20201119IPC to Staff 59-93.pdf

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LISA D. NORDSTROM
Lead Gounsel
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November 19,2020
VIA ELECTRONIC FILING
Jan Noriyuki, Secretary
ldaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, ldaho 83714
Re: Case No. IPC-E-19-19
2019 lntegrated Resource PIan
Dear Ms. Noriyuki:
Attached for electronic filing, pursuant to Order No. 34602, is ldaho Power
Company's Response to the Third Production Request of the Commission Staff.
lf you have any questions about the aftached documents, please do not hesitate to
contact me.
Very truly yours,
&L !.2(,,d-t,.^,
Lisa D. Nordstrom
LDN:slb
Attachment(s)
LISA D. NORDSTROM (lSB No. 5733)
ldaho Power Company
1221West Idaho Street (83702\
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
lnordstrorn@ lda hooower. com
Aftorney for ldaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POT/VER
COMPANY'S 2019 INTEGRATED
RESOURCE PIAN
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CASE NO. |PC-E-19-19
I DAHO POI/VER COMPANY'S
RESPONSE TO THE THIRD
PRODUCTION REQUEST OF
THE COMMISSION STAFF TO
IDAHO POWER COMPANY
COMES NOW, Idaho Power Company ('ldaho Powef or "Company'), and in
response to the Third Production Request of the Commission Staff to ldaho Power
Company dated October 29,2020, herewith submitrs the following inbrmation:
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POI/',ER COMPANY.l
REQUEST NO. 59: Please answer the following questions about the
Comprehensive 2019 tRP Review Process outlined on pages 2 through 6 of the
Company's Second Amended 2019 !Rp:
a- Does the Gompany plan to apply this process to the 2021 lRp? please
explain why or why not.
b. lf the Company plans to apply this process to the 2021 !Rp, please describe
any modifications to the process contemplated by the company.
RESPONSE TO REQUEST NO. 59:
a. \Mtile the Company does not plan on deconstructing and examining allfacets
of the IRP analysis for lhe 2021 lRP, the 2019 IRP Review prooess will be
applied to and/or inform the 2021 IRP process. tn instances where the
prooess has changed and the 2019 IRP Revierry process doesn't direcgy
apply, learnings from the 2019 IRP Review process will be applied. The
following are some examples of how the 2019 IRP Review prooess will be
applied to the 2021 IRP:
i. The flowcharts developed for each major input in the 201g lRp Review
process will guide ffre Company as input data is collected and
reviewed for the 2021 lRp.
ii. A model output verification and validation step will be consistenly
apptied across all major inputs to the 2021 IRP with subject matter
experts to ensure the model is working as expected.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTIONREQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY.2
b. Modifications, while not yet identified, will address the changing nature of the
lRP. The high-level goals of model accuracy and validation will remain the
same.
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power Company.
IDAHO POVVER COMPAI{Y'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVI/ER COMPANY .3
REQUEST NO. 60: Does the Company plan to conduct ib 2021 lRp analysis
using a capacity expansion methodology that selects portblios optimized for ldaho
Power's service territory? please explain why, or why not.
: yes. The Company is in the process of
determining whether the Long-Term Capacity Expansion option in the newest version of
Aurora is able to effectivety optimize for tdaho Powe/s service area while adequately
representing future conditions in the Westem Electricity Coordinating Council (.\TVECC).
The evaluation is still undenray and the final decision has yet to be made on how to
proceed with the capacity expansion solution forthe 2021 lRp.
The Company is committed to a capacity expansion step which will continue to
be a first step in the process regardless of whether manual relinements are
recommended to validate or further optimize the results.
The response to this Request is sponsored by Jared Hansen, Resource planning
Leader, ldaho Polrer Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE THIRD PRODUCTTONREQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY .4
states
REQUEST NO. 61: ln the company's 2019 IRP Review Report the company
Subseguent to the initiat fiting, tdaho Power discovercd that the
LTCE model optimized pnfoiios for the entire Westem Electricity
Coodinating Cbuncil WCC) rcgion, but not neessarily for ldaho
powefssyitem in particutar. Foi|/71is reason, on July .19,2019,-the
company notified the commr'ssions of the need to perform
"uppteiental
analysis to ensurc that the IRP yielded a leasf-cosf,
leasf-nbk solution specific fo IPC's serutce area, and asked that the
Commissions refruin frcm afupting a prccedural schedule until an
amended IRP could be filed. Repofi at 1.
a. please describe what steps the Company has taken to identify requirements
and specifications for capacity expansion modeling solutions or software to
address and resolve this Problem.
b. Additionaly, please describe how the Company will elirninate the potential for
reoccurrence of this problem in subsequent capacity expansion modeling and
lRPs.
c. please explain the criteria that ffre Company is using to select capacity
expansion sofitrare.
d. please identiff all capacity expansion softtrvare that either is or was under
review.
e. If software has been identified, please provide the name and vendor of that
softrare.
RESPONSE TO REQUEST NO. 61:
a. The process the Company used to identiff requirements and specifications
for capacity expansion modeling softurare for the 2019 IRP is explained in the
Company's response to Stafi Request No. 7. ln addition to following the
IDAHO POVVER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 5
same process prior to lhe 2021 lRp, the Company is applying experience
gained through the 2019 IRP analysis process and the 201g lRp Review
process to ensure the modeling software will perform well. The requirements
and specifications are identical to those listed in the Compant's response to
Staff Request No. 56, with the addition of the ability to optimize resufts
specifically for ldaho Power and its customers.
The company has been in contact with Energy Exemplar regarding
enhancements to Aurora. New functionality has been added to the latest
Aurora release. As discussed ln the company,s response to Staff Request
No. 60, the company is in the early stiages of testing out this new
functionality.
b. The Company shares the @noern and is formulating steps to ensure
optimized modeling results in the 2021 lRP. These steps include the
following:
r The Company developed tools to ensure that the planning margin is
maintained specifically for the company, versus building and
optimizing resources for the \ IECC, but not necessarily ldaho powe/s
system. These tools were used during the manual optimization
process for the 2019 IRP and can be used to check the effectiveness
of the capacity expansion tools selected for the ZA21 lRp.
o The company will leverage rearnings from the 2019 lRp Review
process to veriff and validate portfolios developed for the 2021 lRP.
IDAHO POWER COMPANY'S RESPONSE TO THE THTRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVVER COMPANY.6
This includes the use of the flowcharting of input processes and
leveraging experts' understanding to validate modeling results.
c. \Men assessing capacity expansion software, ldaho Power evaluates
whether these models can replace some or all of the funclionallty that Aurora
currently provides. Presently, Aurora remains the most viable option moving
forward.
some of the criteria used in the evaluation are as follows:
r The ability to optimize for ldaho Powe/s sptem (see the Company's
response to Staff Request No. 8).
. production of information that facilitates meeting the Company's
objectives to optimize cost, risk, reliabili$, and environmental fiac{ors
(see the Company's response to Staff Request No'9)'
o Tools available to aid in the validation of the model.
o Model runtime.
. The availability of the modeling tools to Staff and other utilities in the
northwest was considered.
d. ln addition to the softnare identified in Part (a) of this response, the Company
also evaluated PowerSlMM by Ascend Analytics.
e. \Mile the final selection is still pending based on the results of further testing,
the Company is currently focusing efforts on the Aurora modeling soflvvare
developed bY EnergY ExemPlar.
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power ComPanY.
