20220127IPC to Staff 29-49.pdf

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An ]DACORP Company
LISA D. NORDSTROM
Lead Counse!
I [e-mail]
LDN:sg
Attachments
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January 27,2022
VIA ELECTRONIC FILING
Jan Noriyuki, Secretary
ldaho Public Utilities Commission
11331 West Chinden Blvd., Building 8
Suite 201-A
Boise, ldaho 83714
Re: Case No. IPC-E-21-32
ln the Matter of ldaho Power Company's Application for Approval to Modiff
Its Demand Response Programs
Dear Ms. Noriyuki
Attached for electronic filing, pursuant to Order No. 35058, is ldaho Power
Company's Response to the Second Production Request of the Commission Staff in the
above entitled matter.
The Company has included this set's single attachment with this electronic filing
and has posted the attachment to the secure FTP site established for discovery in this
case. The login information for the confidential and non-confidential portions of the FTP
site was provided to all parties on December 2,2021 who have signed the protective
agreement.
lf you have any questions about the attached documents, please do not hesitate
to contact me.
Very truly yours,
X* !.7("1-t,-*,
Lisa D. Nordstrom
LISA D. NORDSTROM (lSB No.5733)
ldaho Power Company
1221 West ldaho Street (83702)
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
I no rdstrom@ ida hopower. co m
Attorney for ldaho Power Company
BEFORE THE IDAHO PUBLIC UT!LITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
APPROVAL TO MODIFY ITS DEMAND
RESPONSE PROGRAMS.
CASE NO. IPC-E-21-32
IDAHO POWER COMPANY'S
RESPONSE TO THE SECOND
PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO
POWER COMPANY
COMES NOW, ldaho Power Company ("ldaho Powed'or "Company"), and in
response to the Second Production Request of the Commission Staff (.Staff) dated
January 7 ,2022, herewith submits the following information:
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POVVER COMPANY- 1
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REQUEST FOR PRODUCTION NO. 29: Please provide copies of al! past and
future data requests and responses received by or sent from ldaho Power to the Public
Utility Commission of Oregon for the Tariff Advice No. 21-12 Proposed Modifications to
the Company's Demand Response Programs. Please include both formaland informal
responses. This response should include public and confidentialdata responses.
Please provide allfuture responses at, or shortly after, the time when the Company files
its responses to the request.
RESPONSE TO REQUEST FOR PRODUCTION NO. 29: Please refer to the
response provided on January 10,2022. To date, no other such requests have been
received or responses filed.
The response to this Request is sponsored by Stacy Gust, Regulatory
Ad min istrative Assistant, lda ho Power Compa ny.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POVVER COMPANY- 2
REQUEST FOR PRODUCTION NO. 30: Please explain and quantiff the
uncertainties and risks for using the stated available demand response nameplate
capacity derived from the 2021 Northwest Power Plan, compared to the future ldaho
Power specific planned potential study identified in Ellsworth's Direct Testimony
(ELLSWORTH, Dt-24).
RESPONSE TO REQUEST FOR PRODUCTION NO. 30: The Company does
not believe using the 2021 Northwest Power Plan values for Demand Response ("DR")
potential, adjusted to ldaho Powe/s service area, creates any additional risks or
uncertainties in meeting system load in the future. This is demonstrated by the 2021
lntegrated Resource Plan ("lRP") only picking an additional40 megawatts (M\Af) of DR
above the 300 MW of assumed current capacity before 2026 and no additional DR until
2038. However, ldaho Power plans to complete a DR potential study specific to its
service area that can be incorporated into the 2023 lRP.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 3
REQUEST FOR PRODUCTION NO. 31: Please update the calculated additional
benefit tied to the Simple-Cycle Combustion Turbine using the results of the filed 2021
Integrated Resource Plan (ELLSWORTH, Dl-21).
RESPONSE TO REQUEST FOR PRODUCTION NO. 31: ldaho Power replaced
the assumed 300 MW DR program starting tn2022 in the 2021 IRP with a 165 MW
Simple Cycle Combustion Turbine ('SCCT"), and removed the fixed costs of the SCCT,
to determine the ancillary benefits provided by the SCCT compared to DR. Utilizing the
2021 IRP modeling, the Company determined that for an SCCT these benefits would
actually become a cost increase associated with the fuel and SCCT plant O&M required
to meet the demand that the Company previously served via DR curtailment. The cost
increase amounts to an average of $552k per year over the 2022-2026 timeframe, and
the Company would propose to simply set this offset to zero. These results support that
DR is cost-effective as proposed in the filing.
