20220824IPC to Staff 1-25.pdf

3Em.
AnDACOIP@mpilY
LISA D. NORDSTROM
Lead Counsel
[e-mail]
August 24,2022
VIA ELECTRONIC FILING
Jan Noriyuki, Secretary
ldaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, ldaho 83720-0074
Re: Case No. IPC-E-22-22
ln the Matter of ldaho Power Company's Application to Complete the Study
Review Phase of the Comprehensive Study of Costs and Benefits of On-
Site Customer Generation & For Authority to lmplement Changes to
Schedules 6, I and 84 for Non-Legacy Systems
Dear Ms. Noriyuki:
Attached for electronic filing is Idaho Power Company's Response to the First
Production Request to the Commission Staff in the above-referenced matter,
lf you have any questions about the documents referenced above, please do not
hesitate to contact me.
Very truly yours,
&; !.("1.+r.-*,
Lisa D. Nordstrom
LDN:sg
Attachment
LISA D. NORDSTROM (lSB No. 5733)
MEGAN GOICOECHEA ALLEN (lSB No. 7623)
Idaho Power Company
1221 West ldaho Street (83702)
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
lnordstrom@ida hopower.com
mqoicoecheaa llen@ida hopower.com
Attorneys for ldaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION TO
COMPLETE THE STUDY REVIEW
PHASE OF THE COMPREHENSIVE
STUDY OF COSTS AND BENEFITS OF
ON-SITE CUSTOMER GENERATION &
FOR AUTHORIW TO IMPLEMENT
CHANGES TO SCHEDULES 6, 8, AND
84 FOR NON-LEGACY SYSTEMS
CASE NO. IPC-E-22-22
IDAHO POWER COMPANY'S
RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO
POWER COMPANY
)
)
)
)
)
)
)
)
)
)
COMES NOW, ldaho Power Company ("ldaho Power" or "Company"), and in
response to the First Production Request of the Commission Staff ("Commission" or
'Staff') dated August 3,2022, herewith submits the following information:
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCT]ON REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 1
REQUEST FOR PRODUCTION NO. 1: Please answer the following for
Measurement !ntervals:
a. Please provide Schedule 84 Net Billing analysis data for non-legacy systems
with a single-meter interconnection for the hourly and real-time or
'instantaneous" measu rement intervals.
b. Please provide additional explanation and supporting data as to why
Schedule 84 two-meter interconnection measurement interval analysis was
not provided.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1: Please see the following
responses regarding measurement intervals:
a. There are no Schedule 84 non-legacy systems with a single-meter
interconnection with 12 months of data in 2021. Appendix 3.4 includes the
data for all Schedule 84 systems that were interconnected for all 12 months
in 2021. Appendix 3.4, Column l, provides a flag that indicates if the system
is legacy or non-legacy. All systems with 12 months of metering data are
legacy systems.
b. All two-meter systems have legacy status and will not be subject to near-term
changes from implementing a successor service offering. The two-meter
configuration measures all generation and consumption separately;
therefore, the Company cannot perform a rea!-time Net Billing analysis.
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, ldaho Power Company.
TDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 2
REQUEST FOR PRODUCTION NO. 2: Please answer the following for recovery
of Export Credit Rate ("ECR") expenditures:
a. Does the Company include kilowaft-hours ("kWh") generated and consumed
for legacy and non-legacy on-site customer-generators in the PCA? lf so,
please provide the impact to the 202'l-2022 PCA if removed.
b. Order No. 35284 at 14 states "[O]ne question to study is whether all
customers or just on-site generation export customers or another class of
customers should bear the export credit costs." Please identiff where in the
Value of Distributive Energy Resources ("VODER") study this question was
analyzed. If this was not analyzed in the VODER study, please provide the
Company's analysis.
c. Please provide a bill impact analysis for Schedule 6, 8, and 84 if customer-
generators are subject to recovery of their own ECR.
RESPONSE TO REQUEST FOR PRODUCTION NO. 2: Please see the following
responses regarding recovery of Export Credit Rate ('ECR") Expenditures:
a. The Company interprets Staffs question regarding kWh generated as net
exported kWh. The Company does not include a monetized value in the
Power Cost Adjustment ('PCA") for legacy, or non-legacy on-site generation
net metering customers' net exported kWh. Therefore, there are no dollars to
be removed. Regarding consumption, on-site generation net metering
customers pay PCA rates based on their net consumption.
b. On page 23 of Order No. 35284, in the "Recovering Export Credit Rate
Expenditures" section, the Commission provided additional direction by
IDAHO POVVER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 3
highlighting "the direct costs should be linked with the associated benefits."
ln the case of export credit rate expenditures, the exported energy will benefit
the totalsystem, and as a result, the Study quantified the impact of recovering
the expenditures from all customers.
c. The Company did not perform this analysis. Please refer to the response to
Request No. 2b.
The response to this Request is sponsored by Tami White, Budget and Revenue
Manager, ldaho Power Company.
TDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY -4
REQUEST FOR PRODUCTION NO. 3: Please answer the following for the
compensation structu re:
a. Please provide Schedule 84 bill impacts using Net Billing Hourly
measurement interva! and compensation structure using the Study example
ECR of $0.03781.
b. Did the Company perform a bill impact analysis of Schedule 84? lf not, why
not? lf so, please explain how the Company dealt with the two-meter
configuration and provide the analysis?
RESPONSE TO REQUEST FOR PRODUCTION NO. 3: Please see the following
responses regarding compensation structure:
a. The Company did not perform this analysis. Please refer to the response to
Request No. 1b.
b. No. Please refer to the response to Request No. 1b.
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.5
REQUEST FOR PRODUCTION NO. 4: Order No. 35284 requires the study to
'[a]nalyze the pros and cons of setting a customer's project eligibility cap according to a
customer's demand as opposed to predetermined caps of 25 kilowatt fkw') and 100 kW'.