IDAHO POVVER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISS]ON STAFF TO IDAHO POWER COMPANY - 7
REQUEST 1{O. 62: On page 2 of the Company's Second Amended 2019 lRp,
the Company states that one objective of its 2019 IRP Review prooess was Validation
of Model outputs. Please explain how modeloutputs were validated,
RESPONSE TO REQUEST NO. 62: Validation of the model outputs was the
focus of Step lV of the 2019 IRP Review process. The overarching goa! of Step lV was
to veriff and validate the AURORA model outputs to ensure the modet produoed logical
and consistent results. Each sub-team evatuated the reasonabteness of the output or
performed additionalwork to validate the data as neoessary. The process to veriff and
validate the key inputs was unique to each input and is described in detail in Section 5
of the 2019 IRP Review Report. The 2019 IRP Review Report can be found on the
ldaho Power website at the following link:
hiles//Cocs.idahooouer.oom/pdft/Abq{UslPlanninoForFutureilrnnOtg/Z01glRp
RevieuyReoorP roegsFi nd lngrs. pd f
AdditionallY, for the adjustments identified from Steps I through il!, sensitivity
runs were completed to determine the impac't. These sensitivities compared the input
data used in the Amended 2019 IRP and the associated results to reruns of select
portfolios with the adjustments identified by the IRP Review Team. These resutts are
contained in Section 6 of the 2019 lRp Review Report.
The response to this Request is sponsored by Jared Hansen, Resource planning
Leader, ldaho Power Gompany.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMTSSION STAFF TO IDAHO PO\'l/ER COMPANY - 8
REQUEST NO. 63: On page 3 of the Gompany's Second Amended 2019 lRP,
the Company states that it reviewed model outputs. Please explain the criteria used by
the IRP Review Team to evaluate the consistency and accuracy of Aurora LTCE
outputs.
RESPONSE TO REQUEST- NO. 63: The review of the model outputs included
subject matter experts and learnings from Sfep I; lnput Data and Source Review and
Step ll: Feeding Data into the Model.
Vrlhile the validation techniques for each input varied, the criteria and process
used to evaluate the model inputs and outputs are covered generically in Section 2.2 of
the 2019 IRP Revieuv Report (pages 3-5) and specifically for each input in Ghapters 3-5
(pages 8-60) of the same report. The 2019 IRP Review Report can be found on the
ldaho Power website at the following !ink:
htps://docs. idahopower.com/odfs/AboutUs/PlanninqForFuture/irp/201 9/201 9l RP
ReviewReoortProcessFindings.odf
The response to this Request is sponsored by Jarcd Hansen, Resource Planning
Leader, ldaho Power CompanY.
IDAHO POV\'ER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY .9
REQUEST NO..64: On pages 4 and 5 of the Company's Second Amended 2019
lRP, the Company states that Naturat Gas Variable Transport Costs were inadvertenly
not included in the model. Please provide workpapers showing the variable transport
costs, per Therm, of gas that was excluded over the life of the model.
BESPONSE TO REQUE$T NO. 6{: Please refer to the Confidentiat Excel fite
accompanying this response for the natural gas variable transport costs inadvertenly
excluded in the model.
The response to this Request is sponsored by Jared Hansen, Resource planning
Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 10
REQUEST NO. 65: ln the summary of the Irrigation Peak Rewards program on
page 10 of Appendix B of the Company's Second Amended 2019 IRP (DSM Annual
Report), the Company stiates: "This maximum realization rate is not always achieved
for every program in any given yeat." Please provide the following information:
a. \Mat is the maxirnum coincident peak reduction achieved by the Company's
lrrigation Peak Rewads program since the program's inception, and on what
date and time did this occur?
b. Under the program's current structure, what is the maximum coincident peak
reduction that could be achieved by the Company's lrrigation Peak Rewards
program?
c. Under the program's current structure, what is the maximum coincident peak
reduction that could be achieved by the Company's lrrigation Peak Rewards
over five consecutive daYs?
RESPONSE TO REQUEST NO. 65:
a. The maximum coincident peak reduction achieved by the Company's
lrrigation Peak Rewards program since the program's inception was 318 MW
on July 6,2017 between 5 and 6 Pm.
b. Under the current program struc'ture br the lrrigation Peak Rewards program,
the Company believes the maximum coincident peak reduction that could be
achieved is approximately 325 MW. This would assume:
a. A high percentrage of eligible participants are participating.
b. The event happens at the peak of the irrigation season with a high
Percentiage of PumPs being on.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVVER COMPANY - 11
c. Opt-outs and device hitures are low.
c. As stated in the response to b., under the cunent program structure the
Company believes the maximum coincident peak reduction that could be
achieved on a single day is approximately 32s MW. lt ls important to note
the cunent program rules allow a maximum of 15 hours of reduction for each
participating service location in a single week, and the maximum number of
events the company has had in one week is two events for a total of eight
hours redustion for each participating service location.
To fully utilize he capacity reduction from the program as peak
reduc,tion to the Company's system load, the Company has determined that it
needs to run events from 2 to 9 pm (7 hours). This is achieved by having four
groups each with four hours of intenuption, with allfour groups overlapping in
the 5€ pm hour. lf the Company wanted to run events for five consecutive
days, the events would need to be restructured with three groups, three hours
long, resulting in only a five-hour reduction period, which could result in the
company not achieving the intended peak reduction to the company's
system load.
Regarding participant impact, the company expects if the program
were operated under this structure, it would experience an increase in
customer opt outs on each consecutive day after the initial event of two to five
percent. The Company also anticipates that five consecutive days of
irrigation interruptions would result in a significant impact to customerc'
agricultural operations, which may result in the customer not being willing to
IDAHO POVVER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY. 12
participate in the program in the tuture.
The response to this Request is sponsored by Quentin Nesbitt, Gustomer
Research & Analysis Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY. 13
REQUEST NO. 86: On page 6 of the Company's Second Amended 2O1g lRP,
the Company states, 'The B2H transmission line continues to be a top performing
resouroe alternative, providing ldaho Power ac@ss to clean and lovrr-cost energy in the
Pacitic Northwest wholesale market." PIease provide an explanation of all assumptions
made by the Company regarding the availability of power, including the Company's
assumptions about hortr Washington's Clean Energy Transformation Act (CETA) would
impact energy available to import through B2H for ldaho power customers.
RESPONSE TO REQUEST NO. 66: The Company used the AURORA modet
from software developer Energy Exemplar as the basis for its 2019 IRP analysis. The
default database for the AURORA model includes data for existing loads and resources,
planning margins by area, all known renewable portfolio standard (RPS) requirements
for each state, future resource characteristics and costs by resource type and area,
future demand requirements for all areas, and other inputs. Throughout the IRP
process, ldaho Power identified numerous inputs and modeling changes that needed to
be modified in AURORA to better reflect conditions for the 2O-year IRP planning
horizon. The Company presented and discussed the modifications/changes during the
IRPAC meetings. Some of the inputs that were modified included: natural gas prices,
carbon prices, the Company's load forecast, and new resouroe costs specific to the
Company. Once the inputs were validated and placed into AUROFIA, a Long-Term
Capacity Expansion ("LTCE') for the entire WECC was performed. The LTCE ensures
that adequate resources are built throughout the WECC by adhering to strict planning
margins by area, as well as all other mode! constraints. For example, the planning
margin for ldaho Power is 15 percent; if the Company's demand is 3,500 megawatts
IDAHO POVI'ER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 14
('MW'), AURORA builds enough resources to meet 4,025 MW (4,025 = 3,500 * 1.15) of
demand for the Company's area. The AURORA LTCE builds areas to a predefined
planning margin ensuring adequate resources to meet demand under conditions that
could exceed a planning condition. Because the planning condition is evaluated during
the IRP pro@ss, adequate supply of generation would exist throughout the WECC and
specifically in the Northwest.
The Company atso performed supplemental analysis in the "Liquidity and Market
Sufficiency Risk" section of Appendix D starting on page 54.
The Washington CETA was not signed into law until May 2019; therefore, it was
not included in the 2019 lRP.
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 15
REQUEST NO. 67: On page 8 of the Company's Second Amended 2O1g lRp,
the Company states that it forecasts load and demand growth of 1.0 and 1.2o/o,
respectively. The Company also states that total customers are expected to increase
from 550,000 to 775,000 between 2018 and 2038, or an annual growth rate of 1.lo/o.
Please explain why the Company believes that load and demand growth will be less
than the annualpopulation growth rate.
