20220909IPC to Staff 26-55.pdf

3Em.
An IDACORP CompanY
Megan Goicoechea Allen
Corporate Counsel
[e-mail]
September 9,2022
VIA ELECTRONIC FILING
Jan Noriyuki, Secretary
ldaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83724
Boise, ldaho 83720-007 4
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, 8 and 84 for Non-Legacy Systems
Dear Ms. Noriyuki:
Attached for electronic filing is ldaho Power Company's Response the Second
Production Request of 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,
Wloi0d^!^0010,,1
Megan Goicoechea Allen
MGA:sg
Attachments
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]
ln o rd strom@ ida hopowe r. com
mqoicoecheaa llen@ ida hopower.com
Attorneys for ldaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
!N 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 AUTHORITY 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 SECOND
PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO
POWER COMPANY
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COMES NOW, ldaho Power Company ('ldaho Powef or "Company"), and in
response to the Second Production Request of the Commission Staff ('Commission" or
'Staff') dated August 19,2022, herewith submits the following information:
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 1
REQUEST FOR PRODUCTION NO. 26: Appendices 4.4 and 4.5 are the net
hourly and real-time exports for year 2021 . Please provide Appendices 4.4 and 4.5 broken
out by Schedule 6, 8, and 84. Please clariff how the Schedule 84 customer data is netted
for two-meter customer implementations.
RESPONSE TO REQUEST FOR PRODUCTION NO. 26: Please see the
Attachment 1 to this response for the data in Appendices 4.4 and 4.5 broken out by
Schedule 6, Residential Service On-Site Generation ("Schedule 6'), Schedule 8, Small
Genera! Service On-Site Generation ('Schedule 8"), and Schedule 84, Customer Energy
Production Net Metering Service ('Schedule 84'). For Schedule 84, the data has been
further broken down between commercial and irrigation customers.
The hourly net values for Schedule 84 customer data in two-meter
interconnections are calculated by subtracting the hourly generation meter reads from the
hourly consumption meter reads.
The response to this Request is sponsored by Jordan Prassinos, Load Research
and Forecasting Manager, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMTSSION STAFF TO IDAHO POWER COMPANY - 2
REQUEST FOR PRODUCTION NO. 27: The Value of Distributive Energy
Resources ("VODER') study at 41 discusses the calculation of avoided cost of energy
based on seasonal time-variant export credit values, using the seasonal and time
differentials of the Company's Demand Response Program.
a. Please explain why a capacity-related on-peaUoff-peak time differentiation
is used for determining a time-differentiated avoided cost of energy rate.
b. Please provide justification for the proposa! of using the seasona! and time
differentials (on-peak and off-peak) of the Demand Response Program.
c. Please explain why the Company did not use othertypes of capacity-related
on-peaUoff-peak time differentiations such as: (1) The peaUnon-peak
information approved in Order No. 35294 in Case No. IPC-E-21-35; (2) The
highest risk hours under the Effective Load Carrying Capability ('ELCC)
method; (3) The highest risk hours under the National Renewable Energy
Laboratory ("NREL') 8760 method. ln your response, please explain what
the highest risk hours are under the ELCC method and the NREL 8760
method, respectively.
d. PIease explain why the Heavy Load period and the Light Load period
described in the VODER study at 37 are not used to determine a time-
differentiated avoided cost of energy rate.
RESPONSE TO REQUEST FOR PRODUCTION NO. 27: Please see the following
responses regarding the calculation of avoided cost of energy based on a seasonal time-
variant export credit value:
IDAHO PO\A/ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 3
a.Energy is more expensive at certain times of the year and day, depending
on market conditions. A time-variant credit values excess generation
exports based on the time they are delivered to the utility, providing a higher
credit when electricity is worth more. The times when energy has the
highest value generally align with the times capacity is most needed.
The Company utilized the identified season containing the hours of highest
risk, which was a result of the Loss of Load Expectation (.LOLE') analysis
adopted lor the 2021 Integrated Resource Plan ("lRP"). The identified
seasonal parameters from the Company's filing for the modification of the
Demand Response ("DR") seasonal parameters in Case No. IPC-E-21-32
align with the capacity-related on-peaUoff-peak time differentiations used
in the VODER Study ('Study"). The procurement of new resources depends
upon the identified hours of highest risk, which is why the Study utilized the
LOLE analysis when selecting the hours for the seasonal time variant
portion of the Study. Attachment 1 to this response includes the heatmaps
that were submitted in Case No. !PC-E-21-32. The heatmaps provided
show the Loss of Load Probability ("LOLP') for each hour during the months
of July and August under various amounts of solar generation. The
Company included two different test years to show the difference in LOLPs
in different calendar years to capture the weather variability and its impact
on the highest risk hours. The heatmaps show how the highest risk hours
start shifting as the amount of solar generation on the system increases.
The hours between 3 pm and11 pm, between June 15 and September 15,
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY -4
b.
c.
cover approximately 99 percent of the highest risk hours. Aftachments 2-5
to this response include the underlying data required to calculate the LOLPs
for each of the four different test years used in Case No. IPC-E-21-32.
The Company did not use the referenced capacity-related on-peaUoff-peak
time d ifferentiations because:
1) The peaUnon-peak information approved in Order No. 35294 in
Case No. IPC-E-21-35 concerned the capacity payment calculations
for battery storage resources in the lncremental Cost lntegrated
Resource Plan ("lClRP') avoided cost model, which uses the 2019
IRP LOLP methodology. As described above, the Study used the
most recently adopted methods from the 2021 IRP to value capacity
in a consistent manner.
2) The ELCC method calculated hours of highest risk by year
depending on various factors, including weather and load. However,
the seasona! parameters identified in Case No. IPC-E-21-32
encompass nearly allof the highest risk hours specified in the Study.
Appendix 4.12 of the Study (sheet "ELCC_Tests") shows that the
variation of customer-generator exports ELCCs is within the margin
of error of the Company's LOLE tool, again demonstrating that the
modified DR seasona! parameters envelop nearly allthe highest risk
hours. For more information on the highest risk hours under the
ELCC methodology, please refer to section 4.2.1.1 of the Study.
3) The NREL 8,760-based method's top 100 net load hours vary by
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 5
year depending on various factors, including weather and Ioad. The
Company determined that utilizing an analysis that only considers
100 hours, which change by year, is not a reasonable approach for
determining a value for customergenerator exports compared to the
ELCC but included the method in the study for comparative
purposes. For more information on the highest risk hours under the
NREL 8,760-based methodology, please refer to section 4.2.1.2 ol
the VODER Study.
d. The Export Credit Rate ("ECR") examples presented in the Study are
intended to provide a general sense of potential energy prices. lf actual ICE
Mid-C prices are chosen for the avoided cost of energy component, then
the export credit value would reflect the actual Heavy Load and Light Load
prices for the given hour that exports occur.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCT]ON REQUEST OF THE
COMMISSION STAFF TO IDAHO POVVER COMPANY - 6
REQUEST FOR PRODUCTION NO.28: Please explain why the Company did not
use other types of capacity-related on-peaUoff-peak time differentiations to calculate
avoided cost of capacity, such as: (1) the peaUnon-peak information approved in Order
No. 35294 (Case No. IPC-E-21-35); (2) the highest risk hours under the ELCC method;
(3) the highest risk hours under the NREL 8760 method.
RESPONSE TO REQUEST FOR PRODUCTION NO. 28: Please reference
Request for Production No. 27(bl and 27(c) for the explanation as to why the Company
did not use the referenced types of capacity-related on-peaUoff-peak time differentiations
in the Study.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POVWR COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISS]ON STAFF TO IDAHO POWER COMPANY - 7
REQUEST FOR PRODUCTION NO. 29: Please explain why the Company did
not use other types of capacity-related on-peaUoff-peak time differentiations to calculate
avoided transmission and distribution capacity costs, such as: (1) the peaUnon-peak
information approved in Order No. 35294 (Case No. IPC-E-21-35); (2) the highest risk
hours under the ELCC method; (3) the highest risk hours under the NREL 8760 method;
and (4) loca! peak hours.
RESPONSE TO REQUEST FOR PRODUCTION NO. 29: To calculate avoided
transmission and distribution capacity costs, the Study utilized each individual
transmission and distribution component's peak load shape profile. The shape profile is
used to identify the timing of each component's peak load. This approach determined
whether customer-generator exports could help defer the historical and forecast
investments identified. The peaUnon-peak information from Case No. !PC-E-21-35 and
the highest risk hours under the ELCC method would not apply at such a granular level.
The highest risk hours under the NREL 8760 method and local peak hours generally align
with the approach used in the Study.
Please reference Request for Production No. 27(b) and 27(c) for the explanation
as to why the Study did not use the referenced types of capacity-related on-peaUoff-peak
time differentiations in the Study to calculate the ECR.
The response to this Request is sponsored by Jared L. 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 POVVER COMPANY. S
REQUEST FOR PRODUCTION NO.30: Order No. 35284 at 18 states "[w]e also
find it reasonable and fair for the study to adopt the Company's offered improvements to
wording and clarification of the use of net peak. We direct the Company to study the use
of first deficit year, the identification and evaluation of methods for identiffing system
coincident peak, the exploration of different rate designs, and the evaluation of potential
differences between customers with and without storage."
a. Please identiff the first deficit year used in determining avoided cost of
capacity in the VODER study. lf this is not provided in the VODER study,
please provide it.
b. Please identiff the evaluation of methods for identiffing system coincident
peak in the VODER study. lf this is not provided in the VODER study, please
provide it.
RESPONSE TO REQUEST FOR PRODUCTION NO. 30: Please see the following
responses regarding avoided cost of capacity and evaluation
a. The Study utilized 2020 and 2021 data to calculate avoided generation
capacity (via the ELCC and NREL 8,760-based method). The analysis
was conducted as if the year in question were a deficit year. As described
in the 2021 lRP, the Company's first deficit year is 2023. The Company
expects to update this rate component periodically, and the Study supplied
indicative values under the assumption that a deficit existed.
b. The Study evaluated both the ELCC and NREL 8,760-based methods to
calculate avoided generation capacity. The NREL 8,760-based method
utilizes "net peak" to produce results. ldaho Power implemented the ELCC
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 9
methodology in lhe 2021 IRP which uses all resources (flexible and
variable) to assess and identiff the system's highest risk hours. This change
was made to capture the fact that as more VERs are added to the system,
highest risk hours will no longer necessarily align with peak hours. To
better capture reliability and account for evolving resource buildouts, the
Company did not utilize a methodology based on the system coincident
peak for evaluating avoided generation capacity in the Study.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMTSSION STAFF TO IDAHO PO\A'ER COMPANY - 1O
REQUEST FOR PRODUCTION NO. 3{: The VODER study at 47 states'ELCC
determines an individual generato/s contribution to the overall system reliability and is
primarily driven by the timing of the highest risk hours, or Loss of Load Probability
('LOLP") hours." Please explain what the highest risk hours are and how they are
determined.
The LOLP, or risk, is the
likelihood of the system load exceeding the available generating capacity during a given
period (typically an hour). The highest risk hours are those hours where the probability of
being unable to meet the demand is the highest. The following equation calculates the
LOLP:
LOL? = pi (Gi - Li)
\tVhere Pi is the cumulative probability of the available generation required to meet the
system demand at hour r, 6i is the available generation required to meet the system
demand at hour i, and L; is the net system load at hour i. For more information on the
LOLP calculation, please refer to the Loss of Load Expectation section on page 96 of the
2021 IRP's Appendix C, Technical Report.
The response to this Request is sponsored by Jared L. 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. 32: The VODER study at 48 discusses the
NREL 8760 method. Please confirm that the highest risk hours under this method are the
top 100 net load hours. If so, please provide the top 100 net load hours.