The Order also requires the study to expand the analysis at 125o/o of customers' demand.
Please respond to the following.
a. Please identiff where the oros and g of setting a cap according to a
customer's 100o/o and 125o/o demand as opposed to predetermined caps of
25 kW and 100 kW are located in the VODER study. lf this was not provided
in the VODER study, please provide them.
b. Please identify where the 100% cap analysis is located in the VODER study.
lf this was not provided in the VODER study, please provide it.
c. Please identiff where the 125o/o cap analysis is located in the VODER study.
lf this was not provided in the VODER study, please provide it.
RESPONSE TO REQUEST FOR PRODUCTION NO. 4: Please see the following
responses regarding the project eligibility cap:
a. Section 9.1 of the VODER Study evaluates the existing project eligibility cap,
and Section 9.2 considers a modified project eligibility cap set relative to a
customer's demand. Both sections describe the considerations evaluated.
From the Company's perspective, assessing the interconnection
requirements and distribution system operational impacts is of primary
importance.
b. The VODER Study cap analysis did not differentiate between 100% and
125o/o of demand because from a system perspective, the interconnection
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 6
considerations related to a generator will be evaluated independently from a
customer's demand. ln other words, during an hour without customer load
(for example, when an irrigation pump isn't running) a generator sized at
125o/o of a custome/s 100 kW load (125 kW generator) would behave the
same as a generator sized at 100o/o of a 125 kW load (125 kW generator).
c. Please see the response to 4b.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 7
REQUEST FOR PRODUCTION NO. 5: Please provide a histogram (10 kW
intervals) showing the number of non-solar residential customers with demand peaks
greater than 25 kW.
RESPONSE TO REQUEST FOR PRODUCTION NO. 5: Please see Figure 1
below for the histogram of non-solar residential customers. This information is based on
billing data over the calendar year 2021. lt excludes mobile home parks, RV parks, and
large master metered customers. The customers included in this histogram with demand
25 kW and greater represenl2.lo/o of non-solar residential customers.
Figure f
Non-Solar Residential Customers Histogram
600,000
495,132
500,000
000
@0
000
400,
300,
200,
U'Lo
Eoo)o
o
o-oEJz
100,000
25 or
less
1,904
25-34
30
75-84
29
85 plus
7,059 1,269 ZgT 64
35-44 45-54 55-64 65-74
Annual Peak Demand (kW)
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 8
g,
@
Eoof
C)
o
olt
Efz
REQUEST FOR PRODUCTION NO. 6: Please provide a histogram (100 kW
intervals) showing the number of non-solar Commercial, lndustrial, and lrrigation ('Cl&1")
customers with demand peaks greater than 100 kW.
RESPONSE TO REQUEST FOR PRODUCTION NO. 6: Please see Figure 2
below for the histogram of non-solar Cl&! customers. This information is based on billing
data over the calendar year 2021. The customers included in the histogram with demand
100kW and greater represent6.10/o of non-solar Cl&l customers.
Figure 2
Non-Solar Cl&l Customers Histogram
1oo'ooo eo,78r
90.0m
80,000
70,000
60,000
50.0m
40,0m
30.0m
20,000
10.000
Annual Peak Demand (kW)
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 9
33,47
I
o)o,C\lo(fGI
I
0)o,
c)C)
1r,v,o,
o(fo
181
U)
J
Ora(f(f-
'f"1 ',l:g!y
O, O, Ct O) O, (,) Ctrq) o) o, o) g, g, (r)c?, =ro(0?!@q)eooooooo(300000
REQUEST FOR PRODUCTION NO. 7: The VODER study asserts that larger
customer generation systems inject more risk. The VODER study also describes
thresholds that trigger additionalanalysis for Public Utility Regulatory Policies Act of 1978
('PURPA") project interconnections (>2 megawatt ("MW') and/or exceeds 150/o of the
distribution line section / p. 100). This implies that projects below that threshold are small
enough to be considered safe to the overa!! system. Please explain if systems below
these PURPA thresholds are small enough to be considered safe for Schedule 6, 8, and
84 customers. lf not, please explain what thresholds might be considered safe for each
customer generation class and the basis used to identiff these thresholds.
RESPONSE TO REQUEST FOR PRODUCTION NO. 7: There was no intended
implication that projects below the PURPA threshold of 2 MWand/or excess of 15 percent
of the distribution line section are inherently considered "safe to the overall system." There
is not a definitive threshold that might be naturally regarded as safe. Projects of the 100-
kW variety often require additional study. For example, a large 5 MW project could easily
connect to a distribution feeder in one instance. ln contrast, on another distribution feeder,
a 1 00-kW project located many miles from the substation, at the end of smaller conductor,
may cause issues or require system upgrades to occur.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 1O
REQUEST FOR PRODUCTION NO. 8: Page 97 of the VODER study states that
a "customer can choose to sell their renewable energy as a Qualified Facility ("QF") to
ldaho Power under Schedule 86 for Exporting Systems larger than 100 kW." Please
respond to the following.
a. Please explain why a customer that chooses to sell their renewable energy
as a QF is limited to Schedule 86 rates.
b. Please explain why a customer that chooses to sell their renewable energy
as a QF is not eligible for other rate options such as published avoided cost
rates.
RESPONSE TO REQUEST FOR PRODUCTION NO. 8: Please see the following
responses regarding QFs:
a. ln general, when a QF chooses to sell its renewable energy to ldaho Power
as a PURPA project, it is not limited to Schedule 86 rates. QFs selling to ldaho
Power in ldaho may be eligible for rates under Schedule 73lor firm energy
deliveries or Schedule 86 for non-firm, as-available energy deliveries. QFs
selling to ldaho Power in Oregon are eligible for rates under Schedule 85 for
firm energy deliveries. Under Schedules 73 and 85, QFs may be eligible for
published avoided cost rates or negotiated rates calculated using an
lntegrated Resource Plan-based methodology, depending on their resource
type and size.
b. The above-referenced statement in the VODER Study provided an example
of how a customer could choose to generate electricity other than net
metering and sell to ldaho Power as a QF; the Company did not intend to
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 11
suggest that was the only option available. For example, a QF in ldaho may
sell to ldaho Power under either Schedule 73 or 86, assuming they meet the
requirements of the specified schedule. Schedule 86 includes fewer eligibility
requirements and performance metrics, which may be a preferred option for
some QFs.