Prior to filing the Company's 2021 lRP, an analysis was performed to validate the
cost-effectiveness of the proposed DR portfolio. ln the Aurora Long-Term Capacity
Expansion ("LTCE') model, for a base analysis, ldaho Power included the proposed DR
portfolio as well as incrementally selectable DR bundles. As a sensitivity analysis, the
Company removed DR as available starting in2023 and required the modelto select
alternative resources. The Company believes this is the most prudent approach to
evaluating the cost-effectiveness of DR, and the results of this analysis, in the table
below, show that the portfolio including DR was substantially more cost-effective than
the optimized alternative portfolio that did not include DR.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 4
Base with B2H - Preferred
Portfolio
Base with B2H - No DR
Validation
Portfolio NPV 57,gLs,7oz 58,228,26L
Demand Response 202L &2O22t Sz4,Ls7 524,t57
Demand Response 2023 and beyond 5155,105 N/A
Total Portfolio NPV sg,og4,g54 59,2s2,418
(S x 1000)
program year assumes program structure program year
2022 assumes modifted hours, season, and incentive.
Whether the Company utilizes the cost-effectiveness equation based on a SCCT,
or an IRP portfolio-based methodology, DR remains the most cost-effective option to
meet ldaho Power's peak demand needs.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 5
REQUEST FOR PRODUCTION NO. 32: Please explain why the Company used
only the first 5 years of the planning horizon when equating the $38.11 per kW per year
of the Simple-Cycle Combustion Turbine to the demand response portfolio
(ELLSWORTH, Dl-21). In calculating this value, what would its value be if calculated
over a 2O-year time horizon consistent with the lntegrated Resource Plan.
RESPONSE TO REQUEST FOR PRODUCTION NO. 32: The analysis period for
ldaho Power's Application for Approval to Modifo lts Demand Response Programs
occurred prior to the filing of the Company's 2021 lRP, and at the time, the most recent
verified AURORA modelto conduct the costing analysis was from ldaho Powe/s
previously filed Application for a Determination Acknowledging its North Valmy Power
Plant Unit 2 Exit Date (|PC-E-21-12). Wth that specific model set-up, focusing on the
first S-years of the planning horizon, the Company felt these most-recently updated
inputs best represented the calculation of the additiona! system benefits of the SCCT
compared to the equally effective 492 MW Demand Response ("DR) portfolio. Please
see ldaho Power's Response to Staffs Production Request No. 31 for a detailed
response to the request for an updated $38.11 per kW benefit value, which references
how this benefit looks when calculated over a 2O-year time horizon consistent with the
IRP.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
]DAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 6
REQUEST FOR PRODUCTION NO.33: Please provide all reasoning,
assumptions, and calculations used in supporting the fixed, variable, and adjusted
incentive values shown in Table 4: Summary of Proposed Demand Response Program
Design Changes (APPLICATION-1 2, PARAGRAPH-24).
RESPONSE TO REQUEST FOR PRODUCTION NO. 33: ldaho Power
endeavors to set incentives at a levelthat will promote sufficient participation while
remaining cost-effective. The existing incentive levels for the Irrigation Peak Rewards
and A/C Cool Credit programs were set as part of the Settlement Agreement approved
by the Commission in Order No. 32923, and the existing incentive Ievels for the Flex
Peak program were set in !PC-E-15-03, approved by Order No. 33292. The 2021 IRP
analysis identified that it would be more beneficial for the programs to be available later
in the evening as well as having a longer season. Because each DR program's
incentives are paid on either a weekly or monthly basis, expanding the season without
decreasing the incentives will result in an overall increase in the incentive amount a
customer receives.
As ldaho Power was evaluating incentive levels based on the proposed
parameters (the longer season, later hours, and increase in number of hours permitted
per week), the Company believed if it proposed to reduce the existing weekly/monthly
incentives it could result in a potentially Iarge amount of attrition in the programs. As
part of its evaluation, ldaho Power reviewed the corresponding cost-effectiveness levels
for each program and determined it could leave the incentive levels the same for A/C
Cool Credit and the fixed Flex Peak incentive, while it had room to increase the variable
incentive for Flex Peak and both the fixed and variable incentives for the lrrigation Peak
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 7
program.
The proposed ResidentialAir Conditioner Cycling program incentive is $20.00
per kW per season, which is calculated by taking the $5.00 monthly credit and applying
it to each of the months of the proposed program season ($5.00 per month x 4 months
= $20.00 per season).
The proposed Flex Peak program incentive of $42.25 per kW per season is
calculated by multiplying $g.ZS per nominated kW by 13 weeks. The proposed season
is from June 15 to September 15, which is 13 weeks. The variable incentive is proposed
to be $ 0.20 per kWh which is higher than the existing $0.16 per kWh, recognizing it
may be harder for participants to participate in later evening hours and recognizing the
variable incentive will be paid after the 4th event instead of after the 3rd event.
The proposed lrrigation Peak Rewards incentive of $25.20 per kW per season is
calculated by taking the proposed incentive of $5.25 per kW x 3 months = $15.75 per
kW. The proposed season is from June 15 to September 15, which is 3 months.