The NREL 8,760-based
method uses the top 100 net load hours as a prory for the hours of highest risk, however,
"net load" in the case of the NREL 8,760 methodology is simply load net solar, and does
not include energy limited resources such as demand response or storage, which require
a more robust approach to fully incorporate (the ELCC method). Please referto Response
to Request for Production No. 21(a), which includes the requested data and explanation
of how it was obtained.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 12
REQUEST FOR PRODUCTION NO. 33: The VODER study at 54 states "[t]o
determine the potential value of on-site generation in deferring or delaying the need for
ldaho Power to build T&D resources, the study identifies coincident peak hours."
Additionally, the VODER study at 55 states "the expected exports coincident with ldaho
Power system peak load at the location [and] [t]he avoided T&D cost values of VERs
[(Variable Energy Resources)] can be calculated using actual and proposed capacity
projects, the loca! area growth rates, and the local VER export values at the time of the
loca! peak."
a. Does the VODER study use coincident peak hours at the local level instead
of the system level to determine avoided transmission and distribution
capacity values?
b. If so, please explain why planning for transmission and distribution is based
on local coincident peak hours, instead of local net peak hours.
c. Please explain how system peak load at the location is determined.
d. Please define "local area growth rates" and explain how they are
determined.
e. Does "system peak load at the location" and "local peak" have the same
meaning? lf not, please explain.
RESPONSE TO REQUEST FOR PRODUCTION NO. 33: Please see the following
responses regarding transmission and distribution avoided capacity:
a. Yes. The Study uses coincident localized peaks to determine avoided
transmission and distribution capacity values. These localized peaks may
not coincide with the system level peaks.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.l3
b. The need for transmission and distribution capacity projects is based on the
local peak demand and the localcapacity. This !oca! peak demand may not
occur at the same time as the system peak.
c. The local peak load is determined from measured load data in the local
area. The measured load data provides the peak load time and the basis
for the peak load magnitude.
d. The local area growth rates are determined based on several factors,
including:
1) historical measured peak load,
2) the addition of known customer projects,
3) weather adjustments, and
4) a cubic regression to forecast load.
e. No, "system peak load at the location' and 'local peak" do not have the
same meaning. System peak load at the location is the coincident load at a
given area that coincides with the system peak load. A Iocal peak is the
peak load measured at a given site which may occur at a different time than
the system peak load.
The response to this Request is sponsored by Jared L. 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 - 14
REQUEST FOR PRODUCTION NO. 34: The VODER study at 54 states that
avoided transmission and distribution capacity costs would be paid only when "the
quantity of the export would need to be sufficient to exceed the planning capacity
shortfall". However, the quantity of the export is not required to exceed the Company's
capacity deficit to receive avoided generation capacity costs. Please explain why avoided
transmission and distribution costs are not counted the same way as avoided generation
capacity costs.
' RESPONSE TO REQUEST FOR PRODUCTION NO. 34: Avoided transmission
and distribution capacity benefits occur when an actual project can be deferred. The
Company evaluated projects over 20 years to determine how many projects could have
been deferred and for how long each project could have been deferred to obtain an ECR
value for the transmission and distribution deferral benefit that was spread over all the
customer exports. ln comparison, the avoided generation capacity captures the potential
to avoid, or reduce, the procurement of future resources and as such, cannot be evaluated
the same as the transmission and distribution deferral benefit.
Also, transmission and distribution projects result in discrete capacity increases
(i.e., step function), while capacity procurement can be done at a more granular level (i.e.,
continuous function). This difference occurs because typicaltransmission and distribution
equipment only comes in standard capacity sizes.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 15
REQUEST FOR PRODUCTION NO. 35: Please explain why the calculation of the
Export Credit Rate ("ECR") uses different time periods of data for different components
of the ECR. For example,2020 and 2021 historica! data is used to calculate capacity
contribution under the ELCC and NREL 8760 methods, whereas only the 2021 data is
used to calculate avoided transmission and distribution costs.
RESPONSE TO REQUEST FOR PRODUCTION NO. 35: The ECR calculation
uses different time periods of data for its components to recognize the various
methodologies utilized, accounting for and reducing year-to-year variability.
ELCC values are primarily driven by the timing of the highest risk hours. The top
100 hours of the NREL 8,760-based method serve as a proxy for the highest risk hours.
The two approaches are directly impacted by year-to-year variability because the
identified highest risk hours can change annually. The data used to calculate the
generation capacity value is based on two years of actual exported energy to capture
annual variability, which can be done because the ELCC and NREL 8,760-based
methods result in percentages. lt is reasonable to take an average over multiple years, to
normalize the data, and apply it to the current customer-generator nameplate. As page
48 of the Study indicates, as more data becomes available, the method could include
additional years in this calculation to reduce the year-to-year variability further.
The avoided transmission and distribution capacity value is based on localized
capacity needs and expected generation. The localized generation is estimated from
average expected generation by seasonal hour. The expected average seasonal hour
export is not based on the measured export of a single specific hour, but rather an
average export for the time of day across the season. This removes much of the year-to-
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 16
year variability which is why only one year of data was used when performing the avoided
transmission and distribution capacity cost calculations.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Porer Company.
IDAHO PO\'\'ER COMPANYS RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POI/VER COMPANY - 17
REQUEST FOR PRODUCTION NO.36: The VODER study at 55 states the data
used for calculating avoided transmission and distribution costs include each capacity
project's peak capacity and peak !oad, growth rate, and time of peak demand, as well as
system aggregate export shapes based on real-time and net-hourly energy measured in
2021. The VODER study at 56 also mentions "expected peak time exports".
a. Please explain how each capacity project's peak capacity is determined.
b. Please explain how system aggregate export shapes are determined based
on real-time and net-hourly energy, respectively.
c. Please define "Solar Contribution at Peak" on Tab "Growth Projects 2007-
2026" in Appendix 4.13 Transmission and Distribution Avoided Capacity
excelfile.
d. Please explain how the "Solar Contribution at Peak" is calculated.
RESPONSE TO REQUEST FOR PRODUCTION NO. 36: Please see the following
responses regarding avoided transmission and distribution capacity:
a. Planning limits are capacity thresholds set below the distribution equipment
therma! ratings to create increased operational margins. These capacity
limits are used to identiff voltage and capacity grid needs. The localized
peak capacity for each capacity project is based on the actual measured
load at that specific location, which is used to determine the peak load time.
Then, localized load growth is applied to the measured load to establish the
future localized peak load.
b. The customer-generator export shapes are determined by taking the actual
measured hourly energy exports, either real-time or net-hourly, and adding
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 18
the corresponding loss factor to each hour. The data is then parsed by
month, and an average is taken by the hour of the day - this calculation
results in a '12 by 24 data set. The data set is then normalized by dividing
each averaged data point by the maximum export value of the specified
year. Finally, the values for June through August are averaged to create a
summer expected hourly output, and December through February are
averaged to create a winter expected hourly result.
c. The solar contribution at peak represents the offtet to the loca! peak load
due to expected customer generation.
d. Customer-generator exports at the locational peak time were determined
based on the number of customers in each rate class connected at each
specific location. The total generation capacity available is determined
using the number of connected customers by rate class, an average system
size by rate class, and the location's current distributed energy resource
penetration level. Then, using the 2021 exported energy from customer-
generators, the average hourly summer and winter exported energy is
calculated as a percentage of connected customer-generator nameplate
capacity. These hourly values estimate the expected generation export for
the locational coincident peak time of day and season.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.l9
REQUEST FOR PRODUCTION NO. 37: Order No. 35284 at 19 states "[t]he
Commission finds it reasonable and fair to separately study avoided transmission costs
and avoided distribution costs. ln doing so, the study should consider: (a) whether exports
avoid construction or delay construction, (b) individual customer-generators versus a
class, and (c) configurations with and without storage."
a. Section 4.3.2 of the VODER study only discusses calculations for project
deferra!. Please identiff where an analysis of project avoidance is
conducted in the VODER study. lf this is not provided in the VODER study,
please provide it.
b. Please identifo where an analysis of individual customer-generators versus
a class is conducted in the VODER study. lf this is not provided in the
VODER study, please provide it.
c. Please identify where an analysis of configurations with and without storage
is conducted in the VODER study. lf this is not provided in the VODER
study, please provide it.
RESPONSE TO REQUEST FOR PRODUCTION NO. 37: Please see the following
responses regarding avoided transmission and distribution costs:
a. An analysis of project avoidance was not conducted. Transmission and
distribution capacity projects are based on anticipated load growth.
Exported customer generation has the potentialto defer a capacity project;
however, eventually, the localized load growth will result in more capacity
need than the exported customer generation can meet. Also, the maximum
reduction recognizes that the potential to reduce the peak load is limited,
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMM]SSION STAFF TO IDAHO POWER COMPANY - 20
partly because the peak will shifi as solar penetration increases to a time
later in the day when solar is no longer available.
b. The method to determine the transmission and distribution avoided capacity
projects used the expected exports for all customer generation projects. The
Study did not evaluate exports or avoided projects by individual customer-
generators versus a class because the size of the transmission and
distribution deferral component was already sma!!, and further splitting out
the value by class would not result in meaningful change to the ECR. Out
of 447 projects reviewed, nine projects were identified for deferral. Appendix
4.13 includes the calculation of the annualized deferralvalue of $15,363.
c. The Study did not include a separate analysis for systems with and without
energy storage due to the low level of this resource type currently on the
system (less than one percent of all customer-generators by nameplate
capacity) and an inability to differentiate between behind-the-meter
resources. Whether the resource behind the meter is solar or storage, it is
non-firm; therefore the Company focused on the timing associated with all
customer exports. For avoided transmission and distribution avoided
capacity projects, the methods throughout the Study used the measured
exported energy to estimate expected exports. Therefore, the Study
inherently included any storage systems connected to customer projects
used for exporting in the analysis.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 21
REQUEST FOR PRODUCTION NO. 38: The VODER study at 57 states "[t]he
study did not evaluate a locational based ECR value as this is not a feasible solution
within the Company's billing system", even though Order No. 35284 at 19 states "avoided
distribution costs are locational benefits properly studied" and that "[i]t is reasonable to
evaluate, for use, examples from the Lawrence Berkeley Nationa! Lab to better value this
element of the ECR.' Please explain in detail why this is not a feasible solution within the
Company's billing system. !n addition, please explain why the VODER study does not
consider examples from the Lawrence Berkeley National Lab.
RESPONSE TO REQUEST FOR PRODUCTION NO. 38: The Lawrence Berkeley
National Lab ("LBNL") report'Locational Value of Distributed Energy Resources" (Feb
2021) uses specific locational data needs to identify the value of customer generation
exports. The method used in the LBNL study identifies transmission and distribution
system capacity requirements using particular projects along with the expected customer
generation exports at those same locations and at the time of the capacity need. The
Company evaluated specific projects from 2007 through 2026 and the customer-
generator exports at those locations, resulting in a locational value for the transmission
and distribution capacity component of the ECR and thus acknowledged examples
provided by the LBNL.
The Company's current billing system uses the customer's service schedule to
determine the rate to apply to energy measured. The billing system would need the ability
to account for the unique location and service schedule to use a specific locational rate
in the export credit value. The current billing system does not have that capability.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 22
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.