The response to this Request is sponsored by Camille Christen, Resource
Acquisition, Planning, and Coordination Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 12
REQUEST FOR PRODUCTION NO. 9: Page 99 of the VODER study states that
"[m]odifications to the project eligibility cap would require an evaluation of the
interconnection requirements and consider specific rules to ensure that ldaho Power is
able to administer its customer generation offering that is consistent for allcustomers with
a proiect elioibilitv cap set at a percentaoe of a customer's demand." Please answer or
provide the following:
a. An action plan (including specific steps, the objectives that would be
accomplished in each step, and amounts of time needed for each step) to
perform this evaluation.
b. An implementation plan (including specific steps and amounts of time needed
for each step) to implement a modified cap determined by the evaluation.
c. Please explain what the Company envisions regarding a modified framework
for allowing larger customer generation over the current caps while protecting
the safety and reliability of the Company's system. Specifically, does the
framework consist of multiple thresholds triggering more studies and higher
levels of controls, as the risks to safety and reliability of the Company's
system increase? Please explain.
RESPONSE TO REQUEST FOR PRODUCTION NO. 9: Please see the following
responses regarding project eligibility cap:
a. The Company envisions that an "action plan" and "implementation plan" could
follow a similar process to the implementation of Schedule 68 in Case No.
IPC-E-20-30, where the Company hosted workshops with the public and
installer representatives to discuss interconnection requirements before
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 13
submitting proposed interconnection modifications. However, the
Commission has not yet approved a change to the project eligibility cap, so
ldaho Power has not presented a process and anticipates that Staff and other
parties in the case wil! make recommendations on the action and
implementation plans.
b. Please see response to Request No. 9a above.
c. The Company envisions the first step in reviewing larger projects would be to
use the current internal screen for each project. The current internal screen
evaluates the project size relative to the individual service transformer size
and the distribution feeder hosting capacity - in Schedule 68, this is referred
to as the Feasibility Review. lf the project passed the initial screen, then the
project would be approved. However, if the project fails, the Company would
require a more detailed study to look at potentialoperational, safety, or power
quality issues caused by the project. These studies could follow the process
for PURPA projects, with an initialfeasibility study being completed within 30
days and, if necessary, a system impact study that would take an additiona!
30 days. Each study would require funding from the customer to cover the
cost of the study.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 14
REQUEST FOR PRODUCTION NO. 10: Page 101 of the VODER study states
that there is currently no option to switch off larger customer generation projects remotely
and that there are two solutions to this issue. Please provide the following.
a. Please provide the specific potential consequences of not providing a remote
cut-out switch.
b. Please describe the criteria and the overall decision process that would be
used to determine if a remote switch is needed by an individual project.
c. lf a switch is needed, please describe how it would be implemented and
provided an estimate of the cost.
RESPONSE TO REQUEST FOR PRODUCTION NO. 10: Please see the following
responses regarding remote switch capabilities:
a. The potential consequences of larger customer-generator projects on the
system are that these projects may limit the ability of distribution operations
to move feeder loads between adjacent feeders to restore service or as part
of a line maintenance project. PURPA projects are typically remotely curtailed
during these operations. Without a similar means to switch off the larger
customer generation systems, the distribution system operations will be
limited, or it will require a site visit for someone to switch the project offline
manually.
b. Several factors could be used to determine the need for a remote switch for
an individual project. The remote switch in most cases could be a device that
connects to the projects electrica! panel, like a relay device. Examples for
factors to evaluate could include but are not limited to: ('1) the relationship of
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 15
the project to switching devices; (2) the size of the generator; (3) the load
characteristics of the feeder; (4) the specific distribution line segment where
the project interconnects; (5) other generation systems on the distribution
feeder.
c. A relay would need to be installed at an electrical location on the customer-
generator side of the Company's retail metering point to allow complete
isolation of the DER and interconnection facilities from the customer's
electrical load and service. The equipment cost depends on the rating
required for the specific generation project at each location, in addition to
communications requirements. Assuming the device would be similar to the
disconnect devices used in the Company's irrigation peak rewards demand
response program, the device would cost about $180.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO ]DAHO POWER COMPANY - 16
REQUEST FOR PRODUCTION NO. 11: Pages 101-102 of the VODER study
discusses the definition of a custome/s demand for purposes of a system size cap and
state a customer's demand can be defined in a variety of ways. Please provide and define
the appropriate variable(s) thatwould need to be measured in each definition of "demand"
for determining demand-related caps that would ensure the Company's system remains
safe and reliable.
RESPONSE TO REQUEST FOR PRODUCTION NO. 11: A customer's demand,
irrespective of the definition or criteria used, is not a technical factor that wil! define a
project eligibility cap to ensure that the Company's system remains safe and reliable.
Developing the appropriate review and study processes and defining the necessary
interconnection requirements are the factors that will ensure the Company's system
remains safe and reliable as Iarger DERs are interconnected.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 17
REQUEST FOR PRODUCTION NO. 12: Page 1O2 of the VODER study states
that customers without historical usage data could be incentivized to overestimate their
demand to maximize the system size installed under a demand-related cap. Please
explain what mechanism(s) may be necessary to sufficiently prevent or mitigate the issue
(such as verification steps, potential penalties, ECR adjustments, etc.). ln addition, please
provide estimated costs of implementing the mechanism(s).
RESPONSE TO REQUEST FOR PRODUCTION NO. 12: For customers without
historical load data, the maximum project size could be based on an estimated demand.
