20200608Stop B2H 1-30 to IPC.pdf

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Jack Van Valkenburgh ISB # 3818
916g Van Valkenburgh Law, PLLC
P.O. Box 531
Boise,lD,83701
(208) 918-1ee4
iack@vanvalkenburgh law.com
June 7, 2020
ldaho Public Utilities Commission
11331 W. Chlnden Boulevard
Building 8, Suite 201-A
Boise, ldaho 837t4
[e-mail]
secretarv@ puc.idaho.gov
VIA ELECTRONIC FILING
Re: Case No. IPC-E-19-19
2019 lntegrated Resource Plan - STOP B2H Coalitions First Production Request to ldaho
Power
Dear Ms. Hanian
We inadvertently sent out a scanned in version of STOPS first production request where the
links to external documents and audio files are not hot. The attached version has active links
which should enhance the readers' experience.
This document contains the production request and all supporting documents. Please delete
my recent email and all supporting documents.
Thank you
Respectfully,
Jack Van Valkenburgh
Jack Van Valkenburgh ISB # 3818
Van Valkenburgh Law, PLLC
P.O. Box 531
Boise,lD,83701
(208) e18-19e4
iack@vanvalken bu rghlaw.com
Jack Van Valkenburgh, Attorney for the STOP 82H Coalition
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. TPC-E-19-19
IN THE MATTER OF IDAHO POWER COMPANY'S
2O!9 INTEGRATED RESOURCE PLAN
FIRST PRODUCNON REQUEST OF
THE STOP B2H COALITION
TO THE IDAHO POWER COMPANY
Pursuant to Rule 225 of the Rules of Procedure of the ldaho Public Utilities Commission (the "Commission"), the STOP
B2H Coalition by and through their attorney of record, Jack Van Valkenburgh, hereby requests that ldaho Power
Company ("ldaho Power" or the "Company") provide the following documents.
This production request is to be considered as continuing, and the Company is requested to provide by way of
supplemental responses additional documents that it or any person acting on its behalf may later obtain that will
augment the documents produced.
For each item, please indicate the name of the person(s) preparing the answer(s), along with the job title of such
person(s).
It should be noted that the STOP B2H Coalition is participating as interveners in the Oregon dockets for PacifiCoro-LC 70,
ldaho Power LC 74 and this docket IPC-E-19-19. Several of our questions reference activities in these dockets and we cite
these activities with supporting documents to the best of our abilities. We believe activities in these other dockets will
inform this docket since PacifiCorp and ldaho Power are partners in many activities. ldaho Power is the junior
partner/owner in many of the acquisitions and retirements and the implications of these relationships is important to
understand especially in light of the Bridger retirement dates and B2H.
STOP REQUEST NO. 1
On Page 85 of the Amended lRP, ldaho Power states the following:
"The Jim Bridger units provide system reliability benefits, particularly related to the company's flexible ramping
capacity needs for EIM participation and reliable system operations. The need for flexible ramping is simulated
in the AURORA modeling as previously described. However, the AURORA modeling indicates removal of Jim
Bridger units needs to be carefully evaluated because of potential heightened concerns about meeting
regulating reserve requirements following their removal."
Please describe what ldaho Powe/s AURORA modeling reveals that indicates "potential heightened concerns about
meeting regulating reserve requirements following their removal". Please explain why ldaho Power was unable to
carefully evaluate the regulating reserve requirements associated with retirement of Jim Bridger units in the 2019 IRP
using AURORA's ability to simulate the need for flexible ramping.