Estimating a customer would run approximately 400 hours in a month for two months,
and 380 hours for one month, the calculation is 400 hours x 1 kW x $0.008 per k\Nh =
$3.20 permonth x2 months = $6.40 + (380 hoursx 1 kWx$0.008 perkWh = $3.04 per
month x 1 month) = $9.44 per kW. $9.44 per kW added to the $15.75 per kW results in
approximately $25.20 per kW per season. The 400 and 380 hours are the Company's
estimates of the time irrigators would run their pumps in a typical irrigation month, and
the $0.008 per kwh is the proposed Energy Credit. Because each custome/s irrigation
hours will vary, $25.20 per kW is only an example of the benefit the customer may
receive. The actual incentive the customer receives will depend on the number of
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 8
kilowatt hours used during their applicable billing cycles. The proposed variable
incentives are $0.18 and $0.25 per k\Mr, which are higher than the existing incentives of
$0.148 and $0.198 per kWh, recognizing it may be more difficult for customers to
participate in the later evening hours as well as the variable incentive moving to after
the 4th event instead of after the 3rd event. The higher variable incentive of $0.25 for
the 11:00pm option is to incent customerc that believe they have the ability to
participate in the latest evening hour if there are variable incentive events.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 9
REOUEST FOR PRODUCTION NO. 34: Please provide the difference and
explain the effect to the Planning Reserve Margin when using the Company's LOLE of
0.05 days per year goal versus a LOLE of 0.10 days per year for the threshold
referenced in Ellsworth Direct Testimony (ELLSWORTH, D!-13).
RESPONSE TO REQUEST FOR PRODUCTION NO. 34: The difference in the
Planning Reserve Margin ("PRM') between reliability thresholds of 0.05 days per year
and 0.1 days per year would be approximately 2.1 percent. This 2.1 percent difference
is attributed to an average difference of 73 MW of generation needed when comparing
the two reliability thresholds. !t is worth noting that the PRM was calculated using four
years of historical data, which does not include 2021.lncluding 2021 dala would
significantly increase the average generation needed, as shown in the chart and table
provided in the Response to Staffs Request for Production No. 20.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 1O
REQUEST FOR PRODUCTION NO.35: Please explain in detailand provide
evidence relative to the following statement made in Ellsworth's testimony, "Therefore,
by planning for an LOLE of 0.05 days per year, the Company expects to be able to
maintain a similar level of reliability that ldaho Power's customers and regulators expect
moving forward" (ELLSWORTH, D!-1 3).
RESPONSE TO REQUEST FOR PRODUCTION NO. 35: Please refer to ldaho
Powe/s Response to Staffs Request for Production No. 20. As explained in that
response, the amount of generation required to meet the Company's reliability threshold
has increased in recent years. By shifting from a Loss of Load Expectation ('LOLE") of
0.1 days per year to 0.05 days per year, the Company expects to maintain delivery of
reliable power to its customers.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 11
REQUEST FOR PRODUCTION NO. 36: Please provide the monthly outage
table referenced in Ellsworth's Direct Testimony (ELLSWORTH, Dl-14). Please indicate
the category of resource (i.e. dispatchable resource, non-controllable resource, or
energy-limited resource) as well as the generating capacity and Equivalent Forced
Outage Rate for each of the resources.
RESPONSE TO REQUEST FOR PRODUCTION NO. 36: Please see
Attachment 1 provided in Response to Staffs Request for Production No. 27.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POI/\'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 12
REQUEST FOR PRODUCTION NO. 37: For each of the demand response
programs that allow a participant to choose to opt-out of an event, how many
dispatched events can the participant opt-out before they do not receive any seasonal
incentive from the program?
RESPONSE TO REQUEST FOR PRODUCTION NO. 37: For the lrrigation Peak
Rewards program, with the proposed incentive levels, customers will receive around
$25.00 per kW total between their kW and kWh incentive (varies with actual kwh
usage). With the opt out penalty of $6.25 per event, it willtake approximately 4 opt-outs
for a participant to negate their total season incentive.
For the C&l Flex Peak program, with the proposed incentive levels, customers
can receive $42.25 per kW of load reduction. With an incentive adjustment of $2.00 per
kW for each hour, it will take approximately 4 events of not providing their nominated
kW for a participant to negate their total season incentive. This assumes each of the
non-performing events are in separate weeks. lf they are in the same week, it would
take more events depending on how many events are called in one week.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 13
REQUEST FOR PRODUCTION NO. 38: Please explain how the Company
accounted for reductions in the amount of DR available during a hot dry year specifically
when:
a. Irrigators participating in the program do not pump due to a lack of
irrigation water (resulting in the participant not having any pumping load to
reduce for the system net load in a called event).
b. The lrrigators participating in the program are un-willing to reduce load
due to extreme weather and the higher potentialfor damage to their crops.