To encourage a realistic peak demand estimation the project could be subject to a
permanent curtailment if the peak demand does not meet the estimated demand after 12
months of service.
ldaho Power has not contemplated other mechanisms that may be necessary to
sufficiently prevent or mitigate the issue but anticipates this would be addressed during
the implementation phase once a change is approved by the Commission.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 18
REQUEST FOR PRODUCTION NO. 13: Pages 101 and 102 of the VODER study
discuss changes in the system ownership and provides an example where a business
owner could have a maximum hourly demand of 50 kW when s/he installs a generation
system, but a new owner may only operate with a maximum hourly demand of 25 kW.
Please respond to the following.
a. Please explain whether this situation could increase the exported amount.
b. Please explain whether this situation could cause any safety or reliability
issues to the Company's system.
c. Please explain what mechanism(s) is(are) necessary to sufficiently address
issues caused by change of ownership.
d. Please provide the estimated costs of implementing the mechanism(s).
RESPONSE TO REQUEST FOR PRODUCTION NO. 13: Please see the following
responses regarding project eligibility cap:
a. There would likely be an increase in exports based on the reduced peak
demand. However, this isn't definitive and would depend on the original load
factor compared to the new load factor.
b. !t is not likely that this situation would cause a safety or reliability issue.
c. The Company believes this is both a policy and administrative issue - not a
safety or reliability issue. A solution could be that the new customer must
curtailthe generation to match the new peak load.
d. Curtailing the generation could require an inverter maximum output settings
change, if possible, or disconnecting a portion of the array. The Company has
not yet evaluated other potentia! administrative costs necessary for
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 19
incremental personnel to monitor and follow up with the new customer to
adjust the inverter.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO POV'JER GOMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSTON STAFF TO IDAHO POWER COMPAT.IY - 20
REQUEST FOR PRODUCTION NO. 14: Appendix 4.8 provides data to estimate
the value of non-firm energy relative to firm energy. Please answer the following:
a. Please clariff the significance of the HL and LL designations, the significance
of Schedule A purchases and Schedule B purchases, and how each of the
above pertain to the Appendix's purpose.
b. PIease explain why 12 of the 25 HL purchases are duplicated as LL
purchases (same date, prices, and price ratios), which gives them double-
weight in determining the non-firm discount rate.
RESPONSE TO REQUEST FOR PRODUCTION NO. 14: Please see the following
responses regarding Appendix 4.8 and non-firm energy purchases:
a. ldaho Power reviewed all firm and non-firm physical energy transactions
conducted between 2016 and 2021 to determine how the value of non-firm
energy actually compared to the value of firm energy, and ultimately calculate
a non-firm adjustment factor that can be applied to a firm energy price. The
result of this analysis is provided in Appendix 4.8. The data is segmented by
Heavy Load ("HL") and Light Load ("LL"), which are industry standard time
blocks for demand and price, and by Schedule (A, B, and C), which pertains
to the firmness of the energy being transacted. Each of these designations
are discussed in detail in the following paragraphs.
Generally, the demand for electricity is lower in the late evening hours,
early morning hours, on weekends and on holidays than it is during daytime
and early evening hours on weekdays. For this reason, the electric industry
places usage periods into two primary categories: HL and LL. Idaho Power
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 21
follows the North American Energy Standards Board ("NAESB') definitions
for HL and LL hour designations for the Western lnterconnectionl, which
specifies the following:
. Heaw Load Hours: Hours-ending 0700 - 2200 Monday through
Saturday
. Lioht Load Hours: Hours-ending 2300 - 0600 Monday through
Saturday, all hours on Sundays and all hours on New Year's Day,
Memorial Day, lndependence Day, Labor Day, Thanksgiving Day,
and Christmas Day. lf holidays fal! on a Sunday, the following
Monday will be considered a Light Load Hour day. Otherwise, the
Light Load Hour day will be the holiday itself
Because it is industry practice to segment demand by HL and LL, it is
typical for energy prices to also be segmented by HL and LL. The
lntercontinental Exchange ('lCE') Mid-Columbia ("Mid-C") index and forward
prices are examples, which are quoted by HL and LL periods, not by hour.
Due to demand and pricing being segmented by HL and LL, the purchase
and sale of energy is most commonly transacted in 16-hour (HL) and 8-hour
(LL) blocks.
ln Case No. IPC-E-13-25, due to the availability of daily HULL index
prices for firm and non-firm energy, parties were able to calculate weighted
average prices for all hours and determine a single non-firm adjustment factor
of 82.4o/o. For the non-firm analysis presented in Appendix 4.8, separate non-
I North American Energy Standards Board \Alholesale Electric Quadrant Business Practice Standards,
WEQ-OO7-A.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 22
firm adjustment factors are provided for HL and LL due to the nature of the
dataset and to properly account for the difference in the value of firm and non-
firm energy during these two periods. More specifically, historical non-firm
energy transaction data is limited in comparison to firm energy transaction
data, i.e., transactions for firm energy are much more common than
transactions for non-firm energy. The dataset includes numerous days in
which non-firm transactions occurred for either HL or LL hours, whereas firm
transactions occurred for both HL and LL hours.
ln order to make an apples-to-apples comparison of the value of firm
and non-firm energy in these instances, ldaho Power calculated a weighted
average HL or LL price for firm and non-firm energy depending on the data
available for non-firm transactions. As an example, on December 28,2016,
the Company purchased non-firm energy for HL hours only. The Company
also purchased firm energy on this day, for both HL and LL hours, the prices
for which were different. Calculating a weighted average price for firm energy
for the day, using both the HL and LL hour volumes and prices, would skew
the value and ultimately the comparison of the value of firm and non-firm
energy.
The non-firm analysis presented in Appendix 4.8 also designates
historical energy transactions by Schedule (A, B, and C), which pertains to
the firmness of the energy being transacted and is contractually agreed upon
by the seller and purchaser. These service schedules are defined in the
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY .23
WSPP lnc.2 First Revised Rate Schedule FERC No. 6 ("WSPP Agreement')3.