IDAHO POVI'ER COMPANYS RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POV'JER COMPANY - 23
REQUEST FOR PRODUCTION NO. 39: lf a utility is in excess of energy and
chooses to sell exported solar generation into the market, please explain whether the on-
site generation customers should pay for line losses, which could potentially be a negative
adjustment in the ECR they receive.
ldaho Power is a net
energy importer, meaning the customer-generator exports reduce the amount of energy
the Company obtains from the market. Forthis reason, the Study only considered avoided
Iine losses, meaning all line losses were counted as a benefit for on-site generation
customers.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
TDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 24
REQUEST FOR PRODUCTION NO.40: Order No. 35284 at 20 states'[i]t is also
reasonable to study the difference between using static or marginal Iosses and the
magnitude of each as part of the valuation to be included in the ECR.' Please identify
where this analysis is located in the VODER study. lf this is not provided in the VODER
study, please provide it.
RESPONSE TO REQUEST FOR PRODUCTION NO. 40: ldaho Power used
average loss percentages in the Study, which were calculated based on the average
system hourly load and the slope between no-load losses, average load losses, and peak
Ioad losses. The losses excluded the transformer core losses and the distribution
secondary system Iosses. For more information on the Company's System Loss Study,
please see the attached 2012 System Loss Coefficient Study Report PDF.
The response to this Request is sponsored by Jared L. 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.25
REQUEST FOR PRODUCTION NO.41: Table 4.9 in the VODER study presents
the Company's 2012 System Loss Study results based on On-Peak, Mid-Peak, and Off-
Peak hours for summer and winter. Please explain whether the2012 System Loss Study
results should be converted to align with the timeframe of the Demand Response
Program (or other capacity-related peak timeframes) before being used for calculating
avoided line losses.
RESPONSE TO REQUEST FOR PRODUCTION NO. 41: The avoided Iosses are
a function of the transmission and distribution system loading, whereas the Study utilized
the DR portfolio days and hours. This timeframe aligns with the Company's highest risk
hours (which drive the acquisition of new resources); those two timeframes are not
necessarily the same. As such, the Study correctly does not convert the avoided losses
to the DR portfolio timeframe.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POI/VER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.26
REQUEST FOR PRODUCTION NO. 42: The VODER study at 59 discusses
transformer core losses, and states "[t]he 2012 System Loss Study determined the loss
percentages forthe transmission system, distribution system, distribution primary voltage,
and the distribution secondary voltage.'
a. Please define transformer core losses.
b. Please define distribution primary voltage and distribution secondary
voltage.
c. Please explain whether losses associated with distribution primary voltage
and losses associated with distribution secondary voltage are two types of
transformer core losses.
d. Please explain whether losses of the transmission system, distribution
system, dlstribution primary voltage, and the distribution secondary voltage
can all be avoided by customer-generator exports.
RESPONSE TO REQUEST FOR PRODUCTION NO. 42: Please see the following
responses regarding line losses:
a. Transformer core losses are the losses that occur from energizing the
laminated steel core in the transformer.
b. The Company's distribution primary voltages are'12.47 kilovolts ("kV'), 25
kV and 34.5 kV, while distribution secondary voltages are typically 240 volts
("V') and 480 V.
c. Losses associated with distribution primary voltage and distribution
secondary voltage are not two types of transformer core losses. The losses
associated with distribution primary voltage include the losses in all
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 27
distribution Iines and facilities at 12.47 kV, 25 kV, and 34.5 kV. The losses
associated with distribution secondary voltage includes the losses in
secondary voltage service lines (including line transformers).
d. Transformer core losses cannot be avoided by customer-generator exports
because they are independent of transformer loading. Also, the other losses
are related to current flow. Customer-generator exports can increase or
decrease those losses depending on the direction of the current flow on the
transmission system and the distribution primary and distribution secondary
Ievels.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 28
REQUEST FOR PRODUCTION NO. 43: The VODER study at 59 states that 2012
System Loss Study was done for both energy losses and for peak losses. Please define
both types of losses and explain whether the loss percentages listed in Table 4.8 and
Table 4.9 of the VODER study represent energy losses, peak losses, or both. lf they only
list one type, please provide the other type.
RESPONSE TO REQUEST FOR PRODUCTION NO. 43: Energy losses occur
over time; in the Company's 2012 System Loss Study, the loss coefficients were
calculated for the 2012 calendar year. The calculated Ioss coefficients inform the energy
loss calculations for the corresponding year. Peak tosses represent losses over an hour,
typically over a peak load hour. The peak losses for the 2012 System Loss Study were
calculated for July 12th from 4:00 pm to 5:00 pm MST. As mentioned in Response to
Request for Production No. 40, the Study calculated the losses for each hour based on
the average system hourly load and the slope between no-load losses, average load
losses, and peak load losses.
The response to this Request is sponsored by Jared L. 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 - 29
REQUEST FOR PRODUCTION NO.44: Please explain how the 5.80% annual
line loss percentage is determined in Figure 4.14 of the VODER study.
As described in Request
for Production No. 40, the Study calculated the hourly losses based on no-load losses,
average load losses, and peak load losses. The hourly losses were then averaged based
on the seasons, as shown in Tables 4.8 and 4.9 of the Study, to obtain the average
avoidable losses. The 5.80% represents the average losses for the Summer Mid-Peak
and the Summer Off-Peak seasons.
The annual line loss percentages were calculated by determining the avoidable
losses in the transmission and distribution systems. The avoidable losses in the
distribution system were calculated by using the total losses in the distribution primary
system obtained from the latest Ioss study and removing the core Iosses component. The
transmission loss coefficient factor remains unchanged from the latest loss study. The
Study considers the transmission losses and the distribution primary losses, with the
exception of the transformer core losses, to be the avoidable losses by customer
generation
The response to this Request is sponsored by Jared L. 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 - 30
REQUEST FOR PRODUCTION NO. 45: Please respond to the following
regarding Avoided Line Loss in Figure 4.18 of the VODER study.
a. Please explain what line loss percentages are used to calculate Off-Peak
Avoided Line Loss and how they are determined.
b. Please explain what line loss percentages are used to calculate On-Peak
Avoided Line Loss and how they are determined.
c. Please explain whetherthe line loss percentages are applied to the avoided
cost of energy (energy losses), the avoided cost of capacity (peak losses),
or both.
d. Please explain whether the line loss percentages are different when applied
to the avoided cost of energy (energy losses) and the avoided cost of
capacity (peak losses).
RESPONSE TO REQUEST FOR PRODUCTION NO. 45: Please see the following
responses regarding avoided line losses:
a. The line loss percentages used to calculate the avoided line Ioss in Figure
4.18 can be found in Table 4.9 of the VODER Study under the
corresponding seasonal and time parameters (Summer On-Peak and Off-
Peak). The Summer and Winter On-Peak, Mid-Peak, and Off-Peak line loss
percentages in Table 4.9 were obtained from the Company's latest System
Loss Study by taking the average of the hourly line loss percentages during
each identified season/time-period. The avoidable losses considered forthe
Study include the transmission losses and the distribution primary losses
with the exception of the transformer core losses.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 31
b. Please reference Response to Request for Production No. 45(a) for the
explanation regarding the determination and application of line loss
pe rcentages for d ifferent seasons/time-pe riod s.
c. The same line loss percentages are applied to both the energy and peak
Iosses. For the avoided capacity component of the ECR, the losses were
added to the customer energy exports by the corresponding loss factor for
each hour. The capacity calculation uses integers numbers, meaning the
margin of error is +/- 1 MW. Calculating losses separately could introduce
significant error due to its magnitude in comparison to the margin of error.
For the energy component, the losses were evaluated using the loss factor
for each season to obtain the corresponding energy for each hour, then the
energy was valued using the three methods described in the avoided
energy section of the Study.
d. Please reference Response to Request for Production No. 45(c) for the
explanation regarding the application of line loss percentages to the avoided
costs of energy and capacity.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO ]DAHO POWER COMPANY.32
REQUEST FOR PRODUCTION NO. 46: lf on-site generation of solar energy is
to be certified in Western Renewable Electricity Generation lnformation System
('WREGIS") by a customer, can all the generation be certified, or can only the exported
generation portion be certified? lf on-site generation of solar energy is to be certified in
WREGIS by ldaho Power on behalf of the customers, can all the generation be certified,
or can only the exported generation portion be certified?
RESPONSE TO REQUEST FOR PRODUCTION NO. 46: WREGIS has specific
and detailed requirements and protocols for approving the creation of Renewable Energy
Certificates ("RECs")-or WREGIS Certificates. Below, ldaho Power references relevant
portions of \NREGIS' operating rulesl in this response but notes that the rules are
extensive, and this response does not constitute a full record of WREGIS' rules or
approval processes.
As a point of clarification, WREGIS does not'certiff" generation but rather has a
process for approving Generating Units2 which, if approved, may earn WREGIS
Certificates for tracking within the WREGIS system.
Wth respect to on-site generation customers and the creation of WREGIS
Certificates, the Company directs Staff to the process by which an entity -that is, a
business or an individua! utility customer-becomes a WREGIS Account Holder and then
registers their Generating Unit.3 The entity must follow the instructions provided by
WREGIS and be approved by WREGIS.
1 WREGIS's Operating Rules, last published January 4,2021:
https://www.wecc.org/AdministrativeMREGlS%20Operating%20Rules%202021-Final.pdf
2 WREGIS defines a renewable Generating Unit as including any generation facility that is'defined as
renewable by any of the states or provinces in [the Western Energy Coordinating Council].'WREGIS
Operating Rules, p. 10.
3 WREGIS Operating Rules, Section 5.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 33
WREGIS also has requirements specific to "On-Site Load"-the category under
which Idaho Power's on-site generation customers would likely fall. An enti$ with On-Site
Load must meet requirements related to metering, communication, and verification of
dynamic data before WREGIS Certificates may be earned. According to WREGIS
Operating Rules 9.6.1:
"For On-Site Load to contribute to Certificates, the Generating Unit must
have sufficient metering in place to measure, either directly or through a
process of nefting, the On-Site Load. lf a netting process is used, it must
be designed to exclude Station Service. lf On-Site Load is metered
directly, the Generating Unit must have two separate meters, one to meter
the On-Site Load and one to meter generation that is supplied to the grid
and each meter must be registered separately with WREGIS. If On-Site
Load is measured through a netting process, both the meter measuring
generation supplied to the grid and the other meters involved in the netting
process may be registered separately with WREGIS. The method of
metering to be used and the netting process, if applicable, must be
reviewed and approved by \ /REGIS staff prior to the On-Site Load being
registered and reported in WREGIS." (p.35)
With respect to Staffs question about ldaho Power "certiffing" Generating Units
on behalf of its customers, the Company again notes that WREGIS does not certiff but
rather has a process for approving Generating Units which, if approved, may earn
WREGIS Certificates. The Company believes Staff may be asking whether an ldaho
Power customer with on-site generation could transfer the rights of their Generating Unit
to another party, such as ldaho Power. The answer is yes, and WREGIS Operating Rules
Section 5 addresses the requirements for transferring a Generating Unit from one
WREGIS account holder to another. The assignment of registration rights will give the
Generator Agent (an entity designated by the Generator Owner via a legal assignment to
act on the Generator Owneds behalf with WREGIS+.g., ldaho Power) full and sole
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 34
permissions and authority over the transactions and activities related to the Generating
Unit and any WREGIS Certificates.
ldaho Power is not aware of any WREGIS rules associated with transfer of rights
that would change how generation is calculated as explained above.