RESPONSE TO REQUEST ltl0. 67: The primary driver for the differing of
customer growth rates and sales growth rates as noted in staffs Request 67 in the
Company's service area is related, but not limited to, energy efriciency. During the
development of the 2019 IRP and subsequent amendments, the Company,s load
forecast is built on an assumption of energy efficiency potential as identified by a third
party, Applied Energy Group ('AEG"). lf the projection of the load growth rate is
reconstituted in absence of future energy efficiency potentiat as identified by AEG
between 2018 and 2038, estimated projected load growth would have been 1.60/o.
The response to this Request is sponsored by Jordan Prassinos, Manager Load
Forecasting and Research, ldaho power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTIONREQUEST OF THE COMMISSION STAFF TO IDAHO POWER COUPNruV. TO
REQUEST NO. 68: On page 58 of the Company's Second Amended lRP, the
Company explained that its third-party contractor provided a Z}-year forecast of ldaho
powe/s energy efficiency potential from a total resource cost (TRC) perspective. ln
Final Order No. 34469, the Commission ordered the Company to use the 'UCT
perspective for integrated resource planning.' Please explain why the Company's
contractor did not conduct iF energy efficiency potential study using the UCT (Utility
Cost Test).
RESPONSE TO REQUEST NO. 68: The ldaho Public Utilities Commission did
not issue Order No. 34469 directing ldaho Power to use the Utility Cost Test ("UCT)
perspective for integrated resource planning until October 31,2019, and the potential
study used in the 2019 IRP was completed in the first quarter of 2019. As part of the
Company's Petition for Clarification of Order No. 34469, ldaho Power noted "changes to
the cost-effectiveness test for energy efficiency will be carried out over the 2020 IDSMI
program year to synchronize with the Company's annual planning cycle. The Company
will also start the process for implementing the UCT as the primary perspective as it
moves into the next tntegrated Resource Plan planning cycle, with a new DSM Potential
Study based on the UCT perspective, which the Company will initiate in the firct quarter
of 2020."1
1 ln the Matter of the Application of tdaho Power Company for a Determination of 2018 Demand-Side
Management Expendiiires as Prudentty lncuned,ldaho Power Company's Petition br Clarification of
Order No. 34469, p. 6-7.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POI'\'ER COMPANY - 17
Early in 2020 the Company hired a third party to perfurm an energy efficiency
potential study using the UCT which will be used for the 2021 lRP. Further, for the
Second Amended 2019 lRP, the Company did not change the energy efficiency
forecast inputs to ensure the same basis for comparison to earlier versions of the 201g
IRP.
The response to this Request is sponsored by Quentin Nesbitt, Customer
Research & Analysis Leader, ldaho Porer Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVI'ER COMPANY - 18
REOUEST NO. 69: On page 109 of the Company's Second Amended lRP, the
Company explains that it manually adjusted six WECC-optimized Portfolios. Please
explain the following:
a. \Mrat criteria did the Company use to select these six \AlECC-optimized
Portfol ios for further adi ustment?
b. What criteria did the Company use to group portfolios into "buckets" as
described on the same Page?
RESPONSE TO REQUEST NO. 69:
a. Previously, in the Amended 2019 lRP, the Company selected two portfolio
pairc (B2H and non-B2H) that represented a combination of low cost and lottt
variance across different future conditions. This resulted in four starting points
(see Slide 1 of the attachment to this request).
For the Second Amended IRP analysis, the Company recognized that
portfolios with similar identified resouroes could be grouped together, or
"bucketed' within the various portfolios developed under planning gas,
planning carbon ('PGPC') and planning gas, high carbon ('PGHC") forecasts
as shown on slide 2 of the attachment. Many of the other portfolios featured
similar resour@s in similar amounts to the PGPC and PGHC portfolios.
Additionally, the Company adopted feedback received during the
Amended IRP process and selected a more diverse afiay of portfolios for
manual optimization. The high gas, high carbon portfolios identified some
unique resources compared to the other portfolios, The Second Amended
IRP manual optimization process started with three non-B2H and three B2H
IDAHO POV\IER COMPANY'S RESPONSE TO THE THIRD PRODUCT]ON
REOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 19
portfolios br a total of 6 portfolios as opposed to the four previously selected
in the Amended IRP. See, Slide 3 of the attrachment for a visual
representation of the tAJECC-optimized portfolios that comprised the three
"buckets'that served as starting points for the manual optimization process.
b. PIease see part (a).
The response to this Request is sponsored by Jared Hansen, Resource planning
Leader, ldaho Power Gompany.
IDAHO POVVER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMTSSION STAFF TO IDAHO POWER COMPANY.20
REQUEST NO. 70: According to Figure 10 (page 57) of Appendix D of the
Company's Second Amended lRP, the Pacific North West (PNW summer surplus
decreases from 6,000 MW in 2O20to2,OO0 MW in 2029 for an average decrease of 400
MW per year. At this rate, the PNW would experience a summer capacity deficit in the
year 2034. \frlhy does the Company believe that the region will have sufficient summer
capacity for ldaho Powe/s summer peak needs after 2034?
RESPONSE TO REQUEST NO.70: The key item to focus on in Figure 10 is the
gap between the summer surplus/deficit and the winter surplus/deficit. This gap
remains constiant through the 10-year forecast period and shows a growing near-term
winter deficit. The graph indicates that the region must build resour@s to address this
winter deficit, which will result in increasing the summer surplus, i.e., maintaining the
winter line at our above 0 MWwill by default maintain a significant summer surplus.
Other factors are also important to consider including:
1) The curves in Figure 10 do not include surplus capacity controlled by
Canadian utilities in the PNW.
2) The curves in Figure 10 include ldaho Power. Removing ldaho Power would
widen the gap - increasing the summer surplus and reducing the winter
surplus (increasing the winter deficit), which further emphasizes the need for
other entities in the region to build new resources to address this winter
deficit.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY.2l
REQUEST No. 7l: Figure 10 (page 57) of Appendix D of the company,s
Second Amended IRP was based on an April 2019 BPA adequacy assessment. !n May
2019, the State of Washington passed ib GIean Energy Transformation Act (CETA).
a. Were the effects of the implementation of CETA factored into the April 201g
BPA adequacy assessment?
b. lf not, please explain how the Gompany believes that CETA woutd afiect the
forecasts displayed in Figure 10.
RESPONSE TO REQUEST NO. 71:
a. The Gompany does not believe that CETA was factored into the April 2019
B PA adequacy assessment.
b' For the BPA \Mite Book, new regional generation projects are included when
those resouroes begin operating or are under construction and have a
scheduled on-line date. Similarly, retiring resources are removed on the date
of the announed retirement. Given this, the Company does not believe
CETA will affect the \Mrite Book assessment until resour@s to futfill CETA
have been definitively identified.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCNON
REQUEST OF THE COMMISSION STAFF TO IDAHO POVI'ER COMPANY - 22
REQUEST NO. 72: On page 59 of Appendix D of the Company's Second
Amended lRP, the Company states, "Under this arrangement, BPA and/or its
customers' OATT payments would, over time, ensure recovery of ldaho Power's
revenue requirement associated with BPA's respective usage of B2H.'
a. How will the contemplated transmission servioe agreement guarantee full
recovery of ldaho Powe/s revenue requirement?
b. t1t1try does the Company believe it appropriate to include a share of a line that
is not used to serue the needs of ldaho Power Customers in ldaho Power's
rate base?
RESPONSE TO REQUEST"NO. 72: Such an arangement between the
Company and BPA remains hypothetical at this time.
a. ln the event Idaho Power and BPA decirje to transition BPA's ownership
share into a transmission service-based contract, one of ldaho Power's
requirements is that BPA and/or its customers' OATT payments would, over
time, ensure recovery of ldaho Powe/s revenue requirement associated with
BPA's respective usage of B2H. To date, the Company and BPA have not
determined a financial structure that would futfillthat requirement.
b. The Company has not proposed, or claimed it would be appropriate, to
include the share of B2H designated to BPA in ldaho Power's retail rate base.
Should the Company propose this when seeking regulatory approval of the
projecfloverall arrangement, the Gompany expects the arrangement would
have retail customers benefiting from the arrangement, or at-worst, be
indifferent.
