Emergencies 15
Q. Why are modifications to the emergency use 16
language in the tariffs needed? 17
A. The purpose of modifying the emergency use 18
language in the tariffs for the three DR programs is to add 19
clarity around the use of DR during a system emergency, and 20
that if an emergency were to occur, the programs would be 21
dispatched in accordance with NERC standards and/or Idaho 22
Power’s Rule J. 23
// 24
// 25
NESBITT, DI 29
Idaho Power Company
Miscellaneous Tariff Changes 1
Q. Why is the Company proposing to modify 2
language or provide additional details in certain sections 3
of the tariff schedules? 4
A. The last major revisions to the tariffs 5
occurred in 2013 as part of the Settlement Agreement. In 6
the years that have passed since those revisions, the 7
Company has gained valuable experience implementing the 8
program provisions and explaining the tariff requirements 9
to customers. The Company's program specialists’ field and 10
respond to a multitude of phone calls and emails each year, 11
and through those conversations, have identified areas 12
where the tariff language could be expanded or clarified to 13
enhance understanding. With these language changes, the 14
Company is not intending to implement new or different 15
requirements; rather, it views these modifications as 16
necessary to improve clarity. 17
III. COST-EFFECTIVENESS OF DEMAND RESPONSE 18
Q. How is cost-effectiveness currently determined 19
for the Company’s three DR programs? 20
A. Cost-effectiveness of the DR programs is 21
currently determined based on the method outlined in the 22
Settlement Agreement. The existing method establishes the 23
avoided cost for the three programs by calculating the 24
avoided capacity cost of a single 170 MW Simple Cycle 25
NESBITT, DI 30
Idaho Power Company
Combustion Turbine (“SCCT”) multiplied by the ELCC,6 1
levelized over 20 years, plus the corresponding deferred 2
energy savings for 60 program hours. The avoided capacity 3
cost is updated with every IRP planning cycle. If the total 4
annual cost of operating the Company’s three DR programs is 5
less than the avoided cost outlined in the Settlement 6
Agreement, the programs are considered cost-effective 7
during the annual prudence review. 8
Q. How does the Company propose to modify the 9
avoided cost calculation? 10
A. The Company is proposing to modify the avoided 11
cost calculation such that the DR programs are compared to 12
an equivalent alternative resource on a cost per kW per 13
year basis to determine cost-effectiveness. 14
Q. What are the components of the proposed 15
avoided cost calculation? 16
A. As described in greater detail in Mr. 17
Ellsworth’s testimony, along with how the value of each 18
component is derived, the three components of the proposed 19
alternate cost calculation are: (1) the levelized capacity 20