The response to this Request is sponsored by Mike Marshall, Regulatory
Compliance & Risk Manager, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTTON REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 35
REQUEST FOR PRODUCTION NO. 47: Order No. 35284 at 21 states that
"changes in costs for distribution circuits are appropriate to study." Please explain
whether the VODER study analyzes changes in costs for distribution circuits. lf not,
please explain why.
RESPONSE TO REQUEST FOR PRODUCTION NO. 47: The method used to
determine the transmission and distribution deferred capacity projects in the Study was
based on actual and proposed projects over 20 years, ranging from 2007 to 2026,
adjusted for inflation. By including projects over a 2o-year timeframe, varying costs
associated with distribution capacity projects are captured in the Study. No other changes
in distribution costs were included in the analysis.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 36
REQUEST FOR PRODUCTION NO. 48: The VODER study at 67 uses an
integration charge of $2.93 per Megawatt hour ('MWh"), determined in the Base 2023
Case of the 2020 VER lntegration Study, and states that "[tlhis integration rate could be
utilized until ldaho Power completes its next integration study and integration costs for
customer-generators could be evaluated directly." Please estimate the deviation of an
integration charge today from the $2.93 per MWh, given the differences between key
assumptions/inputs that should be used today and key assumptions/inputs used in the
2020 VER lntegration Study. Some examples forconsideration are shown in the following
table.
Today's Assumptions/Inputs 2020's Assumptions/Inputs
Latest forecast for 2023 load.2020 VER Integration Study at 10 states
"[t]o estimate2023loads, E3 used load
growth projections from Idaho Power to
uniformly increase 2019 loads by
approximately 5 percent total to 2,081
aMW."
Latest 2023 VER profiles determined.2020 VER Integration Study at l0 states
"the 2019 historical VER profiles were used
to derive the2023 VER profiles."
Updated new solar assumptions, if available.2020 VER Integration Study at I I states
"for the 2023 base case, it was reasonable to
assume thatZll MW of new solar was
online in their service territory (131 MW of
unspecified PURPA contracts and 120 MW
form the olanned Jackpot Solar faciliw)."
Updated wind assumptions for 2023,if
available.
2020 VER Integration Study at I I states
"ldaho Power also proposed that the2023
wind capacity remain the same as that from
2019."
Updated unit capacities, if available.2020 VER Integration Study at 13 lists unit
capacities in20l9 and2023 by generator
and resource tvoe.
IDAHO PO\A/ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 37
RESPONSE TO REQUEST FOR PRODUCTION NO. 48: The Company
recognizes that assumptions/inputs used in the 2020 VER lntegration Study would not
look identical if conducted today but also sees value in utilizing the most recently available
results. VER lntegration Studies are complex and, in the past, have been performed by
externally contracted companies; estimating the requested deviation without conducting
an entirely new study would produce erroneous results. As such, ldaho Power does not
have an estimate of how a newly performed study, based on updated assumptions, as
laid out by Staff, would impact the overall results. ldaho Power proposes updating
assumptions and inputs when the next VER Integration Study is performed.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY.3s
REQUEST FOR PRODUCTION NO. 49: The VODER study at O4 states "Figure
4.15 depicts customer exports compared to the Company's utility scale solar with both
outputs normalized based on their peaks for the first week of the four quarters of 2021."
a. How does Figure 4.15 reflect day-ahead and hour-ahead real time
uncertainty?
b. Please describe the normalization process based on the peaks of the first
week for the four quarters of 2021.
c. For "July 2021" in Figure 4.15, please explain why customer exports do not
align with utility scale solar as compared to January, April, and October of
2021?
d. Given "July 2021', please explain why the Company still believes "[t]his data
shows that the shapes are comparable and highly correlated" and "[t]hese
figures support utility scale solar as a good prory for customer-generator
exports for the purposes of studying integration costs." VODER study at
64.
RESPONSE TO REQUEST FOR PRODUCTION NO.49: Please see the following
responses regarding Figure 4.15:
a. Figure 4.15 of the Study is not intended to quantiff the day-ahead and hour-
ahead real-time uncertainty, but instead show that the normalized outputs
of the customer-generator exports and the Company's utility scale solar are
comparable and highly correlated. The day-ahead and hour-ahead real-
time uncertainty is generally evident in the variability of the output.
b. The normalization process was intended to be illustrative and was created
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 39
by dividing each hourly data set by its corresponding peak output for the
specified year.
c. Although utility scale solar and customer-generator exports are correlated
as stated in the Response to Request for Production No. 49(a), utility scale
solar projects typically use trackers of various rotational and locational
capabilities to maximize production while customer solar projects are often
fixed in place. Given that the summer season in the Mountain West has the
longest days out of any other time of the year, the benefits of having a
tracker system are more accentuated over the summer months in
comparison to the non-summer months. Additionally, customer exports are
also dependent on customer usage behind the meter, the figure reflects that
over the summer the customer load increases Ieading to a reduction in
customers' exports.
d. Utility scale solar is a good prory for customer-generator exports when
studying integration costs because these costs are incurred due to the
uncertainty and variability of the generation, not the level or magnitude of
generation.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Dlstribution & Resource Planning Director, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY .40
REQUEST FOR PRODUCTION NO. 50: The VODER study at 65 states
'[i]ntegration costs are also caused by uncertainty in the lS-minute and S-minute
timeframes. ldaho Power does not collect customer data on these timeframes; therefore,
it is challenging to directly compare customer exports and utility scale solar." Please
explain what the Company means by "ldaho Power does not collect customer data on
these timeframes," when customer meters can measure on real time intervals.
RESPONSE TO REQUEST FOR PRODUCTION NO. 50: The "real-time"
measurement interval does not indicate that the meter can measure sub-hourly intervals.
Advanced Metering lnfrastructure ('AMl") can separately measure (1) energy delivered
to the customer and (2) energy received/exported from the customer. The meter stores
data at an hourly intervalfor each of these channels. Section 3.2 of the Study describes
that Net Billing can utilize these separate channels for hourly or "real-time" measurement.
Under an hourly interval, the two channels are netted for each hour, and the customer is
billed for net hourly consumption or credited for exports during every hour of the billing
cycle. Under a "real-time" measurement, customers would be billed for energy consumed
from the grid and credited for a!!exports in each hour of the billing period.
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 41
REQUEST FOR PRODUCTION NO. 51: The VODER study at 71 states "the
energy input would be updated every other year along with or directly after receiving
acknowledgement of an IRP." VODER study at 72 states "[t]he levelized fixed cost of the
avoided resource is determined in ldaho Power's IRP. Therefore, it would be reasonable
to expect this input only to be updated every other year."
a. Please explain whether the energy input could be updated after an IRP is
filed.
b. Please confirm that the levelized fixed cost of the avoided resource could
be updated every other year along with or directly after an lRP is filed or
acknowledged.
RESPONSE TO REQUEST FOR PRODUCTION NO. 51: Please see the following
responses regarding the frequency of ECR updates:
a. Yes, the energy input, meaning the forecasted energy price, could be
updated after an IRP is filed.
b. Yes, the levelized fixed cost associated with the avoided cost resource
could be updated every other year following the filing or acknowledgement
of the lRP.
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power Company.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY -42
REQUEST FOR PRODUCTION NO. 52: The VODER study evaluates two
methods for calculating avoided cost of capacity: flat annual rates and seasonal time
variant rates. However, Chapter 5 Frequency of Export Credit Rate Updates only
discusses update frequency of the flat annual ECR.
a. Please explain how the Company plans to update seasonal time variant
avoided cost of capacity.
b. lf the update depends on the Demand Response Program, please explain
how frequently the Company plans to update the program.
c. Please explain whether the avoided cost of capacity can be calculated
based on the peak hours that the Company files with the Commission
annually on October 15.
d. lf so, please explain whether the update can occur annually in the October
15 filing.
RESPONSE TO REQUEST FOR PRODUCTION NO.52: Please see the following
responses regarding the methods for calculating an ECR:
a. The Study evaluates both flat annual and seasona! time-variant ECR and
the update methodology in Section 5. The capacity value calculation
considers (1) capacity contribution, (2) levelized fixed cost of the avoided
resource, and (3) annual exported energy from customer-generators. The
inputs to the capacity value calculation could be individually evaluated for
the frequency of updates depending on the most recent data and
methodologies that become available.
b. The avoided cost of capacity value considers the latest IRP avoided
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 43
generation costs and DR portfolio parameters to align with peak need hours.
A new IRP is published every other year.
c. Please reference Response to Request for Production No. 27(c) for the
explanation as to why the Study evaluates the use of the most-recently
adopted methodologies from the 2021 IRP to value capacity, focusing on
highest risk hours rather than the previously filed peak hours.
d. Please reference part c. of this Request for Production.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 44
REQUEST FOR PRODUCTION NO.53: lf the Company is going to do a fullCost
of Service study, please explain whether the Company is going to analyze how
compensations of ECR wil! affect the total system costs. In addition, please explain
whether the impacts could potentially affect all classes.
RESPONSE TO REQUEST FOR PRODUCTION NO. 53: ln a full cost-of-service
study, ECR compensation would be included in total system costs as a power supply
expense and would be allocated to all customer classes consistent with allocation of all
other power supply expenses.
The response to this Request is sponsored by Paul Goralski, Regulatory
Consultant, ldaho Power Company.
]DAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPAiIY -45
REQUEST FOR PRODUCTION NO. 54; The VODER study at 84 states "[i]n
development of CCOS inputs, Schedule 84 customers are not included in the customer
sample for Schedule 9, 19, ot 24." Please explain why Schedule 84 customers are not
included in the customer sample for Schedule 9, 19, or 24.
The information for cost-
of-service assignment for Schedules 95 and 24 uses a historic load research sample
design. The current samples for these classes do not include any customers with on-site
generation. As such, the allocation of cost-of-service inputs for Schedules 9S and 24 do
not include on-site generation customers. The Company has reviewed the sample design
and found that the relative precision sample statistic is within an acceptable tolerance
limit of above 90 percent. For reference, Schedule 95 customers with on-site generation
are less than 1 percent of all Schedule 95 customers and Schedule 24 customers with
on-site generation are 1 percent of all Schedule 24 customers. This fact, coupled with the
high relative precision of the sample, implies a strong statistical significance of these
samples as currently designed. Over time, these samples will continue to be evaluated
by the Company with this information as the customer rate groups potentially evolve.
For 9P and 19 classes, the Company primarily uses the total class population, not
sample design. !n the 2021 CCOS, there was a single non-legacy customer included in
the 9P class and that customer was included in the information for the total 9P
class. There was one legacy system customer in each the Schedule 19 and 9P class.
The population reads were used to extrapolate for the entirety of the respective rate
classes when applicable.
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 46
The response to this Request is sponsored by Jodan Prassinos, Load Research
and Forecasting Manager, ldaho Power Company.
IDAHO POVTER COMPAI.IY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSON STAFF TO IDAHO POVVER COMPATIY -47
REOUEST FOR PRODUCTION NO. 55: The VODER study at 94 states that
customer generation is a must-take resource similar to Public Utility Regulatory Policies
Act of 1978 ('PURPA") qualiffing facilities, so these costs should not be subject to the
95o/ol5o/o sharing mechanism. Please explain why all must-take resources should not be
subject to the sharing mechanism.