Definitions of Service Schedules A, B and C per the WSPP Agreement are
provided below. Please reference the FERC approved rate schedule for full
details.
Service Schedule A is for Economy Energy Service, which is defined
as a non-firm energy transaction whereby the seller has agreed to sell or
exchange, and the purchaser has agreed to buy or exchange energy that is
subject to immediate interruption upon notification. Under this schedule,
unless otherwise agreed to, the purchaser shall be responsible for
maintaining operating reserve requirements as back-up for Economy Energy
Service purchased and the seller shall not be required to maintain such
operating reserves.
Service Schedule B is for Unit Commitment Service, which is defined
as a capacity and/or associated scheduled energy transaction or a physically-
settleda option under which the seller has agreed to sell, and the purchaser
has agreed to buy from a specified unit(s) for a specified period. Under this
service schedule, scheduled energy deliveries may be interrupted or curtailed
as follows:
2 WSPP lnc. administers a multi-lateral, standardized agreement, under a FERC accepted or approved
rate schedule (Rate Schedule FERC No. 6), that facilitates physical transactions in capacity and/or
energy between members and is available to entities (which qualiff for membership) throughout the entire
continental United States, Canada, and Mexico. https:/Arww.wspp.org/pages/Overview.aspx
3 https://etariff.ferc.oovffariffBrowser.aspx?tid= 1 036
a A physically-settled option includes a call option which is the right, but not the obligation, to buy an
underlying power product as defined under Service Schedules B or C according to the price and exercise
terms set forth in the agreement; and a put option which is the right, but not the obligation, to sell an
underlying power product as defined under Service Schedules B or C according to the price and exercise
terms set forth in the agreement.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY .24
(1) By the seller by giving proper recall notice to the purchaser if the
seller and purchaser have mutually agreed to recall provisions,
(2) By the seller when all or a portion of the output of a unit is
unavailable, by an amount in proportion to the amount of the
reduction in the output of the unit, unless otherwise agreed by the
schedulers,
(3) By the seller to prevent system separation during an emergency,
provided the seller has exercised all prudent operating alternatives
prior to the interruption or curtailment,
(4) \Nhere applicable, by the seller to meet its public utility or statutory
obligation to its customers, or by either the seller or the purchaser
due to the unavailability of transmission capacity necessary for the
delivery of scheduled energy.
Service Schedule C is for Firm Capacity/Energy Sales or Exchange
Service, which is defined as a firm capacity and/or energy transaction
whereby the seller has agreed to sell or exchange, and the purchaser has
agreed to buy or exchange for a specified period available capacity with or
without associated energy which may include a physically-settled option and
a capacity transaction. Once an agreement is reached, the obligation for firm
capacity/energy sale or exchange service becomes a firm commitment, for
both parties, for the agreed service and terms. Firm capacity/energy sales or
exchange service shall be interruptible only if interruption is:
(1) Within any recall time or allowed by other applicable provisions
governing interruptions of service, as may be mutually agreed to by
the seller and purchaser,
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 25
(2) Due to an uncontrollable forces, or
(3) Where applicable, to meet seller's public utility or statutory
obligations to its customers; provided, however, this shall not be
used to allow interruptions for reasons other than reliability of service
to native load.
lf service under Service Schedule C is interrupted for any reason other
than pursuant to parts (a) or (b), the non-performing party shal! be responsible
for payment of damages per the terms of the agreement.
b. Staff correctly identified an error in Appendix 4.8. \Men determining the daily
weighted average prices for firm and non-firm energy, the Company
inadvertently made a cell reference error in the formula. After making the
correction, the HL Average Non-Firm Adjustment is 79% and the LL Average
Non-Firm Adjustment is 85%. Idaho Power has provided an aftachment with
an updated worksheet for the non-firm analysis with this response. The
updated analysis supports continued use of an 82.4o/o adjustment factor as a
reasonable basis for determining the value of non-firm energy.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
5 ld. at 3. Uncontrollable Force may include and is not restricted to flood, drought, earthquake, storm, fire,
lightning, epidemic, war, riot, act of terrorism, civil disturbance or disobedience, labor dispute, labor or
material shortage, sabotage, restraint by court order or public authority, and action or nonaction by, or
failure to obtain the necessary authorization or approvals from, any governmental agency or authority,
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 26
REQUEST FOR PRODUCTION NO. 15: Please provide summer (June 15 -
September 15) load curve data that excludes Schedule 6, 8, & 84 exports. Using this data
as the basis, identify a logical On-Peak time window for the Export Credit Rate program.
lf this window differs from the Demand Response Program hours (3 to 11 p.m., Monday
through Saturday, excluding holidays), provide analysis of the pros and cons of each
window.
RESPONSE TO REQUEST FOR PRODUCTION NO. 15: Please see Excel
attachment for the requested load curve data that excludes Schedule 6, 8, and 84 exports.
The logical On-Peak time window for an ECR aligns with ldaho Powe/s Demand
Response ("DR") Program parameters. The current DR Program parameters were
designed to operate during the Company's calculated highest-risk hours using the
internally developed Loss of Load Expectation tool. During the development of the
VODER Study, ldaho Power found that the highest-risk hours did not change from those
identified during the design of the current DR Program parameters. As further verification,
the Effective Load Carrying Capability ('ELCC') calculated for the seasonal time variant
ECR is the same as the ELCC calculated for the flat annual ECR, which can be referenced
in Sections 4.2.3.1 and 4.2.3.2 of the VODER Study report.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO POIA'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 27
REQUEST FOR PRODUCTION NO. 16: Order No. 35284 at 16, states the
VODER study should "evaluate peak-hour pricing or another variable pricing mechanism
so on-site generators who invest in storage can realize the value of their investment when
they export stored energy." Please identiff where in the VODER study this was analyzed.
lf this was not analyzed in the VODER study, please provide the Company's analysis.