IDAHO POIA'ER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVVER COMPANY.23
The reeponse to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resoure Planning Director, tdaho power company.
IDAHO POI/I/ER COMPANY'S RESPONSE TO THE THIRD PRODUCNONREQUEST OF THE COMMISSION STAFF TO IDAHO POWCN COMPANY - 24
REQUEST NO. Z3: Please provide an update to Production Request No. 25 with
an assumption that the company will own 45o/o of Boardman to Hemingway
Transmission Line. please provide the update in EXCEL format with formulae and links
intact.
RESPONSE TO REQUEST NO. 73: lMrile the company's ownership share may
increase to 45 percent in the hypothetical arrangement, Production Request No. 25
asks for ,the Company's estimate of the costs of B2H lo ldaho mtepayers." The answer
provided in Production Request No. 25 remains accurate'
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
NEOUEST OF THE GOMMISSION STAFF TO IDAHO POWER COMPANY - 25
REQUEST NO. 74: Please explain why paying higher property taxes in Oregon
benefits current and future ldaho ratepayers? (Amended Application page 1g - listed
two benefits)
: The B2H line transverces several counties
in oregon, and one of the benefits the B2H project provides these counties is an
increase in propefi taxes. BPA, as branch of the federal govemment, does not pay
property taxes. Property tiaxes will only be levied on the non-Ederat portion of the
project.
ln the event ldaho Power and BPA decide to transition BPA's ownership share
into a transmiesion service-based contract, property taxes would be tevied on the full
value of the project. As described in the Company's response to Staff Requests Nos.
72 and 73, under the current hypothetical arrangement, these costs woutd not
negatively impac,t ldaho Power,s native load customerc.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho power company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTIONREQUEST OF THE COMMISSION STAFF TO IDAHO POT'I'ERbbMPANY.26
REQUEST NO. Z5: Please provide the other additional benefits, not listed, of
owning more than the assumed2lo/o of Boardman to Hemingway Transmission Line on
page 19 of Second Amended Application. (Amended Application page 19)
RESpONSE TO REQUEST NO. 75: ln the event ldaho Power and BPA decide
to transition BpAs ownership share into a transmission service-based contract, benefits
willdepend on the overall construct of the fullfina! arrangement.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Ptanning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY'27
REQUEST NO. 76: Wth BPA potentially dropping out of owning a portion of
B2H, please provide an updated project cost estimate that includes the additional taxes,
such as property, bderal, and state, no longer covered by Bonneville power
Administration. (Amended Application page 1g)
TO REQUEST 76:Financial discussions between the
Company and BPA are ongoing, and the Company has not developed estimates for
additiona! federal and state taxes that would be associated with ldaho power owning a
larger percentage of the B2H project.
Property tax estimates by county assuming BPA is a -24o/o owner in the project
are included on Page 50 of Appendix D. Scaling these values up assuming BpA is not
an owner of the project yields the following:
ldaho Power will be responsible for a percentage of these costs consistent with
the Company's ownership share of the B2H project.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho power company.
IDAHO PO\TVER COMPANY'S RESPONSE TO THE THIRD PRODUCTTONREQUEST oF THE coMMtsstoN STAFF To tDAHo powER coLapnruv - za
Tax Estimates - Annual
County wI BPA Ownership 1u/o BPA Ownership
ldaho/Owyhee $840,714 $1,109,743
Oregon/Morrow $386,497 $510,176
Oregon/Umatilla $251,957 $332,593Oregon/Union $g4z 592 $1?50,822OregonlBaker$1,868,431 $2,466,329Oregon/Malheur $1,879,990 $2,491,596
REQUEST NO. 77: ln its Amended Application, the Company states that there is
potential savings by exiting Valmy Unit 2 as early as year€nd 2022, and that additional
analysis will be conducted to identiff optimal exit timing. Please provide documentation
that shows the considerations that will be used to determine optimal exit timing of Valmy
Unit 2. Additionally, please provide the Compant's plan for communicating Valmy Unit
2 decisions and notifications.
RESPONSE TO REQUEST NO. 7?: The purpose of the valmy analysis will be
to determine the economic and reliability impacts to the ldaho Power grid associated
with an early retirement of Valmy Unit 2. Through additional Valmy analysis ldaho
power will consider, as an alternative to retaining Valmy capacity through 2025, a firm
energy purchase from energy markets to the south. The study will consider desert
southwest energy market pricing, market liquidity, and the deliverability of potential
market purchases to ldaho Power via existing transmission. Other considerations may
be added as the study plan develops.
ldaho power plans to communicate the study outline and study results at IRPAC
meetings early next year, followed by a filing with the Commission in the Spring 2021
timeframe.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution & Resource Planning Director, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REOUEST OF THE COMMISSTON STAFF TO IDAHO POWER COMPANY - 29
REQUEST NO. 78: On page 7 of the 2019 IRP Review Report, the Company
states that Valmy Unit 2 cannot provide regulation reserves. Please explain if the unit's
operating characteristics changed or if it was incorrectly identified in previous iterations
of the IRP as a regulation reserve resouroe.
RESPONSE TO REQUEST NO. 78: The operating characteristics of Valmy Unit
2 changed between previous lRPs and the 2019 lRp.
ln 2017, Valmy was still being used to provide regutation reserve requirements.
During the 2019 IRP rcview of the modet, it was determined that afthough Vatmy
provides support and flexibility in balancing ldaho Poweds system, it is no longer
directly used to provide reserves.
The response to this Request is sponsorcd by Jared Hansen, Resource Planning
Leader, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY.30
REQUEST NO. 79: On page 6 of 2019 IRP Review Report, the Company
describes a change in the way demand response is treated in modeling from a !ast-
resort resouroe to a resource to offset peak load. Please provide the analysis and
justification used to support this change, and documentation demonstrating that actual
deployment of demand response meets this purpose.
RESPONSE TO REQUEST NO.79: Dispatching Demand Response ("DR") as a
last-resort resource (the way it has been modeled in the past) sometimes, but not
consistently, results in an offset to peak load, as the peak demand of ldaho Power's
system may not be coincident with times of resource deficiency in the northwest.
Because the IRP is modeled under average conditions and because the Company's DR
programs are designed to be dispatched for extreme conditions, it is reasonable to align
that dispatch with the known peak hour for the months of June, July and August over
the 20-year planning period.
Section 3.7 of the 2019 IRP Review Report provides more details about the
change to demand response:
A DR event on the peak day in June, July, and August arc incorporated into the
hourly load forccast for each year during the 2l-year planning pertod. Hourty shaping
factors are then apptied over a target rrrnge of three hours prior to the peak hour and
three hours subseguent to the peak hour for each event (the hourty shaping factorc are
consistently apptied to all DR events over the 2Gyear period). The hourly shaptng is
then fed into AIJRORA. The sub-team drbcussed how the Resource Planning team
reviews a gnphical representation of a peak day (including a DR event with houtly
shaping apptied) and concluded that the hourly shaping of DR is reasonable.
TDAHO POWER COMPANY'S RESPONSE TO THE THTRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 31
See the attiachment accompanying this response for the requested
documentation. The attrachment provides a graphical reprcsentation of how the Aurora
model dispatched DR on a peak day in the furecasted period. The behavior illusfated
in the attachment matches how DR is dispatched in practice on ldaho powe/s system.
The response to this Request is sponsorcd by Jared Hansen, Resource planning
Leader, ldaho Power Company.
IDAI-IO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVT'ER COMPANY.32
REQUEST NO. q0: On page 6 of the 2019 IRP Review Report, the Company
describes a change in ramp rate from 100 percent to 60 percent for Langley Gulch'
please define the term "percent ramp rate," and explain the impact that this change will
have to the ComPanY's lRP.