RESPONSE TO REQUEST FOR PRODUCTION NO. 38:
a. The Company estimates the potential capacity of the program based on historical
irrigation system load that peaks in late June or early July. This is when most crops
are being irrigated with load tailing off in August. \Mile this capacity estimate would
not take into account a very severe multi-year drought where there was a significant
reduction in lrrigation load, the estimate takes into account participant performance
in the Company's service area that have experienced periods of drought. Also, if the
irrigation load is not on in the first place, the Company does not experience as high
of an overall system load.
b. The program's operational history does not show large numbers of participants
opting out in hot dry years, and the program incentive structure, particularly related
to the opt-out penalty, is designed to discourage this.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 14
REQUEST FOR PRODUCTION NO.39: Please provide:
a. A description of the methodology that the N\tVPPC used to determine the amount
of Demand Response nameplate capacity available in the Pacific Northwest.
b. A detailed explanation and documentation on why the Company believes this
amount can be used to estimate the amount of nameplate capacity available in
ldaho Power's service territory.
c. Documentation showing how the Company verified that the amount of capacity
available in its service territory is reasonable.
RESPONSE TO REQUEST FOR PRODUCTION NO. 39:
a. lt is ldaho Powe/s understanding that the Northwest Power and
Conservation Council ('NWPPC") estimated the amount of DR capacity in the
Pacific Northwest by collecting program information using expertise from regional
utilities. They applied that information to the total region load by sector. They also
created a Demand Response Advisory Committee, which ldaho Power
participated in, in which the information and assumptions were reviewed and
discussed. The information was gathered from utilities that had experience with
operating particular types of DR programs. The information was combined to
estimate what a particular type of program could produce if results and
assumptions were applied to that sector of customers or end use equipment for
the whole region.
b. The Company believes that the NWPPC assessment represents a
reasonable approximation of the potential for all types of DR programs in its
service area. ldaho Powe/s understanding of how the NWPPC put information
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 15
together to determine DR potential is very similar to how other third-pafi experts
have completed similar assessments. However, the Company believes a DR
potentia! study specific to Idaho Power's service area will result in better
information that can be utilized in future lRPs.
c. While ldaho Power does not have documentation. The Company
reviewed the information internally, and with the NWPPC, before deciding to
incorporate the information into its analysis.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 16
REQUEST FOR PRODUCTION NO. 40: PIease answer the following regarding
the calculation of the levelized fixed avoided capacity cost of the SCCT surrogate:
a. What did the Company assume for the useful Ilfe of an SCCT to calculate the
levelized fixed avoided capacity cost and what did it use as the basis (e.9., EIA
uses a 30-years to determine Levelized Costs of New Generation Resources in
the Annual Energy Outlook -
https ://wunr. eia. g ov/outlooks/aeo/pdf/electricity_gene ration. pdf).
b. Please provide and explain the Company's 2022 avoided cost calculation using
the Company's assumed useful life of the SCCT surrogate of $131.60 per kW per
year for the Simple-Cycle Combustion Turbine determined through the 2021 IRP
resource costing process (ELLSWORTH, Dl-21).
RESPONSE TO REQUEST FOR PRODUCTION NO. 40:
a. The assumed useful life of an SCCT for the 2021 IRP is 35 years (please see the
2021 IRP TechnicalAppendix C for more cost inputs and operating
assumptions). The Company consulted EIA, NREL, and I-AZARD data as well as
its internal natural gas subject matter experts to determine the assumed useful
life.
b. PIease refer to the Company's Response to Staffs Request for Production No.
24.The levelized fixed costof $131.60 is incorporated based on the rationale
provided and the value was determined in the 2021 IRP analysis.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 17
REQUEST FOR PRODUCTION NO.41: According to the Application
(Paragraphs 41.43), the Company plans to determine the cost-effectiveness of
individual programs and the portfolio when the cost of the program and portfolio are less
than the avoided cost value of the SCCT surrogate. Given the amount of
uncertain$/variability of demand response that may be available during a reliability
event (due to varying participation levels, participants opting out of called events, etc.)
when compared to the level of certainty for dispatching an SCCT surrogate, please
describe how the Company's cost-effectiveness evaluation method compensates for
this variability difference. ln other words, how can the Company justiff the cost-
effectiveness of a program that has a cost that is about equal to the avoided cost
threshold, when the variability of an SCCT's performance is assumed to be lower than
the variability of a DR program's performance?
RESPONSE TO REQUEST FOR PRODUCTION NO. 41: The proposed cost-
effectiveness evaluation uses the Effective Load Carrying Capability ('ELCC")
percentage to compare DR programs to an SCCT surrogate. This method considers the
proposed program parameters, and the limitations of those parameters (daily, weekly,
and seasonal usage limits), during possible extreme load scenarios where an SCCT
would be available. As presented in the Company's filing, the ELCCsccr of the DR
programs is 55 percent; that is, the value of the demand response programs is assigned
only 55 percent of the cost of a SCCT.