STOP REQUEST NO. 2
At the December 2018 IRPAC meeting, ldaho Power explained that it refined the representation of ldaho loads and
resources in the AURORA model by assigning ldaho Power Company loads into Area 6L2lPC (ldaho Power Company) in
AURORA and assigning the ldaho loads of Bonneville Power and PacifiCorp into a separate Area 515 identified as lDSo
(ldaho South). ldaho Power further showed that ldaho's peak hour in AURORA in 2019 reflected peak loads in Area 512
IPC of approximately 3,200 MW and peak hour loads in Area 515 lDSo of approximately 550 MW. (The December 2018
presentation is available at this link:
https://docs.ida hopower.com/odfs/AboutUs/PlannineForFutu relirol20L8/lRPACDec20L8.pdf
Further, in response to OPUC Staff DR 54 (OPUC Staff DR 54 with supporting files attached), ldaho Power explained that
it assigned 3,480 MW of existing generating resources to Area 512 and assigned 780 MW of existing generating
resources to Area 515 resulting in the following Area Load/Resource balance in Aurora. (Note that no existing coal
resources were assigned to Area 615 so area 515 will not be directly affected by the retirement of any existing coal
plants.)
The following table displays the Load/Resource balance established by ldaho Power in the Aurora model for Areas 512
(ldaho Power) and 515 (BPA and PacifiCorp).
Area 512lPC Area 615lPC
Peak Hour Load 3,197 MW 554 MW
Area Resources (includes
Jackpot Solar)
3,480 MW 780 MW
Area Resources without Valmy
and Boardman (-319 MW)
3,151MW 780 MW
Surplus Capacity at Peak after
retirement of Valmy and
Boardman
.36 MW
Reserve Margin = 0
225 MW
Reserve Margin = 4t%
It can be seen from the Table that Area 615 has a significant reserve margin suggesting that Area 615 will not need new
resources for many years, yet ldaho Powe/s response to oPUc staff DR 52 (tab R16 RMT) (OPUC Staff DR 52 with
supporting files attached), shows that under ldaho Powe/s preferred Portfolio P15, a 429 MW combined cvcle sas olant
is built in Southern ldaho Area 615 in 2023.
WECC ldahoSouth 615
New Resource 3723 from
2584 CCCI gasloilAdv na 429 NGllDSo tl1l2023 Lzl3t/2039
Please explain why ldaho Powe/s preferred Portfolio includes the addition of a new 429 MW combined cycle gas
plant in Southern ldaho, in 2023. On what utilitt's behalf is this resource added by AURORA. Please also explain the
effect that this thermal resource addition in ldaho in 2023 has on ldaho Powe/s determination that its period of
sufficiency extends through 2025.
STOP REQUEST NO. 3
Please reference the tab titled "AURORA Resources Table" in ldaho Powe/s response to OPUC Staff DR No. 54.
STOP reviewed the resources assigned to ldaho Power Area 512 and observed that Area 612 does not include any of
ldaho Powe/s existing PURPA resources. STOP observes that ldaho Power has instead established a third "Area" in
ldaho labeled Area 513 and it appears to STOP that ldaho Power has assigned all of ldaho Powe/s existing PURPA
resources into Area 613 and assigned a zero capacity to g!! these PURPA resources. STOP interprets this to mean that
ldaho Power has effectively removed its existing PURPA resources from the AURORA resource data base.
STOP B2H Coalition Production Requests 1- 30 in IPC-E-19-19 Page 1 of 14
Proiect MW On-line Date End Date
-
I I
-
I I
-
I IIIII
E E
What follows is sampling from EXISTING RESOURCE DATA Qualifying Facility Data (PURPA)
Cogeneration and Small Power Production Projects Status as of December 31, 2019
from 2019 Amended lntegrated Resource Plan, Appendix C p 29-31 as compared to resources in Staff DR No. 54 Zone
513
ion and Small Power Production Status as of December 3 2019
Staff DR No. 54 - Aurora Resources Table tab
Name Utility Capacity Fuel Area
r
I ImIHffi
STOP observes that removing all existing PURPA Variable Energy Resources (VER) (wind and solar) and small hydro
resources from the ldaho Power system in AURORA by assigning them zero capacity value would significantly reduce the
amount of reg up and reg down required to be held as balancing reserves by ldaho Power in the AURORA model.
Please explain why ldaho Power has removed all its existing PURPA resources from Area 612{daho Power and
reassigned them to Area 513, and then zeroed out all PURPA resource capacity and energy in the AURORA model Area
613.