RESPONSE TO REQUEST FOR PRODUCTION NO. 55: The Energy Policy Act
of 2005 amended Section 111 of the Public Utility Regulatory Policies Act (PURPA") by
adding five new federal ratemaking standards for electric utilities. One of these standards
was a requirement to make available upon request net metering service to any electric
consumer that the electric utility serves. ln Order No. 30229, the Commission concluded
that the federa! net metering standard had already been adopted essentially making net
metering a must-take resouroe. Since the Power Cost Adjustment ('PCA') was
established in 1983, the Commission has allowed the Company "100o/o recovery of a
resource that it is forced to acquire under federal law.' (Order No. 24806 at 17.) The
VODER study contemplates valuing on-site customer generation net exports at avoided
cost. lf the Commission were to authorize compensating on-site customer generation
exports at avoided cost, it would be inappropriate to consider a sharing mechanism
because ldaho Power has no ability to influence or reduce these payments. ln all other
instances where the Company makes payments to customers at predetermined avoided
cost, such as demand response and PURPA, those payments are recovered at 100
percent.
The response to this Request is sponsored by Tami White, Budget and Revenue
Manager, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 48
DATED at Boise, ldaho, this 9th day of September2022
Tiuilul-00ftn
Megan Goicoechea Allen
Attorney for ldaho Power Company
IDAHO POr/\,ER COMPAiIY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPAI.IY.49
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 9th day of September 2022,1 served a true and
correct copy of ldaho Power Company's Response to 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:
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 50
Gommission Staff
Riley Newton
Chris Burdin
Deputy Attorney General
!daho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8
Suite 201-A (83714)
PO Box 83720
Boise, lD 83720-0074
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[e-mail]
ldaHydro
C. Tom Arkoosh
Amber Dresslar
ARKOOSH LAW OFFICES
913 W. River Street, Suite 450
P.O. Box 2900
Boise, ldaho 83701
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_U.S. Mail
_Overnight Mail
_FAX_FTP SiteX Email [e-mail]
Amber.d [e-mail]
erin. ceci!@a rkoosh.com
ldaho Conseryation League
Marie Kellner
ldaho Conservation League
710 North 6th Street
Boise, ldaho 83702
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_U.S. Mail
_Overnight Mail
_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
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Lance Kaufman, Ph.D
4801 W. Yale Ave.
Denver, CO 80219
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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
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[e-mail]
Wil Gehl
Energy Program Manager
Boise City Dept. of Public Works
150 N. Capitol Blvd.
PO Box 500
Boise, ldaho 83701-0500
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lndustrial Customers of ldaho Power
Peter J. Richardson
RICHARDSON ADAMS, PLLC
515 North 27th Street (83702)
P.O. Box 7218
Boise, ldaho 83707
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Dr. Don Reading
6070 Hill Road
Boise, Idaho 83703
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_U.S. Mail
_Overnight Mail
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FTP Site
X 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
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U.S. Mail
Overnight Mai!
_ FAX
_FTP SiteX Email [e-mail]
[e-mail]
awiensen@h olland ha rt.com
Jim Swier
Micron Technology, lnc.
8000 South FederalWay
Boise, ldaho 83707
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U.S. Mail
Overnight Mai!
_ FAX
_ FTP Site
_,L Email [e-mail]
aclee@holland hart.com
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 51
Glean Energy Opportunities for ldaho
Kelsey Jae
Law for Conscious Leadership
920 N. Clover Dr.
Boise, ldaho 83703
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U.S. Mail
Overnight Mail
_ FAX
_ FTP SiteX Email [e-mail]
Michael Heckler
Courtney White
Clean Energy Opportunities for ldaho
3778 Plantation River Dr., Suite 102
Boise, lD 83703
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_U.S. Mail
_Overnight Mail
_FAX_FTP Site
X Email
cou rtnev@cleanenerovopportu n ities. com
mike@cleanenerovooportu n ities. com
Richard E. Kluckhohn, pro se
Wesley A. Kluckhohn, pro se
2564W. Parkstone Dr.
Meridian, lD 83646
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U.S. Mail
Overnight Mail_ FAX
FTP SiteX Email [e-mail]
[e-mail]
ldaho Solar Owners Network
Joshua Hill
1625 S. Latah
Boise, lD 83705
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U.S. Mail
Overnight Mail
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[e-mail]
ABG Power Company, LLC
Ryan Bushland
184 W. Chrisfield Dr.
Meridian, ]D 83646
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U.S. Mail
Overnight Mail
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FTP Site
-[ Email rvan.bush][e-mail]
[e-mail]
&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 - 52
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC.E.22.22
IDAHO POWER COMPANY
REQUEST NO.26
ATTACHMENT NO. 1
SEE ATTACH ED SPREADSHEET
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPG.E-22.22
IDAHO POWER COMPANY
REQUEST NO.27
ATTACHMENT NO. 1
1
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-22-22
IDAHO POWER COMPANY
REQUEST NO.27
ATTACHMENT NO.2
SEE ATTACHED SPREADSHEET
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-22-22
IDAHO POWER COMPANY
REQUEST NO.27
ATTACHMENT NO.3
SEE ATTACH ED SPREADSHEET
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-22-22
IDAHO POWER COMPANY
REQUEST NO.27
ATTACHMENT NO.4
SEE ATTACHED SPREADSHEET
BEFORE THE
IDAHO PUBLIC UTILITIES GOMMISSION
GASE NO. IPC-E-22-22
IDAHO POWER COMPANY
REQUEST NO.27
ATTACHMENT NO. 5
SEE ATTACH ED SPREADSH EET
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. !PC-E-22-22
IDAHO POWER COMPANY
REQUEST NO.40
ATTACHMENT NO. 1
Development of TOLZ System Loss Coefficients
Prepared by:
Trevor Schultz
Bryan Hobson
Transmission Policy & Development
sl2l2ot4
Table of Contents
lntroduction
Transmission Level
Distribution Levels
E nergy Loss Coefficient Ca lcu |ations..............
Transmission Level Energy Losses.........
Distribution Substation Level Energy 1osses..........
4
System LevelDescriptions........... .........4
4
5
6
6
7
8Distribution Level Energy Losses
Distribution Line Transformer Losses 10
Primary/Secondary Distribution Losses Sp1it............ ..............12
2012 Energy Loss Coefficients Diagram ..............14
Peak Demand Loss Coefficients Calculations ..........15
Transmission 1eve1........ .................. 15
Distribution Stations Level 16
Distribution Primary System Level 16
2OLZPeak Loss Coefficients Diagram .................L7
Delivery Point Loss Coefficients 18
Appendix A: 20L2 Energy Losses Data Sources.................. ............19
Appendix B; 2OL2 Peak Losses Data Sources 2L
Appendix C: Loss Coefficients Not lncluding GSU 1osses.................. .................23
Appendix D: Reconciliation with FERC Form 1..24
Executive Summary
This loss study determines the peak and energy loss coefficients for the ldaho Power delivery system for
the calendar year 20L2. The delivery system was broken down into four system levels including:
1. Transmission: All voltage levels from 45 kV to 500 kV, includes transmission voltage tie
transformer banks and iterations with/without generator step up transformers
2. Distribution Stations: lncludes distribution station transformers
3. Distribution Primary: All distribution lines and facilities at12.47 kV, 25 kV and 34.5 kV
4. Distribution Secondary: lncludes distribution line transformers
The losses documented in this study represent the actual, physical losses that occurred on ldaho Power
delivery system facilities. Application of the calculated loss coefficients is limited to loads served from
ldaho Power Company facilities. The peak loss coefficients are calculated based on data from the
system peak hour in 2Ot2 which occurred on July 12 from 4 pm to 5 pm.
This study employs a slightly different approach to calculating losses than previous studies. Previous
studies calculated losses as the difference between system level 'butputs" and system level "inputs".
While the principle of losses = inputs - outputs still applies, this study uses hourly load data from AMl,
MV90 and Pi to directly calculate the losses at each individual system level. Transmission line losses are
calculated directly based on the resistance of the line. Totaltransformer losses, including generator
step-ups, tie banks, distribution substation transformers and distribution line transformers are found by
calculating and summing the core and the winding losses. The distribution system losses, primary plus
secondary, were found as the difference between the distribution system inputs (output of the
substation layer) and the distribution system outputs as defined by the AMl, MV90 and Pi data.
The individual system level loss coefficients are the system level inputs divided by the system level
outputs, including wheeling. The loss coefficients used at each delivery point in the system (at the four
system levels above) are calculated as the product of the individual level loss coefficients. These final
loss coefficients for the energy losses and peak losses for calendar year of 2OL2 are shown in Table 1.
System Level Energy Loss Coefficient Peak Loss Coefficient
Transmission 1.034 1.036
Distribution Stations 1.040 L.O42
Distribution Primary 1.061 1.070
Distribution Secondary 1.095 1.097
Table 1: 2012 Delivery Point Loss Coefficients, wheeling included
Introduction
Loss coefficients are the ratio of the system input required to provide a given output at a particular
system "level" in the power system. For example, the energy input to the system required to serve
residential sales equals the sales multiplied by the distribution secondary system energy loss coefficient.
Similar calculations can be made for peak demand using the peak loss coefficients. Both peak demand
and energy loss coefficients are calculated for each system level.
lndividual level loss coefficients relate the input and the output of each individualsystem level by
Equation 1.
Equation 1 Individual Level Coefficient =Levellnput
L€velOutput
i , Legellosses=- Le?eloutput
The system loss coefficient is obtained by muhiplying all of the "upstream" system levelcoefficients
together. For example, the total distribution secondary system loss coefficient is found by the following
equation:
D istributton S e condary Sy stem Lo s s C oe f f icient
= Transrdssion Level Coefficient
* Distribution Station Level Coef f tctent
* Dtstribution Primary Level Coef f icient
* Distrtbutton S e condary Level C oe f f icient
For 2OL2, the tota! Distribution Secondary system energy loss coefficient is 1.095.
1.0341* 1.0054 * 1.0210 * 1.0330 = 1.096
The 2OL2, the tota! Distribution Secondary system peak loss coefficient is 1.097.
1.0359 * 1.0063 * L.0268* 1.0251 = 1,097
System Level Descriptions
The ldaho Power Company power system was split into four categories for the purposes of this loss
study: Transmission, Distribution Stations, Distribution Primary and Distribution Secondary. The
system inputs and outputs for each level are described below. The sources of information for each of
the individual level inputs and outputs are shown in Appendix A.
Transmission Level
The transmission level includes losses for all facilities and lines from 46 kV up through 500 kV. Losses
from the generation step-up transformers (GSU) and transmission tie-bank transformers are calculated
and included in the transmission level. Customer owned facilities are not included. The loss factors
used for FERC rate calculations assume that the generator step-up (GSU) losses are included as part of
the generation output and therefore are not included in the transmission system level losses. The
adjusted loss factors not including the GSU losses are shown in Appendix C.
The inputs to the transmission system level include IPC generation, power purchases and exchanges
from other companies, customer owned generation connected directly to the transmission system, and
wheeling transactions. The transmission level outputs include high vohage sales to customers and other
utilities, power exchanged to other utilities, wheeling transactions, and output to the distribution station
level. The Exchanges Out are adjusted to remove the scheduled losses for the ldaho Power share of
losses in the jointly owned Bridger-ldaho and Valmy-Midpoint transmission systems. FERC Form 1
includes the Bridger and Valmy scheduled losses as exchanges out. The calculated losses in this study
include the ldaho Power share of losses on the Bridger and Valmy systems as transmission level losses.
The Bridger and Valmy scheduled losses are added to the total FERC Form 1 losses to reconcile the
calculated losses with the FERC Form 1 losses. (See Appendix D, Reconciling with FERC Form 1). The
ldaho Power share of Boardman-ldaho transmission system losses are only accounted for financially.