With regards to varying participation levels, and participants opting out of called
events, the Company has not experienced an unacceptable amount that would cause
concern with how the Company estimates capacity from its programs. ldaho Power
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMM]SSION STAFF TO ]DAHO POWER COMPANY- 18
believes the program design (supported by historical performance) adequately
disincentivizes customers from opting out. However, the Company acknowledges there
may be some risks that the current cost-effectiveness and ELCC calculations do not
take into account.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 19
REQUEST FOR PRODUCTION NO.42: Please provide the Company's
confidence level for the Effective Load Carrying Capability amounts during its highest
risk Loss of Load Probability hours for each of the Company's proposed demand
response programs. lf the Company has not made this analysis, please explain why
not.
RESPONSE TO REQUEST FOR PRODUCTION NO. 42: The Company did not
explicitly determine the confidence levelfor each of its DR programs. lnstead, ldaho
Power calculated the DR portfolio's ELCC using four years of historical data to account
for variations in weather and generation patterns.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 20
REQUEST FOR PRODUCTION NO. 43: Please describe the advantages and
disadvantages between two separate incentive options for each of the DR programs: (1)
increasing opt out penalties, or (2) increasing the proportion of variable incentives
relative to the total amount of incentives. Please include, but do not limit it to, the
advantages and disadvantages of each option relative to free ridership.
RESPONSE TO REQUEST FOR PRODUCTION NO. 43: ldaho Power believes
increasing opt out penalties, beyond what has been proposed in this case, could
potentially deter customers from participating. Customers may become more concerned
about unforeseen circumstances when they need to opt out of the program.
With regards to having a higher variable incentive and a lower fixed incentive,
ldaho Power believes this may not encourage participation as much as the current
incentive structure. Under both the current or proposed structure for the lrrigation Peak
Rewards and Flex Peak programs, customers are incentivized to learn and stay
engaged with the programs, submit paperwork for participation, and train their
employees on what wil! happen during called events. lf the programs had primarily a
larger variable incentive, the Company may be unable to attract participants because
customers would not receive much of an incentive in most years where the Company
only uses the three minimum events. Therefore, a customer may determine the effort to
participate may not to be worth the incentive.
ldaho Power believes the existing structure of the programs has been effective at
limiting free ridership. With ResidentialAir Conditioner Cycling there are likely some
customers that never use their air conditioner; however, the Company believes this is
rare, and the complexity and additionaladministrative costs associated with a modified
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 21
incentive structure implemented to address this would likely outweigh the benefits.
During any given !rrigation Peak Rewards event, there are participants that may
not be running pumps depending on the timing of those events. However, in those
cases, the Company would not labelthat participant a free rider; that participant has
agreed to interruption at times and days determined necessary by the Company. Had
the Company called an event on another day, when that participant had been running
their pump, they would've been subjected to load interruption. On the other hand, a
participant who does not run their pump in a given month (during a given billing cycle),
will not receive an incentive as their demand and energy usage would be zero.
With the Flex Peak program, there may be instances where the facility was
already planning on shutting down, and therefore were able to take advantage of a
specific event. Regardless, the baseline and day of adjustment mechanism are
designed to mitigate this if it was a regular occurrence.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 22
REQUEST FOR PRODUCTION NO. /t4: In Ellsworth's Direct Testimony, the
design of the program with Time Available Hours from 3:00pm to 1 1:00pm, appears to
be based on 400 MW of additiona! solar capacity for 836 MW of tota! solar capacity
(See Chart 4) and not on 436 MW of solar capacity (See Chart 3), a more realistic
amount for year 2023, with Time Available Hours from 5:00 pm to 10:00 pm. ln addition,
the 120 MW from Jackpot Solar included in the 436 MW is currently questionable.
Please answer the following:
a. Please explain why the Company is designing the program with Time Available
Hours from 3:00 pm to 1 1:00pm when the additional 400 MW of solar is currently
speculative and also when the addition of 120 MW of Jackpot Solar is currently
questionable.
b. Please explain the possibility, as well as the advantages of designing the
program based on currently realistic amounts of solar of 436 MW and then
adjusting the Time Available Hours sometime in the future as increased amounts
of solar become less speculative.