Please explain how this effective removal of all existing ldaho Power PURPA resources from the AURORA model
affects the ability of AURORA to accurately model the adequacy of ldaho Powe/s flexible capacity reserves. ln
particular, explain how AURORA can realistically ensure ldaho Powey's existing flexible capacity resources are
providing adequate balancing reserves (i.e., reg up and reg downl when Jackpot Solar is added in2022 and Jim
Bridger 1 ls retired in2022, if the model cannot see any of ldaho Powey's existing PURPA resources and their
associated demands for flexibility resen es.
Finally, please explain the effect of the above removal of ldaho Powe/s PURPA resources from the Aurora model on
the determination of ldaho Powe/s period of sufficiency.
STOP B2H Coalitlon Production Requests 1- 30 in IPC-E-1919 Page 2 of 14
lf tdaho Power denies that it has excluded ldaho Powe/s existing PURPA resources in the Portfolio modeling in the
AURORA model, please provide a table showing the hourly generation for each PURPA resource in Portfolio's P14 P16
and P16-4, as dispatched in the Aurora Model for each hour in July over the 20 year planning period.
STOP REQUEST NO.4
On page 22 of the Amended 2019 lRP, ldaho Power discusses the 2018 Variable Energy Resource (VER) Study conducted
by ldaho Power available at this link.
https://apps. puc.state.or.us/edockets/edocs.asp?FileTvpe=HAD&FileName=um 1793 had16910. pdf&DocketlD=20334&n
umSequence=42
ldaho Power states in the Amended 2019 lRP that:
"The 2018 VER Study also identified that, based on the current resources on ldaho Powe/s system, 173
MW of additional VERs could be integrated before reserve margin violations exceed 10 percent of the
operating hours during the year."
At the time the 2018 VER Study was conducted, ldaho Power stated that it had 1,016 MW of VER resources on the ldaho
Power system and estimated the maximum amount of additional VER that could be added without exhausting ldaho
Powe/s existing regulating reserves was 173 MW; a total of 1,190 MW.
"The 173 MW of additionalVER results in approximately 1,190 MW of total nameplate VER (727 MW
wind + 289 MW solar + 173 MW additional VER = approximately 1,190 MW of total VER) on a system
with a 3,400 MW peak and average sales of 1,755 MW. Expansion beyond this level carries concerns
that significant reliability issues will be encountered associated with the system's inability to provide
sufficient regulating reserves." P 35.
The VER Study further suggested that a strong case could be made that no additional VER resources should be put on
the system:
"However, as described in the 2017 Operational lssues section, the current quantity of variable
resources on ldaho Powe/s system periodically exhausts the operating reserves available. The modeling
results and number of actual wind curtailments during 2017 suggest a strong case could be made that
no additionalVER resources should be put on the system to avoid periodic reserve deficiencies." P 36
According to the Amended 2019 lRP, VER resources on the ldaho Power system now total 1044 MW, an increase of 24
MW since the 2018 Study was completed. The addition of the 120 MW Jackpot Solar in 2022will increase this total to
L,L64,just shy of the maximum amount that could be added without creating "significant reliability issues", according to
the 2018 Study. At the same time, ldaho Power is on the verge of losing existing regulating reserves due to the
impending retirement of Boardman and Valmy, flexible resources that were available for balancing in the 2017
operational study but are retired in the first two years of all Portfolios in the 2019 lRP.
On top of these increases in VER resources and loss of flexible capacity resources (Boardman and Valmy), the 2019
Amended IRP Preferred Portfolio proposes the early retirement of 177 MW of Bridger capacity, which would further
reduce the balancing reserves available to ldaho Power. ln summary despite an 148 MW increase of VER resources
since the 2018 Study, and the loss of regulating reserves associated with the retirements of Boardman, Valmy and the
further retirement of a Bridger unit in 2022,ldaho Power claims in the 2019 IRP that it has sufficient regulating reserves
and no new flexibility resources are needed under the preferred Portfolio, even with the retirement of a Bridger unit in
2022.