RESPONSE TO REQUEST FOR PRODUCTION NO. 16: Seasona! time-variant
pricing was evaluated in Sections 4.1.2.2,4.2.3.2, and 4.3.2. The Summary in Section
4.7 also includes a time variant ECR. A customer that invests in energy storage could
charge the system when energy prices are typically low and discharge the system when
energy prices are typically higher.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY -28
REQUEST FOR PRODUCTION NO. 17: Please explain the method used to
average the pricing data in Appendices 4.2 and 4.3. The '2019-2021 Avg' spreadsheet
averages the corresponding data from the2021,2020, and 2019 tabs. However, it aligns
Friday, January 1,2021, with Friday, January 3,2020, with Friday, January 4,2019, and
maintains this differential through the entire year. At the end of the year - because of the
differential - the last few days of 2021 are averaged with blank data cells in 2020 and
2019. Please verify if the intent is to align the data by days of the week. Please clarify
the intent and correct the appendices if needed, including Appendices 4.6 and 4.7 that
use this data.
RESPONSE TO REQUEST FOR PRODUCTION NO. 17:System loads are both
dependent on customer activities and temperatures. As a result, the market prices tend
to follow those dependencies, which results in seasonal price changes. !n general,
customer energy use differs between weekdays and weekends, which results in market
prices changing based on the day of the week. The average energy prices were
calculated by "aligning" the days of the week in each calendar year to reflect the weekly
variation in market prices. As noted, it aligned January 1, 2021, with Friday, January 3,
2020, with Friday, January 4,2019, and maintains this differential for each hour.
As stated in the request, the last 72 hours of the year averaged hourly historical
prices with at least one blank data cell. Blank cells do not factor into the average;
therefore, the last 72 hours of data simply use 2021 prices or an average of 2021 and
2020 prices. This spreadsheet works as intended and does not require modification.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 29
REQUEST FOR PRODUCTION NO. 18: ln reference to the Appendices 4.2 and
4.3, please explain whether 2020 energy prices are significantly anomalous to the price
trends occurring over a longer period. lf so, discuss possible alternatives such as
removing the year 2020s data from the average or including an alternate year.
RESPONSE TO REQUEST FOR PRODUCTION NO. 18: The Company does not
believe 2020 energy prices are significantly anomalous. System loads are dependent on
both temperatures and customer activities. As a result, the market prices tend to have
seasonal and year-over-year changes to reflect those variables. For instance, the 2020
late spring weather conditions were cooler and wetter than usual, which resulted in energy
loads and slightly lower market prices. However, in 2021, the Pacific Northwest
experienced a "heat dome," which led to record-setting high temperatures (highest
temperatures in 100 years). ln addition, in 2021, there were drought conditions which
resulted in less hydropower available. Both conditions led to higher than usua! market
prices in2021. Because year-over-year conditions result in differing market prices, using
a three-year average tends to remove some of the variability in the pricing.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 30
REQUEST FOR PRODUCTION NO. 19: Order No. 35284 al 17, states the
VODER study should "evaluate firmness of energy for individual customers compared to
firmness as a combined class evaluate firmness of energy for customers with energy
storage devices compared to those without energy storage devices." Please identify
where in the VODER study this was analyzed. lf this was not analyzed in the VODER
study, please provide the Company's analysis.
RESPONSE TO REQUEST FOR PRODUCTION NO. 19: The VODER Study
defines firm energy in the glossary as energy that is to be scheduled, delivered, sold,
received, and purchased on an uninterruptible basis. Page 42 of the VODER Study
states: "ln evaluating the exported energy from customer-generators, the Commission-
approved Study Framework stated that the value should reflect that energy received from
on-site customer-generators is non-firm. Customer-generator exports are non-firm
because there is no obligation for a customer-generator to export energy." DERs, whether
generation facilities or energy storage devices, export non-firm energy because there is
no obligation for a customer to export energy on an uninterruptible basis.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 31
REQUEST FOR PRODUCTION NO. 20: Please provide the following regarding
the Effective Load-Carrying Capacity ("ELCC") factor in Section 4.2 of the Study:
a. Appendix 4.12 lists the ELCC value for 2020 as 4.32Qo/o and for 2021 as
10.918%. Please explain why these values varied so significantly from year
to year. Explain the rationale for averaging the two years, especially af 2020
was anomalous.
b. Please explain why the ELCC result for the Net Hourly scenario o13.420o/o
is less than half of the Real-Time scenario result of 7.6190/o.
RESPONSE TO REQUEST FOR PRODUCTION NO. 20: Please see the below
responses regarding the ELCC values in Section 4.2 of the VODER Study:
a. As stated in response to Request No. 18, the Company does not agree that
the year 2020 was anomalous. The 2020 and202l calculated ELCC values
differ primarily due to the alignment of the specific year's customer-
generator exports output and the highest-risk hours. The highest-risk hours
of a particular year are driven by weather and Variable Energy Resource
('VER") output, which can vary significantly from year-to-year. A robust
ELCC calculation is derived from multiple data years to capture the
previously mentioned year-to-year variability. Only 2020 and 2021
customer-generator export data were available when the VODER Study
was conducted. The implementation approach could include updating and
incorporating more annual data as it becomes available, as mentioned in
Section 4.2.2.1 (page 48) of the VODER Study.
b. The differences between the Net Hourly and Real-Time ELCC values are
]DAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.32
due to the differences between the measurement intervals for each data
set. The Real-Time scenario generally results in more exports over peak
hours than the Net Hourly scenario, which corresponds with a higher
capacity contribution. As an example, air conditioners often cycle
throughoutthe hourwhich willdrive up real-time exports but may be masked
by an hourly measurement interval. A detailed explanation of the hourly and
real-time measurement intervals is available in Section 3 of the VODER
Study.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.33
REQUEST FOR PRODUCTION NO. 21: Please provide the following regarding
the National Renewable Energy Laboratory ('NREL") 8760 capacity factor in Section 4.2
of the Study:
a. The underlying data for derivation of the NREL 8760 capacity values (i.e., the
top 100 hours of Load-Duration Curve ("LDC'), Net Load-Duration Curve
("NLDC"), and the difference)
b. Appendix 4.12 lists the NREL 8760 value as 8.014% for 2020 and 12.608%
for 2021. Please explain why these values varied significantly from year to
year. Explain the rationale for averaging the two years, especially if 2020 was
anomalous.
c. Please explain why the NREL 8760 result for the Net Hourly scenario of
6.1790/o is nearly half of the Real-Time scenario result of 10.3'l1o/o.