RESPONSE TO REQUEST FOR PRODUCTION NO. 44:
a. The Company modeled the DR portfolio with only 50 MW being available for
dispatch from 10:00pm to 11:00pm, meaning the majority of the portfolio was
modeled as only being accessible until 10:00pm. The modeling results
showed that, even with the Company's current Ievels of solar penetration,
having a small Ievel of DR available for dispatch past 10:00pm increased the
ELCC of the DR portfolio.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY-23
b. As previously stated, having a portion of the DR portfolio available for
dispatch during the 10:00pm to 11:00pm hour improved the ELCC value even
at the Company's current levels of solar penetration. The addition of future
resources to ldaho Powe/s system, such as energy storage and solar PV, wil!
require the DR portfolio to continue to be more flexible in order to maintain its
ELCC value.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFFTO IDAHO POWER COMPANY-24
REQUEST FOR PRODUCTION NO. 45: Please provide a list of maintenance,
preventive maintenan@ or actions taken for each demand response program during the
"off-season" (August 16tth to June 14th of following year) to ensure the programs will
operate efficiently when the demand response programs season begins on June 15. ln
the response, please describe if this is done for every customer, a random selection of
customers, or other methods for determining the actions taken.
RESPONSE TO REQUEST FOR PRODUCTION NO. 45: For the Residentia! Air
Conditioner Cycling program, customers are signed up untilthey request removalfrom
the program. Off-season actions center primarily around maintaining load control
devices installed on customers A/C units. Maintenance of these devices is a year-round
activity. The switches are "pinged" several times a week to veriff ldaho Power can
communicate with the switches. Switches that consistently fai! to communicate are first
investigated by looking at data to see if there is a reasonable explanation or a situation
that will resolve itself. For instance, some customers choose to remove the air
conditioner fuse at the end of the summer and reinsert it at the start of the next summer.
By tracking the pattern of switch communications at a location, it is easier to see this
and the expense of sending a technician to the site can be avoided.
lf a switch consistently fails to communicate and data investigation does not
reveal an explanation that wil! resolve itself, the situation is passed to ldaho Power's
contractor to investigate. They attempt to make contact with the participant by phone to
see if something has changed, such as if the customer decided to pull the fuse or had
replaced their air conditioner unit. lf the situation resolves itself, no further action is
taken, and notes are made for future tracking. lf the situation will not resolve itself, such
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY-25
as for a new air conditioner or the participant does not know why it's not communicating,
or the customer cannot be reached by phone or wil! not return a call, then a technician
will visit the site with the goal of correcting the situation so the customer can continue
participating. If ldaho Power can't access the switch, isn't able to contact the customer,
or the customer will not return a call, then a letter is sent requesting they call to
schedule an appointment for the Company to service the switch so they can continue
participating. lf no response is received in two weeks, the custome/s participation is
ended.
For the lrrigation Peak Rewards program, off-season actions include finalizing
customer incentives in the fal! and a robust marketing effort takes place to sign
customers up each spring. Because a very large portion of program participants use
load control devices, device management is a major part of off-season activity. Device
monitoring is extensive for approximately five months out of the year with the majority of
the work being completed in April and May. lrrigation watering season is typically April
15 - Nov 15, and pre-season activities begin in March through June 'tSth of each year.
Actions consist of tracking participating service point locations and working through
weekly device communication reports. The communication reports show the daily
communication to the demand response device and a daily record of successful or
unsucc,essfulcommunication. The communication reports are reviewed weekly starting
mid-Aprilthrough the end of August. The report is not reviewed year-round due to
many irrigators tuming pumps off at the main panel switch during the off season which
disconnects ldaho Power's demand response device. The season is also condensed
due to weather related access issues with pump panels in the field. Additionally, when
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 26
the electrician arrives on site with a work order request, it is important the pump is on or
can be turned on to veriff device communication.
Every device in the field is on the communication report, and if the service point
has enrolled for the current demand response season and has failed to communicate, a
work order is created for an electrician site visit. The bulk of the work orders are sent in
April and May with additionalwork being done through August. Occasionally customers
will callwith information about the participating service point such as a new panel being
installed. The program specialist will create a work order for an electrician to re-install a
device at the pump location. The electrician sent onsite is required to contact ldaho
Power's metering department to veriff the device exchange or that the repairs have
been successful. lf the communication is still unsuc@ssful, the electrician will continue
to troubleshoot issues and/or exchange the device. ln addition, sometimes other issues
are identified such as AMI communication equipment or substation issues or issues with
the custome/s electrical equipment. For the Flex Peak program there are no devices
that need to be maintained, but actions taken during the off-season include calculating
and sending out customer payments once the season is over and signing up customers
in the spring before the season starts.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 27
REQUEST FOR PRODUCTION NO.46: Please provide in excelformat, a
breakdown of 2019 and 2020 expenses for each of the demand response programs in
the'off-season" (August 16th to June 14th of following year). Please breakdown each
programs expenses by incentives, administration, marketing and outreach, and
maintenance and testing.