RESPONSE TO REQUEST NO. 80: From the AURORA help menu, the ramp
rate is described as fotlows: "The value is expressed as a percent (%), which is divided
by 100 and multiplied by the resource capacity to determine the increase in resource
capability available in the next hour."
pertaining to the Langley Gulch ramp rate change, Section 5.5 of the 2019 IRP
Review Report states: "The ramp rate for Langley was set at 100 percent, meaning that
the plant can ramp from 0 to full capacity in one hour. The actual ramp rate is less than
100 percent and varies based on starting conditions. This modeling assumption was
discussed with the company's subject matter experts, and a sensitivity was performed in
AURORA to assess the impact of different ramp rates on the total portfolio Net Present
Value ("NpV') costs. Compared to the Amended 2019 IRP modeling with a 100 percent
ramp rate, the following reduced ramp rates were used to determine impact on portfolio
cost in NpV: A 23 percent ramp rate increased the NPV by 0.05 percent; a 50 perc,ent
ramp rate increased the NPV by 0.02 percent; and a 60 percent ramp rate increased the
NpV by 0.05 percent. The results show that reduced ramp rates have only a minimal
increase to the portfolio NpV and have an immaterial impact on the overall portfolio
outcomes. The sub-team determined that a 60 percent ramp rate would better reflect
actualoperations and the plant sefting was adjusted accordingly.'
IDAHO PO\A'ER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVVER COMPANY'33
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power Company.
IDAHO POVTER COMPAI{Y'S RESPONSE TO THE THTRD PROOUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY.34
REQUEST NO. 8l: Ptease provide eviden@, based on actual operation, that
the ramp rates for Danskin and Bennett Mountain plants are accurate in the model,
RESPONSE TO REQUEST NO. 8{: tn the AURORA model, the ramp rates for
the Danskin and Bennett Mountain plants are set to 1000/0, meaning that the plants can
start and ramp to ful! capacity within one hour. Both Danskin and Bennett Mountain are
peaker gas plants and are designed with the ability to quickly respond to peak demand.
These inputs were reviewed with ldaho Power subiect matter experts and
determined to accurately represent actual plant operations.
Please see the Excel file accompanying this request for an example of Bennett
Mountain and Danskin ramping from 0 to full capacity in one hour or less in actual
operation. Note that full capacity may vary from nameplate based on operating
conditions.
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power ComPanY.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 35
REQUEST NO. 82: Please explain the process the Company performed to
validate, not only the input assumption for all of its resouroes, but all inputs into the
model to ensure it represents actual operation.
RESPONSE TO REQUEST NO. 82: To ensure the data input into the modet a
total of 11 sub-teams were formed, each with appropriate subject matter experts, to
examine individual categories of AURORA model input data. ln Step I of the review
process, each of the sub-teams conducted deep-dive interviews with those at ldaho
Power responsible for preparing the data for use in AURORA. Company subject-matter
experts helped with the evaluation of a key input, its assumptions, and sources. ln Step
ll of the review process, the sub-teams conducted interviews with members of the
company's IRP planning team to analyze how each key input is fed into the AURORA
model, and gain an understanding, if applicable, of any ne@ssary changes or
conversions that were made to the data inputs to make them model ready. For more
details on Step ! and ll of the IRP review please refer to section 3 of the 2019 lRp
Review Report.
Pertaining to AURORA model inputs, in Step lll of the IRP revienv, the System
Settings Sub-Team performed an assessment of the setup and utilization of the
AURORA modelfor the 2019 lRP. Specifically, this sub-team was assembled to review
the model settings that were applied to perform long-term capacity expansion and unit
commitment optimization runs in support of the 2019 lRp filing.
The System Seftings Sub-Team systematically stepped through AURORA to
review all known model system settings. There are three distinct locations within the
AURORA model graphical user interface (GUl) where system settings can be adjusted:
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY.36
project Setup Menu, Simulation Options Menu, and lnput Tables. The sub-team created
an itemized list of the system settings that reside in each location. The sub-team then
reviewed each setting to ensure that they were corectly configured for the 2019 lRP.
For more details on the AURORA model inpuUsettings review please refer to sestion 4
of the 2019 IRP Review RePort.
The Gompany's response to Staff Request No. 62 addresses model inpuUoutput
validation.
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Porer ComPanY.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMM]SSION STAFF TO IDAHO POWER COMPANY - 37
REQUEST NO. 83: On page O4 of 2019lRP Review Report, naturatgas peaker
plant startup costs are described. The Company included the following results:
Resultrs - The adjustment to the startup costs of the peaker plants
resulted in thelargest impact to the resultrs of allthe adjusiments acrossthe tested portfolios. The Prebrred Portfolio increasedby 0.g3 percent,
with increases among the tested portfolios ranging from 0.7g percent to1.07 percent.
Please provide workpapers with formulas intact for all peaker plant startup cost
adjustments.
RESPONSE TO RE9UEST NO. 83: The Conlidentiat Excel file accompanying
this response contiains the startup cost for Bennett Mountain, Danskin 1, Danskin 2 and
Danskin 3.
The response to this Request is sponsored by Jared Hansen, Resource planning
Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTIONREQUEST oF THE coMMtsstoN srAFF To tDAHo powER cortapnNy - eg
7
REQUEST NO. 84: Please provide a detailed explanation for the IRP impact of
transmission input adjustments made to transmission line loss and wheeling rates,
transmission capacity input corrections (53 MW, 85 MW, and 200 MW, and for the
transmission capacity update for ownership share at Bridger West' 2019 IRP Report at
RESPONSE TO REQUEST NO, 84: These changes were made in aggregate to
select portfolios from the Amended 2019 IRP; the Net Present Value Revenue
Requirement changes are shown in the 2019 IRP Review Report on page 66'
The transmission adjustments were made to the model before the Second
Amended 2O1g lRp analysis and all portfolios developed in that analysis reflect the
changes. The transmission capacity increases were applied to peak load requirements
and the planning margin.
ln the new prefened Portfolio (PGPC B2H(1)), the capacity adjustment reduced
the need for the large amount of solar resouroes previously identified in the last two
years of the lRp timeframe. Transmission capacity was more effective at meeting peak
demand than solar or wind capacity on a per-MW basis (see the marginal capacity
factor of solar in Fiqure 4.1 and the capacity factor of wind on paqe 52 of the Second
Amended 201I IRP RePort).
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power ComPanY.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
niOuesr oF THE CoMMtSStON STAFF TO IDAHO POvtER CoMPANY - 39
REQUEST NO. 85: On page 28 ol 2019 tRP Review Report (Forecast
Generation), the Company states that all PURPA contracts are forecast to be replaced
upon expiration of the existing contract, except for wind contracts, because the
Company is unable to accurately predict whether wind Qualifying Facilities (eFs) will
choose to invest in repowering due to several factons. Please identiff and explain the
factors.
RESPONSE To REQUEST No. gs: tn ldaho power's experience, puRpA
contracts involving small hydro, biomass, cogeneration, and other renewable resouroe
types have entered into replacement contracts with little or no additional investment
required to maintain generation capacity. Solar Quatifying Facilities (,,eFs,) have
provided manufacturerwarranty information that extends beyond the current term of
solar projects under contract with ldaho Porer. On the other hand, none of the wind
QFs under contract with ldaho Power have discussed repowering their facilities or have
provided any data or information that verifies the QF's intent to repower and continue
operating their projects beyond the economic life of their current contracts and useful
life of their wind generation facilities. ln fact, one of the ea1iest and largest wind eFs
selling its output to ldaho Power under a PURPA Energy Sales Agreement (,,ESA',) has
provided the Company with a copy of the QF's decommissioning plan and associated
cost estimate for the retirement of project facilities at the end of its useful !ife.
Therefore, the Company cannot accurately predict whether wind generators will choose
to invest in repowering and seek a replacement ESA when the current contract expires,
Another fuctor affecting the likelihood of wind QF repowering is the phase out of
federal production tax credits ('PTc) that have been a major driver of wind
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTIONREQUEST OF THE COMMISSION STAFF TO IDAHO POVI/ER COMPANY - 40
development and repowering of wind facilities in the U.S., including PURPA wind
projects. The latest extension of the PTC in 2015 provided 10 years of tax credits at
$23lM\ Jh for new projects and turbine upgrades that were started in 2016. The PTC
was scaled down by 20 percent annually from that time forward, but in 2019 the PTC
was extended through2O2O at $15/triWtr. The first PURPA energy sales agreement
scheduled to expire with a wind Qualifling Facility ('QF') under contract with ldaho
power will occur inZO25 and it is unknown what tax incentives will be available to wind
QFs at thattime.