RESPONSE TO REQUEST FOR PRODUCTION NO. 2{: Please see the below
responses regarding NREL 8,760-based method values in Section 4.2 of the VODER
Study:
a. The NREL 8,760-based method Load-Duration Curve (LDC) and Net Load-
Duration Curve (NLDC) top 100 hours for the Net-Hourly data (and the
corresponding difference between the two curves) have been provided in the
attached Excel spreadsheet for both 2020 and2021. The NREL 8,760-based
method defines the capacity contribution as the difference in the areas
between the LDC and NLDC during the top 100 hours. To calculate the area
between the two curves, ldaho Power utilized the Trapezoidal Rule for
lntegration which evaluates the area under the curves by dividing the total
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 34
area into smaller trapezoids. lf a different method is used to determine the
area between the LDC and NLDC, slight differences in results may occur.
b. Please reference response to Request No. 20a.
c. Please reference response to Request No. 20b.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANYS RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POVVER COMPAi.IY.35
REQUEST FOR PRODUCTION NO. 22: Although the NREL capacity factor was
35% larger than the ELCC factor, the ELCC factorwas used for all subsequent scenarios
and analyses. Please provide the rationale for using the ELCC factor.
RESPONSE TO REQUEST FOR PRODUCTION NO. 22: The methodologies to
evaluate capacity continue to evolve and improve as more renewable generation is
integrated grid-wide. The Effective Load Carrying Capability (ELCC) method is the current
industry standard for calculating the capacity contribution of variable energy resources.
As such, it was adopted by Idaho Power for capacity calculations in the Company's2021
lntegrated Resource Plan (!RP) filed in Case No. IPC-E-2143. Further explanation
regarding the ELCC method is available in the Loss of Load Expectation section of the
2021 IRP Appendix C: Technical Report, starting on page 96.
As explained in Section 1 of the VODER Study, there is no advocation for a single
position regarding potential modifications to ldaho Powe/s net metering service, but
rather the exploration of several methods that value customer on-site generation energy
exports. The VODER Study used the ELCC method in summary figures as it is both the
industry standard, and the method utilized in the Company's 2021 lRP. The results of
both the ELCC and NREL 8,760-based methods are provided in Appendix 4.16 of the
VODER Study.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.36
REQUEST FOR PRODUCTION NO. 23: Order No. 35284 at 18, states that the
VODER study should evaluate the "potential differences between customers with and
without storage" with respect to avoided capacity costs. Please identify where in the
VODER study this was analyzed. lf this was not analyzed in the VODER study, please
provide the Company's analysis.
RESPONSE TO REQUEST FOR PRODUCTION NO. 23: The Company analyzed
the potential differences between customers with and without storage for avoided
capacity costs in Sections 4.2.3.1 and 4.2.3.2 of the VODER Study. ln Section 4.2.3.1,
the ELCC was calculated using customer-generator export data for all hours of the year;
in Section 4.2.3.2, the ELCC was calculated using customer-generator export data but
was limited to June 1Sth to September 1Sth,3:00 p.m. to 11:00 p.m., Mondaythrough
Saturday. A customer that invests in energy storage could charge the system outside the
parameters mentioned above and discharge the system during the identified hours.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 37
REQUEST FOR PRODUCTION NO. 24: Please explain why the Nameplate
Capacity value of 64.11 MW was used to calculate the Avoided Capacity Cost. Please
provide any workpapers supporting this value.
RESPONSE TO REQUEST FOR PRODUCTION NO. 24: The cumulative
nameplate capacity of active projects installed at the end of 2020 was 64.11 MW. By
selecting the operational projects at the end ol 2020, data for at least one full year was
available. The ELCC and the NREL 8,760-based methods provide capacity contribution
results as percentages whose calculations utilize a nameplate capacity of the resource
under review and can be used for different amounts of penetration levels in the system.
The attached Excel spreadsheet provides the data supporting the nameplate capacity
value of 64.11 MW.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, ldaho Power Company.
IDAHO PO\A/ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 38
REQUEST FOR PRODUCTION NO. 25: ln Table 4.8 of the VODER study,
combined transmission, distrlbution, and transformer losses are displayed as a
percentage of total load, which implies that they are all load-dependent. However, pages
58 and 59 of the VODER study, assert that transformer losses are constant and not
avoidable for customer-generated exports, and therefore ignores those losses. PIease
provide a detailed explanation as to why transformer losses are not being counted.
RESPONSE TO REQUEST FOR PRODUCTION NO. 25: As described in Section
4.4.'l of the VODER Study, transformer losses consist of significant core and winding
losses. Core losses occur from energizing the laminated steel core in the transformer,
and winding losses occur from current flowing through the windings of the transformer.
The core losses do not change based on the amount of load on the system while winding
losses are proportional to the amount of load connected to the transformer. Because
transformer core losses are not a function of load, these losses are not avoidable by DER
exports and were therefore excluded from the calculation of avoided line losses.