6 At the time the ELCC was developed in 2013, the Company studied the
top 100 hours of peak demand of each year over the prior five years. Of
those top 100 hours, approximately 7 percent occurred outside of
program hours. As a result, an ELCC of 93 percent is currently applied
to determine the value of demand portion of the avoided capacity
calculation. The purpose of the ELCC is to reflect the ability of a
peaking resource, such as a SCCT, to be used year-round where the DR
programs can only be dispatched during certain hours between June 15th
and August 15th each year.
NESBITT, DI 31
Idaho Power Company
fixed costs of a proxy resource, (2) the additional system 1
benefits of the proxy resource, and (3) the ELCC of the 2
annual DR nameplate capacity compared to a proxy resource. 3
Q. What is the proposed avoided capacity equation 4
to determine the dollar per kW per year avoided cost value 5
for the DR programs? 6
A. The equation below incorporates the components 7
listed above as follows: 8
(Levelized Fixed Cost – Additional Benefits) x 9
ELCC of Annual DR Capacity Compared to Proxy Resource 10
= $ per kW year DR Avoided Cost 11
Q. How would cost-effectiveness be determined 12
using the proposed equation? 13
A. The Company proposes to evaluate cost-14
effectiveness at both the individual program and portfolio 15
level. A dollar per kW cost would be calculated annually 16
for each of the Company’s DR programs and the overall 17
portfolio, assuming the maximum 60 hours of operation. The 18
per kW costs would then be compared to the avoided cost 19
value. A program and a portfolio would be considered cost-20
effective as long as their dollar per kW costs are less 21
than the avoided cost value. 22
// 23
// 24
// 25
NESBITT, DI 32
Idaho Power Company
For example, using the values from Mr. Ellsworth’s 1
testimony, the avoided cost value would be $51.42 per kW 2
per year assuming a 492 MW capacity program. 3
($131.60 - $38.11) x 55% = $51.42 per kW per year 4
Q. How often will the Company update the 5
components of the proposed avoided cost equation? 6
A. The Company intends to evaluate all three 7
components with every IRP planning cycle to establish 8
baselines, but the values used in the cost-effectiveness 9
calculation will be updated with every DSM annual reporting 10
cycle. For example, the ELCC component of the equation is 11
dependent on the capacity of the DR programs. Therefore, 12
the value used in the cost-effectiveness calculation may 13
change in-between IRP planning cycles if capacity changes, 14
but the baselines will reset with every acknowledged IRP. 15
The levelized cost value of the proxy resource will change 16
every year to ensure the value is in the equivalent year’s 17
dollars with the baselines derived from the acknowledged 18
IRP as well. The Company proposes to annually run the 19
production cost models from the most recently acknowledged 20
IRP to update the additional system benefits of the proxy 21
resource component since this value is also dependent on 22
the total DR portfolio capacity. All three components and 23
cost-effectiveness will be reported in the annual DSM 24
report, and a request for a prudence determination on the 25
NESBITT, DI 33
Idaho Power Company
DR program costs will be sought in each year’s DSM prudence 1
case. 2
Q. Do you expect the modified programs as 3
proposed in this filing to be cost-effective? 4
A. Yes. The Company anticipates that the cost of 5
each individual program and the overall DR portfolio will 6
be less than $51.42 per kW per year. This value is derived 7
using 492 MW of traditional DR potential identified from 8
the Northwest Power and Conservation Council assessment 9
referenced in Mr. Ellsworth’s testimony. The Company 10
evaluated future program costs with the proposed incentives 11
against the $51.42 value and believes the DR programs will 12
remain cost-effective in the future. The Company also 13
recognizes that near-term DR capacity will most likely be 14
less than the 492 MW. A lower capacity results in a higher 15
ELCC, and a higher ELCC value increases the $ per kW per 16
year avoided cost in the proposed equation. 17
IV. IMPLEMENTATION OF PROGRAM CHANGES 18
Q. When does Idaho Power wish to implement these 19
program changes? 20
A. Idaho Power plans to implement the changes 21
described above for the 2022 demand response season that 22
begins on June 15, 2022. 23
Q. If the Company’s proposed changes are approved 24
by the Commission, how long will it take for Idaho Power to 25
NESBITT, DI 34
Idaho Power Company
market the modified programs with proposed changes and 1
enroll customers for the 2022 DR season? 2
A. Idaho Power anticipates that it will need some 3
lead time to finalize program marketing materials, engage 4
with customers on modified program parameters, conduct 5
program workshops, and enroll customers in preparation for 6
the 2022 DR season. A Commission order received by 7
February 15, 2022 would position the Company to best meet 8
these timeframes. 9
V. CONCLUSION 10
Q. Please summarize your testimony. 11
A. Idaho Power proposes several DR program 12
modifications informed by the risk-based methodology 13
utilized in the 2021 IRP analysis, which has identified a 14
change in system need and operations since the Settlement 15
Agreement in 2013. The rationale behind the changes is to 16
ensure the Company has a portfolio of cost-effective DR 17
programs that effectively meet system needs. As described 18
in Mr. Ellsworth’s testimony, the changes proposed above 19
would improve the ELCC of the Company’s DR portfolio by 20
approximately 40 percent. The Company believes this 21
improvement is not only necessary but also benefits 22
customers and the reliability of the system alike. 23
Q. Does this complete your testimony? 24
A. Yes, it does.25
NESBITT, DI 35
Idaho Power Company
DECLARATION OF QUENTIN NESBITT 1
I, Quentin Nesbitt, declare under penalty of perjury 2
under the laws of the state of Idaho: 3
1. My name is Quentin Nesbitt. I am employed by 4
Idaho Power Company as a Customer Research and Analysis 5
Leader in the Customer Relations and Energy Efficiency 6
Department and am competent to be a witness in this 7
proceeding. 8
2. On behalf of Idaho Power, I present this pre-9
filed direct testimony and Exhibit No. 2 in this matter. 10
3. To the best of my knowledge, my pre-filed direct 11
testimony and exhibit are true and accurate. 12
4. I hereby declare that the above statement is true 13
to the best of my knowledge and belief, and that I 14
understand it is made for use as evidence before the Idaho 15
Public Utilities Commission and is subject to penalty for 16
perjury. 17
SIGNED this 1st day of October 2021, at Boise, Idaho. 18
Signed: 19
20
21
22
23
24
25
BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-21-32