Other factors that may influence a decision of a QF on whether to repower a
project includes unknoam future PURPA avoided cost prices, integration @sts, contract
provisions, etc.
The response to this Request is sponsored by Michael Danington, Energy
Contracts Leader, ldaho Power Company.
IDAHO POVVER COMPANY'S RESPONSE TO THE THIRD PRODUCT]ON
REQUEST OF THE COMMTSSION STAFF TO IDAHO POWER COMPANY.4l
REQUEST NO. 86: On page 28 of 2019 IRP Review Report (Forecast
Generation), the Company discusses PURPA lnputs in AURORA and states that
"average estimated generation is allocated to Heavy Load at 56 percent, unless it is
determined a different proportion should be used. Average estimated generation for
solar has been calculated to be 84 per@nt."
a. Please describe "average estimated generation" and explain how it is
determined. ln the explanation, please include: The source of the data used,
if it is based on historic data, and if it is calculated specific to each month or
as an annual average.
b. Please explain how the 56 percent is determined.
c. Please explain how the 84 percent is determined.
d. Please list and explain all purposes making it necessary to allocate estimated
generation to Heavy Load hours and Light Load hours in Ute modeling
prooess. ls one purpose to determine a QF's generation amount at the hourly
level?
e. Please explain how the QFs' generation amounts are used in the dispatch
prooess. Does AURORA subtract the hourly generation amount of QFs from
the load first, due to must-purchase provisions, and then dispatch other
resources to meet the remaining load?
RESPONSE TO REQUEST NO. 86:
a. ldaho Power's Cogeneration and Small Porer Production ('CSPP") forecast
pro@ss, which includes all Qualifying Facilities ("QFs") under eontract, is
developed for each QF based on a number of factors including: contract
]DAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMTSSION STAFF TO IDAHO POWER COMPAI{Y - 42
estimated generation amounts, most recent 12-month history, 5-year rolling
average, project adiusted estimated net energy amounts, and any previous or
current adjustments. Generally, the starting point is the rolling S-year
historical average of monthly generation (or shorter if the facility has operated
less than five years). lf a QF has operated less than one year, the generation
estimates from the QF's Energy Sales Agreement ('ESA') are used. The
forecasted generation is adjusted as neoessary due to infonnation known to
ldaho Power or changes in adjusted monthly net energy amounts provided by
the QFs. The goal is to create the most accurate estimate possible of the
forecast monthly energy deliveries from each QF.
b. The 56 percent factor is an approximate allocation of generation received
from a QF during Heavy Load hours as defined in the PURPA ESA and is
used as a component to calculate a forecast estimate of costs associated with
each contract, except for those applied to solar QFs. The 56 percent
allocation is determined by allocating the number of Heavy Load hours across
8,760 hours on an annual basis and applied to monthly estimated QF
generation.
c. 84 percent is an approximate allocation of generation received from a solar
QF during Heavy Load hours as defined in the PURPA ESA and is used as a
component to catculate a forecast estimate of costs associated with each
solar QF under contract. Because solar QFs only generate during daylight
hours, most solar generation occurs during Heavy Load hours except for
generation on Sundays and holidays. The 84 percent is determined by
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVVER COMPANY .43
allocating all solar generation received to Heavy Load hours across g,760
hourc, except for Sundays and holidays, on an annual basis and applied to
monthly estimated eF generation.
d. The only puPose for allocation of Heavy Load and Light Load perentages as
used in the CSPP forecast prooess is for estimating contract costs as differing
contract rates are paid during Heavy Load and Light Load hours.
e. The forecast of QF generation is applied to the Aurora modeling as a must-
run resource. The must-run resour@s are dispatched first to serve load, with
remaining resour@s and additional market purchases serving the remaining
load.
The response to this Request is sponsored by Jared Hansen, Resource planning
Leader, ldaho Power Company.
IDAHO POWER COMPANYS RESPONSE TO THE THIRD PRODUCTIONREQUEST OF THE COMMTSSION STAFF TO IDAHO POTA'ERbOMPANY -44
REQUEST NO. 87: On page 50 of the 2019 IRP Review Report (Long Term
Gapacity Expansion Results), the company states that 'equal or fewer natural gas
resources were selected by the model in the planning gas soenario than the resource
stacks built under high-gas conditions when comparing the same carbon conditions'"
Does the company mean "more" natural gas resources, instead of "fewe/'? Please
explain.
RESPONSE TO REQUEST NO. 87: The company inadvertently used the word
'Tewer'and the correct wording in that section should be "more,"
The excerpt on page S0 of the 2019 IRP Review Report should be corrected as
follows: ,ln these figures, the first four (left-most) resource stacks shown were
developed under a planning natural gas scenario. The next four were developed with
the mid-natural gas forecast. And the last four (right-most) resource stacks were
developed under a high-cost natural gas forecast. ln both figures, equal or f€lrer more
natural gas resouroes were selected by the model in the planning gas scenarios than
the resource stiacks built under highgas c-onditions when comparing the same carbon
conditions
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power ComPanY'
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 45
REQUEST N9. 88: On page 61 of 2019 IRP Review Report (Reserve Shortfatt),
in lts discussion of the reserue shortfall for P16(4), the preferred portfolio identified in
the Filst Amended 2019 lRP, the Company states, "There was a projected reserve
shortfa!! of just 54 M\ /h out of 119,000,000 M\ /h of total load.,,
a. Please explain why a reserve shortfall exists, Does the Company's
implementation of AURORA relax reserye requirements to achieve a
solution? ls there a hierarchy between least cost and reliability in reaching its
optimization results?
b. Please report the total load in Mt /h identified in the Second Amended 2019
IRP.
c. Please report the amount of reserve shortfall in MWh for the preferred
portfolio PGPC B2H(1) identifted in the second Amended 2019 tRp.
d. Please discuss whether the reserve shortfall provided above is acceptable
and why.
e. Generally, how many loss of load hours per year due to regulation reserve
shortfall is appropriate for planning purposes? Does the reserve shortfall
provided above meet this standard?
REgPOtrl$E TO REQUEST NO. 88:
a. The AURORA model has an hourly demand requirement, as wellas optional
constraints. One of the optional constraints is ancillary services, which the
Company defines as regulation services. The regulation services are input
into Aurora and designated to be served by a serect set of company
resources. The model's primary objective is to meet the hourly demand
IDAHO POI/VER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 46
requirement. lf a secondary constraint cannot be met, the model will relax an
optional constraint in order to meet its primary obligation (to meet the hourly
demand). The 54 MWh of reserve shortfalls were the result of the model
relaxing a secondary restraint in order to meet the hourly demand
requirement over the course of the ldaho Powe/s action plan window (2020-
2026't. The Total RegUp requirement over the seven-year action plan window
was 19,317,307 MVVh, with 19,317,253 M\Mt being served within the mdel,
creating a 34 M\Mt deficiency, which is 0.0003 percent. The Company uses
the regulation requirements to ensure that portfolios are reliable, with the
understanding that differences do exist between the modeling and actual
operations of regulation requirements. One primary difference is that market
purchases can free up Company-owned resources to provide regulation
requirements during acilual operations, which is not possible during the
modeling process. Based on 0.0003 percent of the total RegUp requirements
not being met within the model, the Company feels the portfolio is reliable and
can meet regulation requirements based on differences like the one
mentioned above.
b. The total demand requirement for lhe2020-2026 timeframe in the Second
Amended 2019 IRP is 117,967,011 Ml Jh.
c. There were no reserve shortfalls for the preferred portfolio PGPC B2H(1)
identified in the Second Amended 2019 lRP.
d. Please refer to the response in part a.
e. The loss of load hours quantification and the regulation shortfall quantification
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVVER COMPANY.4T
are two distinct evaluations that assume different criteria, (e.g., extreme
conditions versus planning conditions). As described previously, the reserve
shortfall is acceptable and the loss of load standard of one day in ten years is
also acceptable, which is described in more detailon page 61 of the lRp
Review Report.