The response to this Request is sponsored by Jared L. Ellsworth, Distribution &
Resource Planning Director, Idaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 39
DATED at Boise, ldaho, this 24th day of August2022.
fr;fr.ff"u,.-*,
LISA D. NORDSTROM
Attomey for ldaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POVUER COMPANY - 40
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 24th day of August 2022, I served a true and
correct copy of ldaho Power Company's Response to the First 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:
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 41
Commission Staff
Riley Newton
Deputy Attorney General
ldaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8
Suite 201-A (83714)
PO Box 83720
Boise, lD 83720-0074
_Hand Delivered
_U.S. Mail
_Overnight Mail
_FAX
FTP SiteXEmail [e-mail]
ldaHydro
C. Tom Arkoosh
Amber Dresslar
ARKOOSH LAW OFFICES
913 W. River Street, Suite 450
P.O. Box 2900
Boise, ldaho 83701
_Hand Delivered
_U.S. Mail
_Overnight Mail
_FAX_FTP SiteX Email [e-mail]
Amber.d ressla r@arkoosh. com
erin.cecil@a rkoosh. com
ldaho Conservation League
Marie Kellner
ldaho Conservation League
710 North 6th Street
Boise, ldaho 83702
_Hand Delivered
_U.S. Mai!
_Overnight Mai!
_FAX_FTP SiteX Email [e-mail]
ldaho lrrigation Pumpers Association, lnc.
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Avenue, Suite 100
P.O. Box 6119
Pocatello, !daho 83205
_Hand Delivered
_U.S. Mail
_Overnight Mail
_FAX_FTP SiteX Email [e-mail]
Lance Kaufman, Ph.D
4801 W. Yale Ave.
Denver, CO 80219
_Hand Delivered
_U.S. Mail
_Overnight Mail
_FAX_FTP SiteX Email [e-mail]
City of Boise
Mary Grant
Deputy City Attorney
Boise City Attorney's Office
150 North Capitol Boulevard
P.O. Box 500
Boise, ldaho 83701 -0500
_Hand Delivered
_U.S. Mail
Overnight Mai!
_FAX_FTP SiteX Email [e-mail]
bo isecitvatto rnev@citvofbo ise. orq
VUil Gehl
Energy Program Manager
Boise City Dept. of Public Works
150 N. Capitol Blvd.
PO Box 500
Boise, ldaho 83701-0500
_Hand Delivered
_U.S. Mail
_Overnight Mail
_FAX_FTP SiteX Email [e-mail]
lndustrial Customers of ldaho Power
Peter J. Richardson
RICHARDSON ADAMS, PLLC
515 North 27th Street (83702)
P.O. Box 7218
Boise, ldaho 83707
_Hand Delivered
_U.S. Mail
Overnight Mail
_FAX_ FTP SiteX Email [e-mail]
Dr. Don Reading
6070 Hill Road
Boise, ldaho 83703
_Hand Delivered
_U.S. Mai!
_Overnight Mail
_FAX_ FTP SiteX Email [e-mail]
Micron Technology, lnc.
Austin Rueschhoff
Thorvald A. Nelson
Austin W. Jensen
Holland & Hart, LLP
555 Seventeenth Street, Suite 3200
Denver, Colorado 80202
Hand Delivered
U.S. Mai!
Overnight Mail
_ FAX
_FTP SteX Email [e-mail]
[e-mail]
awiensen@holland hart.com
Jim Swier
Micron Technology, lnc.
8000 South FederalWay
Boise, ldaho 83707
Hand Delivered
U.S. Mai!
Overnight Mail
_ FAX
_ FTP Site
-[Email [e-mail]
aclee@holla nd hart. com
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.42
Clean Energy Opportunities for ldaho
Kelsey Jae
Law for Conscious Leadership
920 N. Clover Dr.
Boise, ldaho 83703
Hand Delivered
U.S. Mail
Overnight Mai!
_ FAX
_ FTP SiteX Email [e-mail]
Michael Heckler
Courtney \Mite
Clean Energy Opportunities for ldaho
3778 Plantation River Dr., Suite 102
Boise, lD 83703
_Hand Delivered
_U.S. Mail
Overnight Mail
_FAX_FTP Site
X Email
cou rtnev@cleane ne rqvopportu n ities. com
mike@cleanene rovopoortu n ities. com
Richard E. Kluckhohn, pro se
Wesley A. Kluckhohn, pro se
2564 W. Parkstone Dr.
Meridian, lD 83646
Hand Delivered
U.S. Mail
Overnight Mai!
_ FAX
FTP SiteX Email [e-mail]
[e-mail]
ldaho Solar Owners Network
Joshua Hill
1625 S. Latah
Boise, ID 83705
Hand Delivered
U.S. Mail
Overnight Mail
_ FAX
FTP SiteX Email [e-mail]
[e-mail]
ABC Power Company, LLG
Ryan Bushland
184 W. Chrisfield Dr.
Meridian, lD 83646
Hand Delivered
U.S. Mail
Overnight Mai!
_ FAX
FTP SiteX Email [e-mail]
[e-mail]
&r"j.
Stacy Gust, Regulatory Administrative
Assistant
IDAHO PO\A/ER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY -43
BEFORE THE
IDAHO PUBLIC UTILI,TIES COMMISS]ON
cAsE NO. IPG-E-22-22
IDAHO POWER COMPANY
REQUEST NO. 14
ATTACHMENT NO. 1
SEE ATTACHED SPREADSHEET
IDAHO PUtsLIC UT]LITIES COMMISSION
GASE NO. IPC-E-22-22
IDAHO POWER COMPANY
REQUEST NO. 15
ATTACHMENT NO. 1
SEE ATTACHED SPREADSHEET
BEFORE THE
IDAHO PUBLIG UTILITIES GOMMISSION
CASE NO. IPC-E-22-22
IDAHO POWER COMPANY
REQUEST NO.21
ATTACHMENT NO. 1
SEE ATTACHED SPREADSHEET
BEFORE THE
IDAHO PUtsLlC UTILITIES COM.MISSION
CASE NO. IPC-E-22-22
IDAHO POWER COMPANY
REQUEST NO.24
ATTAGHMENT NO, 1
SEE ATTACH ED SPREADSHEET