IDAHO POWER COMPANY

NESBITT, DI

TESTIMONY

EXHIBIT NO. 2
Exhibit No. 2
Case No. IPC-E-21-32
Q. Nesbitt, IPC
Page 1 of 4
Flex Peak Invitation 

Join us for a one-hour virtual seminar on proposed updates to the Flex Peak pro ra
Dear Flex Peak Participant:  

Please join us for a one-hour virtual seminar to provide feedback on proposed updates to
the 2022 Flex Peak demand response program.  

Attendees will learn why program modifications are needed, view comparison of the current
program and proposed new program design, discuss the proposed timeline of changes and have
an opportunity to provide comments and feedback. 

Date: Aug. 31, 2021 
Time: 9:30 to 10:30 a.m.  
Join: email [e-mail] to receive a virtual meeting link and a reminder
email. 

Exhibit No. 2
Case No. IPC-E-21-32
Q. Nesbitt, IPC
Page 2 of 4
To join the meeting, open the link and follow the directions to download the WebEx app.  
https://idahopower.webex.com/idahopower/j.phpMTID=m3f0f5649dfdb330e47f6580d3ae6f43f   

Once downloaded enter the member number and meeting password below: 
 Meeting number (access code): 1457 43 6485
 Meeting password: UgyE4nfss38
To join by phone, dial 1-650-479-3208 and enter the access code: 1457436485##  

If you are unable to attend, share with any appropriate colleague at your business that may be
familiar with the program. We really want to hear from you — your input and feedback is
important to us.  
Zeke VanHooser, Idaho Power
1221 W. Idaho St., Boise, ID 83702
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Exhibit No. 2
Case No. IPC-E-21-32
Q. Nesbitt, IPC
Page 3 of 4

Irrigation Peak Rewards Invitation 

Join us for a one-hour virtual seminar on proposed updates to the Peak Rewards pro ra
Join us for a one-hour virtual seminar to provide feedback on proposed updates to the
2022 Irrigation Peak Rewards demand response program. 

Date: Aug. 31, 2021 
Time: 12-1 p.m. 
Join: Email [e-mail] to receive a virtual meeting link and a reminder email.  

OR to join the meeting, open the link below and follow directions to download the WebEx app a
few minutes before the meeting starts. 
https://idahopower.webex.com/idahopower/j.phpMTID=m4cb8f5e40c15b00144f628342014a58b

After downloading the app, enter the meeting number and meeting password below: 
 Meeting number (access code): 145 461 8350
Exhibit No. 2
Case No. IPC-E-21-32
Q. Nesbitt, IPC
Page 4 of 4
 Meeting password: YBmY9Vjdb68
To join by phone, dial 1-650-479-3208 and enter the access code: 145 461 8350##  

Please note: If we have more than one email address on file for your farm’s Peak Rewards event notifications, all
email addresses will receive this seminar invitation. We welcome and value your feedback. For questions,
contact Tonja Dyke, [e-mail], 208-388-5356 or Dan Axness, [e-mail], 208-
388-2586.
Idaho Power Irrigation
1221 W. Idaho St., Boise, ID 83702
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