RESPONSE TO REQUEST FOR PRODUCTION NO. 46: Please see the
attachment provided for this response.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.23
REQUEST FOR PRODUCTION NO. 47: For EM&V evaluations, please provide
the following:
a. Please provide results from the two most recent EM&V evaluations for the
current program offerings.
b. When willthe next demand response evaluations be conducted? Willthis be
conducted on the current program offerings or the proposed program in the
Application?
c. Please provide the EM&V Evaluation schedule for the next 5 years.
RESPONSE TO REQUEST FOR PRODUCTION NO. 47:
a. Please refer to the 2019 and 2020 DSM Report Supplement 2 filed in Case
Nos. IPC-E-20-15 and IPC-E-21-04, respectively, for the most recent EM&V
evaluation reports and results. The DR programs are evaluated internally
each year, and the evaluations can be found in the Other Reports section of
Supplement 2. Periodically, third-party evaluations are conducted on the DR
programs and the reports can be found in the Evaluations section of
Supplement 2. All reports can be found under the program names. The table
below gives the history of DR program evaluations for the last 10 years.
I =Third-party impact evaluation
P = Third-partv Frocess evaluation
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 29
Third-Pafi Evaluations
26j2 mt3 2gt/t zr15 mfi 2tt7 ?0.t8 2([9 NN zojt
A/C cool Cr€dlt P I I I
Flex Peak I I I
I I
lnternal lmoact Evaluatlons
20t:2 2013 zgu 2015 20fi M7 2018 20r!l M 2@t
A/C Cool Cr€dlt
Flex Peak
b. Each program is currently undergoing a third-party evaluation for the 2021
season with the current program parameters. However, those evaluations are
not complete in time for this data response but will be included with the 2021
DSM Report. A process evaluation is planned to be conducted in 2023 to
evaluate any program changes that are enacted as part of this filing.
c. The EM&V plan for the next 5 years involves the Company completing an
impact evaluation each year internally and to contract for the next third-party
impact evaluation for each of the programs in 2026. As noted above, a
prooess evaluation will also be conducted on each program in 2023.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO PO1/\'ER COMPANY- 30
REQUEST FOR PRODUCTION NO.48: Please describe the costs supporting a
$500 installation fee for lrrigation Peak Rewards customers with a measure horsepower
pump of 30 or less in Schedule No. 23. Please provide the average cost of an
installation in2020for a20,25 and 30 horsepower pump.
RESPONSE TO REQUEST FOR PRODUCTION NO. 48: The Company has
estimated the average cost of installing a device to be approximately $567, which
includes the cost of the device itself ($160) as wel! as the cost of installation by a
licensed electrician ($aOZ). The Company estimated the $160 based on an estimate
from the device supplier Iast summer and the $407 by summing the past three years of
electrician invoices dividing by the number of installs over that same time period.
Recent information received from the device supplier indicates the cost of new devices
will range between $170-190 depending on the size of the order.
ldaho Power has not tracked data to determine conclusively whether different
horsepower pumps cost different amounts to install. However, in ldaho Powe/s
experience, it is not the size of the pump that may make one site cost more than
another. The device costs the same regardless of the pump size, but the electrician's
costs are variable. The electrician's cost is primarily driven by traveltime differences
caused by getting to the individual pump sites.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 31
REQUEST FOR PRODUCTION NO. 49: Nesbitt Testimony at 32 states'the
value used in the cost-effectiveness calculation may change in-between IRP planning
cycles if capacity changes, but the baselines will reset with every acknowledged lRP."
Please confirm the values used in the cost-effectiveness calculations for the program
modifications are set using preliminary analysis for the 2021 !RP. lf values are not using
the preliminary 2021 lRP analysis, please explain.
RESPONSE TO REQUEST FOR PRODUCTION NO. 49: The components of
the proposed cost-effectiveness calculation below used the preliminary analysis of 2021
IRP:
. The levelized capacity fixed costs of a prory resouroe ($131.60)
. The ELCC of the annua! DR nameplate capacity compared to a prory
resource (55%)
However, the additional system benefits of the proxy resource amount ($38.1 1)
was determined using 2019 IRP information, because the 2021 IRP analysis was still in
process at the time of this filing.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 32
DATED at Boise, ldaho, this 27th day of January 2022.
&-.O.ff^*+**-
LISA D. NORDSTROM
Attomey for ldaho Power Company
IDAHO POWER COMPAI{Y'S RESPONSE TO TI{E SECOND PRODUCTION REQUEST OF THE
OOMMISSION STAFF TO IDAHO POVI/ER COMPANY.3S
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 27th day of January 2022, ! served a true and
correct copy of ldaho Power Company's Response the Second Production Request of
the Commission Staff to ldaho Power Company upon the following named parties by the
method indicated below, and addressed to the following:
Commission Staff
Riley Newton
Deputy Attorney General
ldaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8,
Suite 201-A (837'14)
PO Box 83720
Boise, lD 83720-0074
ldaho lrrigation Pumpers Association, lnc.