The scheduled output loss transactions by IPC to other utilities for losses caused by wheeling IPC energy
through other systems are included as system outputs used to calculate transmission losses.
The treatment of loss transactions in the computing of the transmission level loss coefficients is to: (1)
lnclude in ldaho Powe/s transmission level losses, energy delivered to ldaho Power for loss
compensation due to wheeling other system's transactions on the ldaho Power system. (2) lnclude in
ldaho Powe/s transmission level losses, tdaho Powe/s share of losses in the jointly owned Bridger-
ldaho and Midpoint-Valmy transmission systems. (3) Exclude from ldaho Powe/s transmission level
losses, energy scheduled out for losses on other systems due to ldaho Powe/s wheeling on other
systems.
Distribution Levels
The distribution station level includes all ldaho Power owned distribution substations, including ldaho
Power owned distribution substation transformer losses. Customer owned facilities are not included.
The input to the distribution station level is the net output of the transmission level. The outputs of the
distribution station level are the direct sales from substations (both industriaUcommercial and
irrigation), wheeling transactions with substation level delivery points, and output to the primary
distribution level.
The distribution primary level includes all primary voltage lines and equipment at voltages of L2.5 kV, 25
kV and 34.5 kV. Customer owned facilities are not included. lnputs to this level include the net output
of the distribution station level and the customer owned (PURPA) generation connected to the primary
distribution system. Outputs from the distribution primary system include direct primary metered sales
to IPC customers, wheeling transactions with distribution primary delivery points, and the output to the
distribution secondary level.
The distribution secondary level consists of all ldaho Power owned secondary voltage lines and
equipment including the distribution line service transformers. Customer owned facilities are not
included. lnputs to this level include the output from the distribution primary level and the net-
metering and Oregon Solar customers. Outputs include the retail distribution sales (secondary
customers), wheeling transactions with distribution secondary delivery points, and ldaho Power
Company internal uses (not including substation local service use).
Energy Loss Coeffi cient Calculations
Figure 1 shows the total system flow diagram for the 2012 energy losses. This figure outlines each
system level's input and output, the total energy losses (MWh) and loss coefficient. The transmission
level output (MWh) to the distribution station level is calculated by subtracting the remaining outputs
and calculated losses from the transmission level inputs.
Transmission Level Energy Losses
The transmission level losses (in MWh) were calculated by first collecting hourly Ioad data from the Pi
database for the entire 2012 calendar year. Then the l2R losses were calculated for each ldaho Power-
owned transmission line section using Equation 2.
Equation z Losses(Mwh) = X Hourly-usage2.#
Where Rp.u.sn" is the total p.u. resistance of the transmission line section on 100 MVA base
And "Hourly_Usage" is the average hourly usate on the transmission line section in MWh
The transmission line energy losses in MWh were calculated by voltage at all the voltage levels from 45
kV up to 345 kV (see Table 2). Where transmission voltage data was available in Pi (138 kV and higher),
the line losses were scaled by the average hourly vohage to more accurately calculate the losses. Where
voltage data is not available in Pi, 1.0 p.u. voltage is assumed.
Voltage
Tot Losses
MWh
345 kV 2L5,275.7
230 kv 26L,673.9
138 kV 117,581.5
59 kV 37,888.5
46 kV L8,21O.2
Total Lines Losses 650,629.8
Table 2: Transmission Line Losses by Voltage
The energy Iosses for the generator step-up transformers (GSU) and transmission tie-banks are
calculated by summing the winding (copper) losses and the core losses for each transformer unit. The
winding (copper) losses are calculated by collecting hourly load data and per unit resistance (100 MVA
base) on each transformerthen using Equation 2 above.
The core losses for each transformer are obtained from ldaho Power Apparatus department "no-load
losses" records. lt is assumed the transformers are energized for every hour of the year so the total core
losses for each transformer unit are calculated with Equation 3.
Equation 3 Corelosses (MWh) = NLL- fi#
Where NLL is the "no-load losses" in kW for each transformer
And 8784 is the number of hours in 20L2 (leap year)
The GSU and transmission tie-bank energy losses for 2012 were found to be:
76,L54.L MWh Core Losses + 45,703.0 MWh Copper Losses = 12L,857.7. MWh Total Losses
Totaltransmission level losses are shown in Table 3.
Tot Losses
MWh
Total T-Lines 550,629.8
GSUs & Tie-banks t2L,857.1
Total Transmission 772,486.9
Table 3: Total Transmission Level Losses
Distribution Substation Level Energy Losses
Distribution substation losses are found by calculating the total losses in the substation transformers for
the calendar year 2OL2. Losses in other substation apparatus, equipment and bus are assumed
negligible. The total losses in the substation transformers are the sum of the core losses and the
winding (copper) losses.
The core losses are calculated using Equation 3. The no-load losses (in kW) were obtained from the IPC
Apparatus group. The winding (copper) losses are proportionalto the total energy delivered through
the transformer. Hourly average load data (MWh) was obtained for each transformer. Most of the
substation transformer load data was obtained from Pi. For the transformers not in the Pi database,
one of three methods was used to obtain or estimate hourly transformer data:
1) MV90 system data if available, otheruvise
2l Sum of the Pi data on the feeders served by the transformer if available, othenivise
3) Estimated losses based on transformer kVA rating and average load profile
96% of all the distribution substation losses were calculated from Pi data. 3% of the data came from
MV90 and 2% of the total losses were estimated.
Distribution Substation Core Losses 38,950 MWh
Distribution Substation Copper (Winding) Losses 37,090 MWh
Distribution Substation Total Losses 75,040 MWh
Table 4: Distribution Station Losses 2012
Distribution Level Energy Losses
The system wide implementation of Automated Metering lnfrastructure (AMl) has provided a much
more granular data set of customer loads than was ever available before. ln 20L2, approximately 99016
of ldaho Power customers were metered with AMI meters. To calculate distribution system inputs,
outputs, and losses, this study gathered and made use of hourly customer metered data that is available
from the AMI system, the MV90 metering system, and Pi. For information about how each type of data
source was handled, including care taken to ensure the correct sign for net-metering and cogen data,
see the document titled "Notes About Data.doofl.
The total distribution level losses (distribution primary plus distribution secondary losses) were
calculated in a multi-step process whereby a loss percentage was calculated based on distribution level
inputs minus distribution level outputs for a large subset of distribution data screened for data integrity,
then this loss percentage was applied to the total distribution leve! input (the output of the substation
level). Here is a description of the steps in the total distribution system loss calculation:
1) Hourly energy data was obtained for distribution level inputs for the subset of substation
distribution transformers with AMI installed. The distribution level input hourly data came from
one of two sources:
a. MV90 database if available, othenlrrise
b. Pi database
2l Hourly energy data was obtained for distribution level outputs (primary and secondary) for the
subset of customers connected to distribution systems fed by station distribution transformers
with AMI installed. The distribution level hourly output data came from several sources:
a. AMI meter data; includes the vast majority of energy consumption
b. MV90 BPA meter data; includes all BPA customers served by IPC distribution system
c. MV90 Large Customer meter data; large customers metered via the MV90 system
d. AMI Net meter data; All net-metering customers net load
e. MV90 Oregon Solar meter data; the'net" energy meter data was tabulated
f. Co-generation meter data; All customer owned generators connected to the
distribution system (generation was considered a negative output for computation
purposes). Data came from the MV90 database if available, othenrrise from the Pi
database if available, othenrise hourly data was estimated based on monthly billing
from the Energy Contracts group.
3) The output data for each customer was mapped to a substation based on one of two methods:
a. For AMI meters, the mapping was assigned according to AMI meter self-reported
locations based on a snapshot from May L3,2Ot3.
b. For non-AMl meters, the mapping was assigned based on the substation which normally
sources the feeder to which it is connected.
4l Total input and total output data were tabulated by substation.
5) The hourly input data from the Pi database was screened for "gaps" between consecutively
logged data points of 3 hours or more. (tt was assumed the hourly output data integrity was
adequate since most data came from the AMI or MV90 databases. The AMI database logs
hourly interval data, and any missing data is replaced by an estimation algorithm that replaces
the missing intervals with estimated data based on valid register reads on the boundaries of the
missing interval data. The MV90 system logs 15-minute interval data and generally does not
have missing data).
6) The input and output data for hours where "gaps" were detected in the input data for a
particular substation were excluded from the input and output totals for that substation.
7l lnput data was further screened to check for situations where load transfers caused the input
data to flatline at 0, which generally results in intervals of greater than 3 hrs between logged
data points in Pi, thereby resulting in exclusion of the inputs and outputs for that substation for
the duration of the load transfer. ln this situation, if load was transferred between different
stations, this caused the exclusion of output data for meters connected to the offloaded
transformer or feeder, but inclusion of the input energy feeding those meters which shows up in
the input data for the substation to which the load was transferred. ln cases where valid
flatlined data was identified for load transfers between stations, the input and output data for
those hours were included in the totals for the offloaded substation. Development of a dynamic
substation-to-meter map would prevent this problem in future loss studies.
8) Screened losses for each AMI substation were calculated based on the screened input and
output data by subtracting the sum of the output data from the sum of the input data for valid
hours.
9) A loss percentage was calculated based on the total screened losses for all substations divided
by the total screened input for all substations.
10) This loss percentage was applied to the total distribution level input (the output from the
substation level) to determine total distribution level losses and individual loss percentages for
distribution primary, distribution transformers, and distribution secondary (see below for
calculation of these values).
11) At this point, a slightly iterative process was used to factor in the losses of the non-AMl
substations.
12) Distribution level inputs and outputs for each non-AMl substation were tabulated in terms of
annualkWh.
13) The non-AMl substation distribution input data came from one of the following sources:
a. MV90 database if available, otherwise,
b. Pi database if available, othenrise,
c. Estimated data based on substation distribution transformer rating and average load
profile 16% of input energy for non-AMl stations came from this source)
14) The non-AMl substation distribution output data was directly measured via MV90 where
available or estimated based on the average loss percentages calculated for distribution
primary, distribution transformers, and distribution secondary up to this point. Only the
percentages for the portion of distribution system fed by each non-AMl station were used. For
example, if a particular non-AMl substation fed one or more large industrial customers for which
ldaho Power owns the primary facilities and service transformers, only the average distribution
primary and distribution line transformer loss percentages would be applied to this substation
to determine the losses (the distribution secondary loss percentage would not be applied).
15) Once the non-AMl stations inputs and outputs were calculated, these numbers were added to
the AMI substation inputs and outputs from step 9. ldaho Power internal use and non-metered
energy (e.g. street lighting) were also added as outputs. Adding the non-AMl substation input
and non-AMl substation output, lPCo internal use output, and non-metered energy output
resulted in a slightly different average loss percentages as originally calculated in steps 9 and 10.
This creates new average loss percentages to apply in step 14 to the non-AMl substations. This
iterative process was repeated untilthe average loss percentages settled out.
After the final iteration, the following numbers were calculated:
Total Distribution Energy lnput
Total Distribution Energy Output
Total Distribution Energy Losses
= L2,9O6,659 MWh
= L2,282,015 MWh
= 624,644 MWh
Distribution Line Transformer Losses
The distribution line transformer energy losses are also calculated as part of the total distribution
system energly losses. As with other transformer loss calculations, both the core losses and the winding
(copper) losses are calculated. Distribution line transformer data was extracted from the GIS database
including number of transformers, kVA rating, and feeder. Typical manufacturertest data including no-
load losses and full-load losses by kVA size was obtained from lPCs Methods and Materials troup.