The response to this Request is sponsored by Jared Hansen, Resource ptanning
Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTIONREQUEST OF THE COMMISSION STAFF TO IDAHO POV\GR COMPANY - 48
REOUEST NO. 89: Page 67 of 2019 IRP Review Report Process and Findings
states that'Energy Exemplar, the developers of AURORA, regularly releases updated
versions of the softrare. One of the latest updates enables co-optimization of results,
which would allow co-optimization of the portfolio specific to ldaho Power and the
WECC. This development could greatly increase the efficiency of the IRP pro@ss."
Does the Gompany plan to co-optimize portfolios for ldaho Power's system and for the
WECC in the future? lf so, please explain why the Company seeks to co-optimize,
rather than optimize for ldaho Powe/s system alone.
RESPONSE TO REQUEST NO. 89: As discussed in the company's response
to Staff Request No. 60, the Company is still evaluating the capabilities of the newest
AURORA software release. According to Energy Exemplar and based on current
testing, the newest version of the AURORA Long-Term Capacity Expansion softrryare is
capable of simultaneously modeling the \AIECC and ldaho Power, with the concurrent
goal of meeting the planning margin for all entities within the WECC' The planning
margin is still the main driver for new resource builds and retirements, with no priority
given to a specific area within the model,
As discovered in the 2019 lRP, optimizing for the WECC does not necessarily
result in least-cost portfolios for Idaho Poweds customers. lt is anticipated that allowing
the model to solve for ldaho Power's system and the rest of the I/VECC simultaneously
will result in accurate market conditions and matching least-cost resource portfolios for
ldaho Power's system.
For the reasons explained above, the Company is currently evaluating this
modeling approach for the 2021 lRP.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -49
The response to this Request is sponsored by Jared Hanson, Resoure planning
Leader, ldaho Power Company.
IDAHO POVVER COMPANYS RESPONSE TO THE THIRD PRODUCTIONREQUEST OF THE COMMISSION STAFF TO IDAHO POVVER COMPANY. 50
REOUEST NO. 90: Table 8.5 on page 119 of the Second Amended 2019 IRP
shows how the new portfolios are created in the second arnended lRP. For example,
portfotio PGPC combines the original P(13) and P(14), and Portfolio PGPC B2H
combines the original P(1) and P(2). Please provide and explain the individual steps
used to determine how the new portfolios were created.
RESPONSE TO REQUEST NO. 90: Portfolio PGPC combines the original
WECC optimized portfolios from P(1) and P(2), while Portfolio PGPC B2H combines the
original WECC optimized portfolios from P(13) and P(14). The rationale for using these
groups of lA1ECQ-optimized portfolios as strarting points for the manual optimization
prooess is described in the Manuallv Buitt Portfotios section of Chapter 8 in the Second
Amended 2O1g lRP. Combining the WECC-optimized portfolios was done by
maintiaining similar resouroe selections and timing to the portfolios shown in Table 8.5.
Once the six starting points were identified, four scenarios were developed for
each starting point, resulting in the creation ol24 portfolios. Three scenarios optimized
each starting point with specific Jim Bridger exit scenarios, as shown in Table 9.4 using
the guiding principles that follow the table. Scenario 4 leveraged the results of the first 3
scenarios to select optimal Jim Bridger unit exit timing and then attempted to further
optimize the results. The guiding principles used for Scenario 4 are described in the
same section.
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power ComPanY.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POVVER COMPANY - 51
REQUEST NO. 9{: Page 27 of Appendix C lists resource additions and
removals from the prefened portfolio for PURPA reference pumoses. please explain
the purpose of this table and provide an example of how it is intended to be used.
RESPONSE TO REQUEST NO. 91: The pupose of the tabte on page 27 is to
provide frle reader with an underctanding of the difference between the installed
capacity and peak hour capaci$ of the resources added and removed in the
determination of the first capacity deficit. For some resour@s, such as solar and wind,
the peak hour capacity varies significanfly fiom installed capacity.
The response to this Request is sponsored by Jared Hansen, Resource planning
Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTTON
REQUEST OF THE COMMISSION STAFF TO IDAHO POVT'ER COMPANY. 52
REQUEST NO. 92: Please provide the workpapers used to determine the
deficiency period start date of July 2029 and the 42 MW deficit as shown on page 28 of
Appendix C.
RFSPON$E Tp BFOITEST llo, 9?: The spreadsheet used to determine the
deficiency period start date is provided in the Excel file accompanying this response
(see ce1 DY46). The initial calculation of the deficiency period did not consider the
transmission capacity adjustments modeled in the Second Amended IRP' The updated
deficiency period start date is August 2029 with a deficit amount of 5 MW.
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, ldaho Power ComPanY.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO ]DAHO POWER COMPANY - 53
REQUEST NO. 93: Please describe the QF historic generation data used for
determining the QF contribution of capacity in the lRP. Specifically, what time periods
(how many years of data, which months, which hours) of historic data are used? tf the
types of data are different for different QF technologies, please explain the differences
ofeach.
: For baseload resouroes such as hydro,
biomass and cogeneration, the monthly average megawatts of the generation estimates
are used to determine each QF's contribution to capacity. For solar and wind resources
the total nameplate capacity of each resource type is multiplied by a peak hour capacity
factor to determine the contribution to peak. For example, in the 201g lntegrated
Resource Plan the total nameplate capacity of wind QFs was muttiplied by a peak hour
capacity factor of 5 percent.
Please see ldaho Powe/s response to Staff Request No. 86(a) for a description
of horr monthly forecast values for each eF are determined.
The response to this Request is sponsored by Michael Danington, Energy
Contracts Leader, ldaho Power Company.
DATED at Boise, ldaho, this lgth day of November 2020.
h!.2(^u,.^,
LISA D. NORDSTROM
Aftorney for ldaho power Company
IDAHO POYVER COMPANYS RESPONSE TO THE THTRD PRODUCTIONREQUEST OF THE COMMISSION STAFF TO IDAHO POV\,ER CbMPANY - 54
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 19th day of Novemb er 2020, I served a true and
correct copy of IDAHO POWER COMPANY'S RESPONSE TO THE THIRD
PRODUCTION NEOUCST OF THE COMMISSION STAFF TO IDAHO POWER
CoMPANY upon the following named parties by the method indicated below, and
addressed to the following:
Hand Delivered
-U.S.
Mail
Overn(1ht Mail
_FA)(X email [e-mail].9ov
Commission Staff
Edward Jewell
Deputy Attorney General
ldaho Public Utilities Gommission
11331 W. Chinden Blvd., Bldg. No' 8,
Suite 201-A(83714)
PO Box 83720
Boise, lD 83720-0074
ldaHydro
C. Tom Arkoosh
ARKOOSH I.AW OFFICES
802 W. Bannock Street, Suite LP 103
P.O. Box 2900
Boise, ID 83701
ldaho Conservation League
Benjamin J. Otto
ldaho Conservation League
710 N. 6th Street
Boise, lD 83702
STOP B2H Coalition
Jack Van Valkenburgh
Van Valkenburg Law, PLLC
P.O. Box 531
Boise, lD 83701
Jim Kreider
STOP B2H Coalition
60366 Marvin Road
La Grande, OR 97850
Hand Delivered
-U.S.
Mail
-Overnight
Mail
_FAX
-L Email [e-mail]
slacie.ioor@arkoosh. com
erin. [e-mail]
-Hand
Delivered
-U.S.
Mail
Overnight Mail
_FN(X Email botto@ldahoconservatlon'org
-Hand
Delivercd
-U.S.
Mail
-Overnight
Mail
_FN(
X - Email iack@vanvalkenburohlaw'com
-Hand
Delivered
-U.S.