Eric L. Olsen
Echo Hawk & Olsen, PLLC
505 Pershing Ave., Ste. 100
P.O. Box 6119
Pocatello, ldaho 83205
Lance Kaufman
Aegis lnsight
4801 W. Yale Ave.
Denver, CO 80219
ldaho Conservation League
Benjamin J. Otto
Emma E. Sperry
ldaho Conservation League
710 N. 6th Street
Boise, ldaho 83702
lndustrial Customerc of ldaho Power
Peter J. Richardson
Richardson Adams, PLLC
515 N.27th Street
P.O. Box 7218
Boise, ldaho 83702
_Hand Delivered
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_Overnight Mail
-FAX
X FTP SiteX Email:[e-mail]
_Hand Dellvered
_U.S. Mail
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_FAXX FTP SitexEmai! [e-mail]
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esperry@ida hoconservation.orq
_Hand Delivered
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Overnight Mail
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IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO PO\'\'ER COMPANY- 34
Dr. Don Reading
6070 Hill Road
Boise, ldaho 83703
Micron Technology, lnc.
Austin Rueschhoff
Thorvald A. Nelson
Austin W. Jensen
Holland & Hart LLP
555 17th Street, Suite 3200
Denver, CO 80202
Jim Swier
Micron Technology, !nc.
8000 South FederalWay
Boise, !D 83707
Boise City
Ed Jewell
Deputy City Attorney
Boise City Attorney's Office
150 N. Capitol Blvd. P.O. Box 500
Boise, lD 83701-0500
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_FAXX FTP SiteX EMAIL [e-mail]
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tnelson@holla nd ha rt. com
awiensen@ holland hart. com
aclee@holla ndhart.com
q loa rqanoamari@holla nd ha rt. com
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bo isecitvatto rn ey@cityofbo ise. o rq
\kr*rtr &r^J..
Stacy Gust, Regulatory Administrative
Assistant
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 35
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-21-32
IDAHO POWER COMPANY
REQUEST NO.46
ATTACHMENT NO. 1
SEE ATTACHED SPREADSHEET
A/G Cool Credit
2019 16, 2019 - Jun 14, 20201
Grand Total
2020 (Aug 16, 2020 - Jun 14, 2021
Grand Total
FlexPeak Program
2019 (Aug 16, 2019 - Jun 14,
Administration
lncentives
378,512.U 21,997.63 170,291.29 570,801.76
289,038.25 16,493.09 153,713.40 459,24.74
252,676.25 294,9!O.75
3.49 59.80
66,763.00 256,157.95 294,910.75 617,831.70
2,673.45
203,066.50 247,393.00 450,449.50
59,480.31 206,376.71 250,056.45 515,913.47
L,923.25
2,534,760.27
3,091.65 59,957.48
33.73 674.sL
Services
Grand Total
2020 (Aug 16,2020 -Jun 14, 20211
Administration
lncentives
Grand Total
lrrigation Peak Rewards
2019 16, 2019 - Jun 14, 20201
Administration
lncentives
Marketing
Materials & Equipment
Services
Training - Education - Workshops
55,475.45 2,945.62 58,42L.07
L72,62L.29
9,904.36
2,330.00
527.29
t70,29t.29
10,425.65
Materials & Equipment
Administration
lncentives
Marketing
(74,2O2.O3l,(747.47l,(14,949.50)
327,335.06 16,948.19Services 344,283.25
TotalCategory0&MlD Rider 0R Rider
L,997.592,734.O8
1,583.50
749.70 L4,994.20
54,080.87
153,299.31
Materials & Equipment
L4,244.50Marketing
(4,288.25],(85,755.00)
Program Evaluation 5,847.00
301,074.30Services
307.73
15,406.33
L5L,7L5.8L
6,L54.73
316,480.63
TotalCategory0&MlD Rider 0R Rider
55,695.69 3,538.21 70,234.90
547,527.O0
66.31
0&M TotalCategorylD Rider 0R Rider
59,480.31 3,3tO.2t 65,463.97
Category 0&M TotallD Rider 0R Rider
59,929.97
2,605,575.L!
55,092.03 2,9L4.63
798.84
70,8L4.84
15.5429s.22
L5,L78.L7
310.76
L5,977.O7
56,865.83
640.78
0&M TotalCategorylD Rider 0R Rider
Services 128,072.03 77,069.23 2,536,683.52 2,742,421.78
2020 16,2020 - Jun14,2021
Administration 55,503.97 3,061.96 5,027.01 63,592.94
lncentives 84,022.67 2,746,9O3.36 2,83O,926.O3
Marketing 841.10 44.26 885.36
Materials & Equipment 83,744.28 4,407.60 88,151.88
Program Evaluation 240.87 L2.67 253.54
Services 94,823.2790120.05 4703.2t
Category Total0&MlD Rider 0R Rider