Distribution Line Transformers AsotLZlStl2Ol2
f Transformers 2t7,688
Total Nameplate kVA LL,973,575
Table 5: Distribution Line Transformers (from GIS)
The distribution line transformer core losses of each individual transformer were calculated directly by
transformer kVA size and summed by feeder.
Equation 4 TransformerGoreloss(MWh) = NLL * 8784 hrs/1000
Where NLL = No-load loss in kW from transformer manufacturer test data
The winding losses or copper losses are dependent on the load through the transformer. The feeder
and kVA rating of each individual distribution line transformer on the system as of L213L12012 was
collected from the GIS system. Also, the manufacturer rated full-load losses (FLL) were collected from
the IPC Methods and Materials group by transformer kVA rating. Two sets of FLL data were provided;
one from 2005-2006 data and one set of test data from 2013. The 2013 vintage transformers were
found to be less "lossy'' than the 2005-2005 vintage by about 23%. Since the vast majority of existing
line transformers were installed prior to 2013, the 2005-2006 data was used in the winding losses
calculations as the best approximation of the diverse set of line transformers installed on the
distribution system. For individual transformers that were not included in the manufacturer test data
(by kVA rating), a linear approximation was used to estimate the FLL for that kVA rating size.
The winding losses for all the line transformers installed on each distribution feeder were then
calculated based on the load profile of each distribution feeder and applying a loss factor method
developed by Kip Sikes in previous losses studies. First, the total full-load losses (from manufacturer
test data) of allthe individual line transformers on each feeder were summed by feeder in kW. Then,
the hourly load profile for each distribution feeder was used to calculate feeder peak load and average
load in MW for 2Ot2. A loss factor for each feeder was then calculated based on the loss factor
equation developed by Kip Sikes:
Equation 5 Loss Factor = OpFact.l[Gl(oPFectorlz + C2lopractor) + Ct]
Where: OpFactor = Average Feeder Load / Connected kVA on feeder
CL, C2, C3 are coefficients determined based on 2012 system loading data
For 20L2, the coefficients are:
C1 = -1.0551 C2 = 1.350 C3 = L.574
Resulting in the final loss factor equation as Equation 6
Equation 6 Loss Factor = OpFactor[-1-0561(OnFector)2 + L36(OpFactor) + 1.57+]
A loss factor is then calculated for every feeder. The total distribution line transformer winding losses
are then calculated by feeder with Equation 7.
Equation 7
Where:
Wlndlngl.osses = (RatedFllreeder) * LossFactor * 8784 hrs/1000
Windinglosses are in MWh
RatedFLLs""6", (in kW) = sum of all line transformers Full-load Losses (FLL) on feeder
The total of allthe distribution line transformer energy losses in 2OL2 are:
Core Energy Losses = 173,365 MWh
Winding Energy Losses = 38,095 MWh
Total Energy Losses = 211,452 MWh
For feeders that do not have load data either in Pi or the MV90 system, the total core losses for all the
line transformers were calculated and included in the totaltransformer losses, but the winding losses
were ignored. The total connected kVA on the feeders that do not have hourly load data is only about
0.8% of the total connected line transformer kVA (103,101 connected kVA out of L1,973,575 total
connected kVA).
A potential improvement in calculating the total distribution losses is to directly calculate the winding
losses in each individual line transformer. Prior to AMl, this was impossible, but with the AMt data and
the customer-to-transformer (C2T)tie in the GIS system, it is possible by summing the hourly customer
load by line transformer. This could replace the loss factor method used in this study in a future loss
study.
Primary/Secondary Distribution Losses Split
To be able to calculate and apply loss coefficients to both primary metered and secondary metered
customers, the distribution system level must be split into to classifications: Primary Distribution and
Secondary Distribution. Because ldaho Power does not currently keep records on the service
conductors to customers (i.e. size of conductor, length of service), we are not able to directly calculate
the secondary distribution losses separate from the primary distribution losses. One option is to build
"typical" models to simulate the primary and secondary losses and extrapolate the model results to all
500,000+ customers. This method may or may not provide additiona! information and is left to be
investigated in a future possible future version of the loss study.
The total distribution system energy losses were split into primary and secondary losses in this study by
using a ratio of distribution primary and secondary line miles. Two sources of the line mileage data were
considered: the company's GIS system and the company's property tax statements. The tax statements
were used as the fina! source of line mileage data because they included totals by voltage for both
primary and secondary wire miles see Table 6 and Table 7.
All Wire Mileage (TN(6511
(lncludes Secondary mileage)
Lzl3tl20r2
12.s kv 47,652.7
25 kV 1,4L5.4
34.s kv L6,428.9
Total 65,497.L
Distribution Feeder Mileage Summary FA)(672)
AsotL2l?tll2
(Does not include Secondary mileage)
Line Miles Wire Miles
1 phase
2 phase
3 phase
Total
Lt,783.6
984.6
10,148.0
22,9L6.2
11,783.6
t,969.2
30,444.L
4,L96.8 67.s%Table 6: Total Dist Wire Mileage
Table 7: Primary Distribution Wire Miles
Total Secondary Wire miles = 65,497.L-44,L96.8 = 21,3fl).3 miles
Split of distribution system line losses based on wire miles is Table 8.
Miles %
Primary Distribution Wire Miles M,L96.8 67.5%
Secondary Distribution Wire Miles 21,300.3 32,SOA
Table 8: Distribution Wire Miles as of l2l31.l20L4
The distribution line transformer losses are included in the Distribution Secondary system level. Then,
based on the distribution wire mileage data, the total distrlbution system level energy losses are in Table
9.
MWh
Prtmary Dtsffibudon Llne l.osses 278,871
Distribution Line Txfrmr Losses atl,,462
Secondary Distribution Losses t34,37t
Total Seanrdary Dlstrlfuitton Losses lrttli,833
Total Distribution Losses 624,W
Table 9: Distribution Level Energy Losses
2Ol2 Energy Loss Coefficients Diagram
ldaho Power Company
2012 Energy Loss Coefficients Diagram - lncluding Wheeling
Values in MWh
Power Supply
Utility Purchases
PURPA,/Cust Gen
Exchange ln
Wheeling In
13,859,001
L,71L,463
1,398,995
392,3L3
6,074,L32
328,060 Retail Transmission Sales
2,L83,262 High Voltage Sales
152,381 Exchange Out (excluding Bridger
and Valmy loss transactions)
5,864,395 Wheeling Out
L4,125,3t9 To Distribution Stations
851,865 Direct Station Sales
85,375 lrrigation Sales
92,!51Wheeling Out
13,019,887 To Distribution Primary
PURPA 565,879
Net Met/Ore Solar L,L25
t0,837,4LG To Distribution Secondary
2,468,64L Direct Primary Sales
898 Wheeling Out
L0,302,329 Distribution Sales
22,8L8 lPCo lnternal Use
49,885 Street Lighting / Unbilled
tL7,576 Wheeling Out
Transmission Svstem
lnput =
Losses =
Output =
23,425,9U
772,487
22,653,417
Loss Coefficient =1.0341
Distribution Stations
lnput =
Losses =
OutPut =
t4,L25,3t9
76,U0
L4,0/;9,279
Loss Coefficient =1.0054
Distribution Primary
lnput =
Losses =
Output =
13,585,755
278,8t!
13,306,955
Loss Coefficient =1.021C
Distribution Secon
10,838,541
345,833
Put =
708
Coefficient =
Figure L: 2OL2 Energy Loss Coefficient FIow Diagram
Peak Demand Loss Coefficients Calculations
A load-flow case simulating the conditions on the system peak hour in 2OL2 was used in the peak losses
calculation. The peak hour for 2012 was 7 /L2trom 4 pm to 5 pm. The peak system demand was 3245
MW. The peak demand loss calculations are intended to calculate and represent the physical losses on
the ldaho Power Company owned facilities at peak demand.
As with the energy losses calculations, the ldaho Power system was split into four system levels:
1. Transmission: All voltage levels from 46 kV to 500 kV, includes transmission voltage tie
transformer banks and iterations with/without generator step up transformers
2. Distribution Stations: lncludes distribution station transformers
3. Distribution Primary: All distribution Iines and facilities at L2.47 kV, 25 kV and 34.5 kV
4. Distribution Secondary: lncludes distribution line transformers
The representation of the four system levels including input and outputs, calculated losses (MW) and
individual level loss coefficients are shown in the diagram in Figure 2. The source of the data used for
the peak loss calculations are in Appendix B.
Transmission Level
Transmission level inputs and outputs were gathered for the peak hour. The transmission level IPC
power supply generation was obtained from the Pi archives and totaled 2,533.6 MW, as shown in Table
10.
2012 Peak Hour IPC Generation
Hvdro 1,168.9 MW
Coal 940.4 MW
Gas Thermal 424.4MW
Total 2,533.6 MW
Table 10: 2Ol2lPC Peak Hour Generation
Other transmission inputs include utility purchases, customer generation / PURPA, exchanges in, and
wheeling transactions in. The utility purchases, exchanges, and wheeling transactions were provided by
ldaho Power Operations for the peak hour. The customer generation was obtained from Pl and includes
all customer owned generation that connects directly to the IPC transmission system (customer owned
substation transformer). The transmission level outputs include high voltage sales for resale, retail
transmission sales, exchanges out, wheeling transactions out, and the output to the Distribution
Substation level. The retail transmission sales data came from MV90 data and Pi data for transmission
level customers. The high voltage sales for resale, exchanges out, and wheeling transactions out came
from the system operation data forthe peak hour.
The transmission level losses are calculated directly from the power flow model built to simulate the
2012 system peak load, 7lLzll2 4-5 pm. The losses in the transmission lines and tie bank and generator
step-up (GSU) transformers totaled L67.L MW and are shown by voltage in Table 11.
Line kV Line Losses
(Mw1
Transformer
Losses (MW)
Total
(Mwl
345 kV 26.72 2.O3 28.75
230 kv 75.62 5.74 81.35
161 kV 3.28 .29 3.57
138 kV 29.93 3.L7 33.1
115 kV 01 0 .01
69 kV 9.s3 .11 9.64
46 kV 10.48 .17 10.55
Total 155.57 11.53 L67.10
Table 11: Transmission Level Losses by Voltage
Distribution Stations Level
The distribution substation transformer losses are the sum of the transformer core losses and the
winding (copper) losses. The core losses (in kW) are obtained from manufacturer test data supplied by
the Substation Apparatus group.
The winding losses are calculated directly based on the demand (MW) on the transformer and the per
unit resistance of the transformer. The per unit resistance of each transformer was supplied from the
Substation Apparatus group and from Planning files. The MW demand on each distribution substation
transformer during the peak system load hour (71L2/LZ 4-5 pm) was found from Pi data, AMI and MV90
data. Peak Winding losses in MW were calculated for each transformer with Equation 8.
Equation 8 PeakWndtnglosses(Mltl) = PeakHrDemand2 * !,ffi
The distribution substation peak losses are totaled in Table 12.
Core Losses 4.421MW
Windine Losses 14.218 MW
Total Distribution Substation Losses 18.639 MW
Table 12: Distribution Substation Transformer Losses
The input to the distribution station level equals the output of the transmission system level. The direct
station sales are included as outputs to the distribution stations system level. The direct station sales
are customers that get their service directly from an ldaho Power owned substation with primary or
secondary distribution facilities not owned by ldaho Power.