STOP BzH Coalition Production Requests 1- 30 in lPc-E-19-19 Page 3 of 14
"The results of the 2019 IRP portfolio development show that additionalVERs are selected in a majority
of LTCE portfolios, and many of the portfolios show new solar resources selected and coalunits being
retired. This indicates the model has sufficient regulating reserves to economically retire a reserve-
contributing coal unit while adding new solar resources." (Amended IRP Paee 23)
Please explain this conflict/disconnect betureen the AURORA modeling results showing that the ldaho Power system
has plenty of existing flexible capacity resources to integrate Jackpot Solar and retire a Bridger unit, and the detaited
ana!6ic results presented in the 2018 VER Study showing that ldaho Power is close to exhausting its flexible capacity
reserve margin today, even without the addition of new VER resources or coal plant retirements (i.e., Valmy,
Boardman and Bridger).
STOP REQUEST NO. 5
Referencing page 11 of the Reply Comments of ldaho Power (see STOP Request No. 5 support file - attached), E.
Emergency Transmission Capacity Does Not Offset the Need for B2H, please explain how ldaho Power defines the term
"Emergency Transmission".
STOP REQUEST NO.6
Please provide a copy (listing) of ldaho Powe/s Designated Network Resources, as currentty posted on ldaho Powerrs
Open Access Same Time tnformation System (OASlSl.
STOP REQUEST NO. 7
Refer to the FERC Audit Report dated June LL,2OL8, "Audit of ldoho Power Company's Open Access Some-Time
lnformotion Systems, Business Proctice Stondords ond Communicotion Protocols for Pubtic utilities, Tronsporency Rule,
ond lnformotion Posting Requirements Contoined Within ldoho Power's Open Access Tronsmission Toriff'-(FERC Docket
No. PA17-7-000) available on the FERC website at
https ://elibra rv.ferc.eov/id mws/com mon/Open Nat.aso?filel D=14943440 .
Pertaining to CBM, FERC noted the following Pertinent Guidance p 38
Pertinent Guidance
o 78 C.F.R. I 37.6(b)(3)(iii)(A) stotes:
The Tronsmission Provider must reevoluote its CBM needs ot leost every year.
. 78 C.F.R. I 37.6(b)(3)(iii)(B) stotes:
The Tronsmission Provider must post its proctices for reevoluoting its CBM needs.
o 78 C.F.R. 5 37.7(b) stotes, in port:
The oudit doto ore to be retoined ond mode ovoiloble upon request for downlood lor five yeors from the date
when they ore first posted in the some electronic form as used when they originolly were posted on the OAS|S.
The audit found that ldaho Power was not in compliance with the above
"ldaho Power's data responses demonstrated that it established its current CBM value (330 MW) in
2015 and had not changed in the last three years. ldaho Power admitted that it does not have the
documentation for reevaluating its CBM needs as an internal documented procedure to inform its
practices, nor does it post such information on its OASIS. This does not comply with the requirement
described under 18 C.F.R. 5 37.6(bX3Xiii)(B), which requires a transmission provider like tdaho Powerto
post its practices for reevaluating its CBM needs."
STOP B2H Coalition Production Requests 1- 30 in IPC-E-1$19 Page 4 of 14
FERC recommended that ldaho Power:
r lmplement a procedure to maintain documentation adequate to show ldaho Power reevaluated its
annual CBM needs on a going-forward basis.
o Enhance controls to ensure the planning department provides timely notification to OASIS personnel
that they reevaluated CBM needs.o Revise CBM Procedures to include a description of practices for the annual reevaluation of CBM needs
or post a separate document describing the practices for annual reevaluation of CBM needs.
The report indicated that ldaho Power accepted and implemented each of these recommendations.
Corredive AdionsTaken
As of June 2,2077,ldaho Power had developed two procedures to ensure its transmission planner and OASIS
staff coordinate with each other on evaluating and posting CBM needs. ldaho Power also developed a Capacity
Benefit Margin Procedure that summarizes its current process for establishing a CBM value. Based upon its
review of the actions undertaken by ldaho Power during the audit, audit staff determined that ldaho Power has
fully completed Recommendation L7-L9. to reevaluate its capacity benefit margin (CBM) needs at least annually,
and post its practices for reevaluating its CBM needs.