Mail
-Ovemight
Mail
_FN(X Email [e-mail]
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
NEOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY'55
ldaho Sierra Club
Julian Aris, Associate Attorney
Gloria D. Smith
Sierra Club
2101 Webster Street, Suite 1300
Oakland, CA 94612
-Hand
Delivered
_U.S. Mail
_Overnight Mail_FA)(X Email iu [e-mail]$
[e-mail] :
an a. bordttDsbr raclub. oro
lndustrial Gustomers of ldaho Power
Peter J. Richardson
RICHARDSON ADAMS, PLLC
515 N. 27h Street
P.O. Box 7218
Boise, lD 83702
_Hand Delivered
_U.S. Mail
Overnight Mail_Fru(X Email peter@/rhardsonadamr.conr
Dr. Don Reading
6070 Hill Road
Boise, lD 83703
_Hand Delivered
_U.S. Mail
_Ovemight Mail_Fru(X Email dreFglQg!@mindsorinq,corn
Micron Technology, lnc.
Austin Rueschhoff
Thorvald A. Nelson
Holland & Hart, LLP
555 17th Street, Suite 3200
Denver, CO 80202
Hand Delivered
U.S. Mail
Overnight Mail_ FN(X Email
Jim Swier
Micron Technology, lnc.
8000 South FederalWay
Boise, lD 83707
Hand Delivered
U.S. Mail
Ovemight Mai!_ FA)(X Email [e-mail]
Stephanie L. Buckner
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 56
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE No. IPG-E-19-{9
IDAHO POWER COMPANY
ATTACHMENT TO REQUEST NO.69
TO
IDAHO POWER GOMPANY'S RESPONSE TO THE
THIRD PRODUGTION REQUEST OF THE COMMISSION
STAFF
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. IPC-E-19-19
IDAHO POWER COMPANY
ATTACHMENT TO REQUEST NO. 79
TO
IDAHO POWER COMPANY'S RESPONSE TO THE
THIRD PRODUGTION REQUEST OF THE COMMISSION
STAFF
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. IPG-E-19-19
IDAHO POWER COMPANY
ATTACHMENT TO REQUEST NO. 81
TO
IDAHO POWER COIUIPANY'S RESPONSE TO THE
THIRD PRODUCTION REQUEST OF THE COMMISSION
STAFF
Bennett Mountaln
I
Time Stamp Total MW (Mwl
04-Aug-15 10:53:00 0.0
04-Aue-16 10:54:00 7.4
04-Aug-15 10:55:00 14.3
10:56:00 21.3
04-Aug-15 10:57:00 28.3
04-Aug-15 10:58:00 35.7
- 04-Aug-L610:59:00 42.6
O4-Aug-16 11:00:00 49.7
04-Aug-16 11:01:00 s5.0
04-Aug-15 11:02:00 63.3
0rt-Aug-15 11:03:00 70.4
04-Aug-16 11:04:fi)77.3
04-Aug-15 11:05:@ 84.1
04-Aug-15 11:05:@ 91.0
04-Aug-15 11:07:00 98.9
O4-Aue-16 11:08:00 104.9
04-Aug-15 11:09:00 7L2.3
04-Aug-15 11:10:00 LLg.2
O4-Aug-16 11:11:00 126.3
04-Aug-15 11:12:00 133.3
04-Aug-15 11:13:00 140.3
O1-AuS-15 11:14:00 147.4
(M-Aug-16 11:15:00 154.5
O4-Aug-15 11:16:00 161.3
04-Aug-15 11:17:00 167.8
04-Aug-15 11:18:00 t72.7
Danskln Unit 1
Nameplate Gpacity (MWl 779.7
Time Stamp Total MW Output (MWl
22-Oct-2O 18:35:00 0.0
22-Oc.-2018:37:00 2.5
22-Oct-2O 18:38:00 4.4
22-Oct-2018:39:00 6.4
22-Oc.-2O 18:40:fr)L2.8
22-Ocr-2018:41:00 20.5
22-Oct-2O 18:42:00 26.3
22-Act-2O 18:43:00 33.8
22-Oc.-2018:44:00 40.6
22-Oct-2O 18:45:00 47.t
22-OcE-2018:46:00 54.8
22-Oc.-2O 18:47:00 51.5
22-Oct-2018;48:00 69.1
22-Oct-2O 18:49:00 75.8
22-Oct-2O 18:50:00 82.6
22-Oct-2018:51:00 90.1
22-Oct-2018:52:00 95.8
22-Oct-2018:53;00 103,6
22-Ocl-2O 18:54:00 111.1
22-Ocr-2O 18:55:fl)tL7.8
22-Oct-2O 18:56:fi)L24.5
22-Oct-2O 18:57:00 t32.1
22-Oc.-2A 18:58r00 138.8
22-Od-2018:59;00 145.5
22-Oct-2019:00:00 L52.2
22-Oct-2O 19:01:00 158.2
22-Oct-2019:02:00 159.0
22-Oct-2O 19:03:00 158.1
22-Oct-2019:04:00 155.0
22-Oct-2O 19:05:00 155.0
22-Oct-2019:06:00 156.0
22-Ac"-2O 19:07:00 156.0
22-Oct-2O 19108:00 156.0
22-Oc.-2O 19:09:00 156.0
22-Oct-2019:10:00 155.0
22-Oct-2019:11:00 155.0
22-Ac.-2A 19:12:00 155.0
22-Oct-20 19:13:fi)156.0
22-Oct-2019:14:00 156.0
22-Oct-2019:15:00 155.0
22-Oct-2O 19:16:00 156.0
22-Oct-2O 19:17:00 155.0
22-Ocr-2019:18:00 153,1
22-Od-2A 19:19:00 159.8
22-Oc.-2O 19:20:fl)175.0
22-Oct-2O 19:21:00 175.0
Unlt 2
45.9
Date Start Tlme in Minutes Total MW (Mwl
26-Oct-20 01:32:00 0.0
26-Oct-20 01:33:fi)0.9
26-Oct-20 01:34:00 1.8
26-0ct-20 01:35:fi)2.8
26-Oct-2O 01:36:00 3.7
-2OOt:!7 4.4
25-Oct-20 01:38:00 7.0
25-Oct-20 01 9.7
26-Oct-20 01:40:00 t2.o
26-Oct-20 01:41;00 14.3
26-Oct-2O 01:42:00 16.5
26-Oct-20 01:43 L9.2
01 27.7
26-Od-20 0t:45:00 23.8
26-Oct-20 01:46:00 25.9
26-Oct-20 01:47:00 28.4
25-Oct-20 01:48:00 30.8
26-Oct-20 01:49:00 33.s
26-Oct-20 01:50:00 36.0
26-Oct-20 01:51 38.4
26{ct-20 01:5 40.9
26-Oct-20 01:53:00 43.4
26-Oct-20 01:54:00 45,9
Danskln Unit 3
Nameplate CaPacitY (MW)-45.9
Date Start Tinre ln Minutes Total MW Output
25-Oct-20 00:55:@ 0.0
26-Oct-20 00:56:00 0.4
26-Oct-20 00:57:fi)1.8
26-Oct-20 00:58:00 3.4
26-Oct-20 00:59:00 6.1
25-Oct-20 01:00:00 8.5
26-Oct-20 01:01:00 11.0
26-Oct-20 01:02:00 L3.4
25-Oct-20 01:03:00 1s.0
25-Oct-20 01:04:00 18.0
26-Od-2O 01:05:00 20.9
26-Oct-20 01:05:00 23.2
26-Oct-20 01:07:00 2s.2
26{cl-20 01:08:00 28.2
26-Oct-20 01:09:00 3A.7
26-Oct-20 01:10:00 33.0
26-Oct-20 01:11:00 35.s
26-Oct-20 01:12:@ 38.0
25-Oct-20 01:13:00 40.5
26€ct-20 01:14:00 43.0
26-Oct-20 01:15:00 45.4
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-19-19
IDAHO POWER COTVIPANY
ATTACHMENT TO REQUEST NO. 92
(EXCEL SPREADSHEET ATTACHED TO EMAILI
TO
IDAHO POWER COMPANY'S RESPONSE TO THE
THIRD PRODUGTION REQUEST OF THE COMMISS]ON
STAFF