Distribution Primary System Level
The distribution primary system level inputs include the output of the distribution stations level and
customer owned (PURPA) generation connected to the primary distribution system. The distribution
primary level outputs are the direct primary sales (primary metered customers) and the output to the
distribution secondary system level. The direct primary sales totals were found in MV90 data on the
peak system hour 17l!21L2 -5 pm).
2012 Peak Loss Coefficients Diagram
ldaho Power Company
2012 Peak Loss Coefficients Diagram - lncluding Wheeling
Values in MW
2012 Summer Peak:
Power Supply Gen
Utility Purchases
PURPA/Cust Gen
Exchange ln
Wheeling ln
7/L2l2Ot2
4:00 PM
2,534
501
101
70
1,516
3245 MW
105.3 Retail Transmission Sales
0 High Voltage Sales
4 Exchange Out (Excluding Bridger
and Valmy loss transactions)
1,554 Wheeling Out
2,980 To Distribution Stations
PURPA 50.3
2,45L To Distribution Secondary
2,805 To Distribution Primary
113.5 Direct Station Sales
28.1 lrrigation Sales
14.9 Wheeling Out
340 Direct Primary Sales
0.1 Wheeling Out
2,350 Distribution Sales
3.51 lPCo lnternalUse
35.9 Wheeling Out
Transmission System
4,655
lnput =
Losses =
Output =
4,822
L67.L
Loss Coefficient = 1.0359
Distribution Stations
2,962
lnput =
Losses =
Output =
2,980
t8.64
Loss Coefficient = 1.0053
Distribution Primary
2,791
lnput =
Losses =
Output =
2,866
74.7
Loss Coefficient = 1.0258
Distribution Secondary
2,39L
lnput =
Losses =
Output =
2,451
60.1
Loss Coefficient = 1.0251
Figure 2: 2Ot2 Peak Loss Coefficient Flow Diagram
Delivery Point Loss Coefficients
One of the primary goals for this loss study is to determine the total amount of energy required to be
generated to serve a customer at any given delivery point in the system. Or in other words, how much
energy must be generated from ldaho Power generators to deliver 1 kwh of energy to a customer
connected to the ldaho Power system at the distribution secondary level? Delivery point loss
coefficients are used to define the total losses to each delivery point level in the system. Delivery point
loss coefflcients calculated by multiplying allthe "upstream" individual level loss coefficients together.
The 2012 delivery point loss coefficients for energy and peak demand are shown in Table 13 and Table
L4.
Deliverv Point Enerw Loss Coefficients
Transmission 1.034
Distribution Stations 1.040
Distribution Primary 1.051
Distribution Secondary 1.096
Table 13: 2012 Delivery Point Energy Loss Coefficients
Deliverv Point Peak loss Coefficients
Transmission 1.035
Distribution Stations LO42
Distribution Primary t.07O
Distribution Secondary L.097
Table 14: 2012 Delivery Point Peak Loss Coefficients
AppendixA: 2012 Energy Losses Data Sources
Transmission
lnputs
Value
(Mwhl Data Source Notes
Power Supply
Generation 13,859,001
FERC Form 1 p 401a line
9
Utility
Purchases 1,7LL,463
FERC Form 1 p 326.8 -
327.L2 col g (Subset of
Utility Purchases FERC
Form 1 p 401a line 10)
OATT Power purchases from
utilities/entities not directly connected to
IPC system
PURPA/Cust
Gen 1,388,995
FERC Form 1 pp 325-
327.7 col g (Subset of
Utility Purchases FERC
Form 1 p 401a line 10)
Power purchased from non-lPC owned
generation connected to IPC transmission
svstem
Exchange ln 392,3L3
FERC Form 1 p 401a line
L2
Details on FORM L p326.L2-327.L3
See "Exchanees 2012 ln Out.xlsx"
Wheeling ln 6,074,L32
FERC Form 1 p 401a line
16
Transmission
Outputs
High Voltage
Sales 2,L83,262
FERC Form 1 p 401a line
24 Details on Form 1 p 311
Exchange Out 152,381
FERC Form 1 p 401a line
t2
Details on FORM Lp326.L2-327.L3
See "Exchanges 2012 ln_Out.xlsx"
Wheeling Out 5,864,395
FERC Form 1 p 401a line
L7 File: "Wheeling Form l Detai!"
Retail
Transmission
Sales 328,050 MV90 data and Pi
Rate 9T, 19T and transmission loads with
customer owned substations; see files
'2012MV90Sum mary.xlsx" a nd
"Transmission level customers not in
MV90 data.xlsx"
Distribution
Station
Outputs
Direct Station
Sales 851,866 MV90 hourly data Filename:'2012MV90Summary"
lrrigation Sales 85,375 MV90 hourly data
Filename:'2012MV90Summary"; Total
for "Su bstation Customers"
Note: this total does not match the total
in FERC Form 1 "Special Contracts"
because the INL load is assigned to the
transmission layer.
Wheeling Out 92,LsL Operation Data File: "Wheeling Form l Detail"
Distribution
PURPA 555,879
PURPA gen connected to
IPC Prima ry distribution
system from FERC Form
1p326-327.7 cole
Subset of Utility Purchases
FERC Form 1 p 401a line 10
Total from p 401a line 10 is split by system
level on spreadsheet:
Cogen_PURPA_Purchases Detail FERC
Form 1 2012
Disribution
Primary
Outputs
Direct Primary
Sales 2,468,64L MV90 hourly data Filename: "2012MVgOSummary"
Wheelins Out 898 Operations Data File: "Wheeling Form l Detail"
Distribution
Secondary
lnputs
1,L25
FERC Form Lp326.t2-
327.t2 col g (Subset of
Utility Purchases FERC
Form 1 p 401a line 10)
Net Met/Ore
Solar Net-metering and Oregon Solar customers
Distribution
Secondary
Outputs
Distribution
Sales L0,302,329
Calculated: lnputs -
losses - lPC company use
lPCo lnternal Use 22,8L8 IPC Load Research IPC Rate 0
Wheelinc Out LL7,675 Operations Data File: "Wheeling Form 1 Detail"
Appendix B: 2012 Peak Losses Data Sources
Transmission
lnputs
Value
(Mw)Data Source Notes
Power Supply
Generation 2,534 Pi
Power flow model closely
approximates actual Pi data
Utility Purchases 501
From Operations records from
peak day,7lL2llz 4 pm Mtn
time
see file "System operations peak day
inputs outputs 2012_2013.x1sx"
PURPA/Cust Gen 101 Pi matches power flow model
Exchange ln 70
From Operations records from
peak day, TlLzlLZ 4 pm Mtn
time
see file "System operations peak day
inputs outputs 2012 2013.x1sx"
Wheeling ln 1,6L6 Operations data on peak hour File: "PeakWheeling20l2_2013.x|sf
Transmission
Outputs
High Voltage
Sales 105
Transmission customer sales
from MV90 data: filename
"2012MV90Sum mary.xlsx"
Also "Transmission Level customers
not in MV90 Data.xlsx"
Exchange Out 4
From Operations records from
peak day,7lt2lL24 pm Mtn
time
see filename "System operations
peak day inputs_outputs
2012 2013.x1sx"
Tronsmission
losses 167.2
Determined from peak power
flow model simulating 2072
system peok on 7/12/12 4-5 pm
See file: "Peok PowerFlow
model.xlsx"
Wheeling Out 1,564 Operations data on peak hour File: "PeakWheeling2012 2013.x1sx"
Distribution
Station Outputs
Direct Station
Sales 113 MV90 hourly data filename'2012MV9OSu mmary.xlsx"
lrrigation Sales 28 MV90 hourly data filename'2012MV90Summary.xlsx"
Distribution
Station Core
Losses 4.42L Manufacturer Test Data
IPC Apparatus group (Cascade)
See "Dist Substotion Tronsformer
tosses 72Ju1y2072 peok hour.xlsm"
Distribution
Station Winding
Losses L4.218
Colculated from MW looding on
7/12/12 4 pm to 5 pm (peok
2072 hour)
Filenome: " Dist Substotion
Tronsformer losses 12Ju1y2072 peok
hour.xlsx"
Distribution
Stotion Peok
Iosses 78.640 Sum of Core and Windi losses
Filenome: "Dist Substotion
Tronsformer losses 72Ju1y2072 peok
hour.xlsx"
14.9Wheeling Out Operations data on peak hour File: "PeakWheeling2012_2013.xlsx"
Dastribution
Primary lnputs
PURPA 50.3
Generotion doto from
Operotions Logs, Pi, ond Cogen
Poyment data
See fi le : " Cog e n_P U RP A_P u rch o ses
DetoilFERC Form 7 2072.x1sx"
Distribution
Primary Outputs
Direct Primary
Sales 340.0 MV90 hourly data filename "2012MV90Summary.xlsx"
Distribution
Primory [osses 74.7
Difference of Distribution
lnputs and Outputs with
calculated Distribution Line
Transformer losses included in
secondary losses
Files: "Distribution Peok losses
2072.xisx"
"Dist Line Trtrmrs fosses 2072.x1sx"
Wheeline Out 0.1 Operations data on peak hour File: "PeakWheeling2012 2013.x!sx"
Distribution
Secondary
Outputs
Distribution Sales
lPCo lnternal Use 4 from billing - all Rate 0
See file "Company Use Data
2012.x|sx"
Distribution
Secondory losses 60.1
Difference of Distribution
lnputs and Outputs including
calculated Distribution Line
Transformer losses
Files: "Distribution Peok losses
2072.xlsx'
"Dist Line Txfrmrs Losses 2072.x1sx"
36.9 Operations data on peak hourWheeling Out File: "PeakWheeling2012 2013.x|sx"
Appendix C: Loss Coefficients Not Including GSU Losses
System delivery point loss coefficients not including generator step-up transformer unit (GSU) losses and
including wheeling:
Deliverv Point Total Enercv loss Coefftcients
(No GSU lossesl
Transmission 1.031
Distribution Stations L.O37
Distribution Primary 1.059
Distribution Secondary 1.094
Deliverv Point Total Peak toss Coefficients
(No GSU lossesl
Transmission 1.035
Distribution Stations 1.041
Distribution Primary 1.069
Distribution Secondary 1.096
Appendix D: Reconciliation with FERC Form 1
The data used in the development of the energy loss coefficients in this report is consistent with that
reported in the 2012 FERC Form 1 page 401a. Values used in Figure 1 are reconciled with values in 2OL2
FERC Form 1 below.
Svstem Losses
The ratio of Figure 1 losses to Adjusted FERC Form 1 losses is 99.94ot6. Reasons for the small discrepancy
may include non-uniformity between the calculation method used to determine transmission losses on
the Bridger and Valmy subsystems in this study versus the calculation method used to determine the
actual loss transactions and estimation methods used where small amounts of data were missing in the
tabulation of individual level losses.
!tem Figure 1
MWh
2012 FERC
Form l MWh
Comment
Total System Losses t,473,L7L L,253,953 Form 1, pg 401a, line 27
Adjustment for Bridger Loss
Transactions
238,94L Bridger Loss transactions counted as
system outputs in Form 1 (part of
total in Form 1, pg 401a, line 13)
Adjustment for Valmy Loss
Transactions
3,935 Valmy Loss transactions counted as
system outputs in Form 1 (part of
totalin Form 1, pg4Ota,line 13)
Adjustment for Company Use -22,8L8 Company Use counted as losses in
Form 1 (part oftotal in Form 1, pg
40La,line27l
Adjusted Total L,473,t7L t,474,OLL