Please provide a copy of each of the two procedures referenced in the FERC Audit Report that ldaho Power developed
to ensure its transmission planner and OASIS staff coordinate with each other on evaluating and posting CBM needs.
Please provide a copy of ldaho Powe/s Capacity Benefit Margin Procedure referenced above as currently posted on
OASIS, that summarizes its current process for establishing a CBM value, and
Please provide documentation of ldaho Powe/s three most recent annual re-evaluations of CBM needs.
STOP REQUEST NO. 8
Reference Compliance with EV Guideline 1 (Amended 2019 lntegrated Resource Plan-Appendix C Page 85) reprinted
below.
Guideline 1: Forecast the Demand for Flexible Capacity
Forecast the Demand for Flexible Capacity: The electric utilities shall forecast the balancing reserves needed at
different time intervals (e.g. ramping needed within 5 minutes) to respond to variation in load and intermittent
renewable generation over the 20-year planning period;
Please provide ldaho Powe/s forecast of balancing reserves needed at different time intervals to respond to variation
in load and intermittent renewable generation over the 20-year planning period for Portfolios P4, P-15 and P-164.
STOP REQUEST NO.9
Reference Compliance with EV Guideline 2 (Amended 2019 lntegrated Resource Plan-Appendix C Page 85) reprinted
below.
Guideline 2: Forecast the Supply for Flexible Capacity
Forecast the Supply of Flexible Capacity: The electric utilities shallforecast the balancing reserves available at
different time intervals (e.g. ramping available within 5 minutes) from existing generating resources over the 20-
year planning period.
Please provide ldaho Powey's forecast of balancing reserves available from existing tenerating resources over the 20-
year planning period for Portfolios P4, P16 and P164.
STOP B2H Coalition Production Requests 1- 30 in IPC-E-19-19 Page 5 of 14
STOP REQUEST NO. 10
ln OPUC staff data request # 33 (STOP REQUEST NO. 10) staff asks about resource adequacy concerns in the Pacific
Northwest and the type of resources that the company is assuming is available to generate power and subsequently buy
at mid -c to export across B2H. The company's reply is reassuring.
However, the ldaho PUC in CASE NO. IPC-E-19-14, ln the matter of the application of ldaho power for the approval of a
power purchase agreement with Jackpot Holdings, LLC for the sale and purchase of up to 220 megawatts of renewable
solar generation, IPUC staff felt that the inclusion of Jackpot Solar was a prudent investment as the PPA rates were more
competitive over the PPA period than market purchases from the mid - c.
Please show all market research done on the cost of market purchases from the mid-c for the 20 year planning period.
!f no market research was done please show all mid - c cost data from AURORA for the 20 year planning period.
CASE NO. IPC-E-79-74, ln the motter of the opplicotion of ldoho power for the opprovol of o power
purchose ogreement with Jockpot Holdings, LLC for the sole ond purchose of up to 220 megowotts of
renewoble solor generotion, IPUC stoff stote on p 5.
To supplement the 2079 IRP onolysis, Stoff compored controct prices to expected morket prices ot Mid-C.
ld. ot 10. Stoff selected Mid-C for comporison becouse ldoho Power tronsocts most of its morket
purchoses through the Mid-C hub. ld. ot 17. Stolf found o $ll5,N0 sovings in this comporison during the
first year, $492,@O in sovings in the second yeor, ond inueosed sovings thereafter becouse the
forecosted Mid-C prices increose ot o foster rote thon the controct rate. ld. at 7O-72.
STOP REQUEST NO. 11
ln the Amended 2019 lntegrated Resource Plan-Appendix D on p 9 in the section, "Mid-C and ldaho Powe/', the
company states:
"ldaho Power customers benefit from these surplus energy sales as offsets to net power supply costs through the power
cost adjustment (PCA)."
Please provide the last 10 years of data showing how ldaho Power customers benefited ftnonciolly from these surplus
energy sales as offsets to net power supply costs through the power cost adjustment (PCAI.
Please provide the last 10 years of data for power cost adjustment (PCA) by categories and schedules. tnclude the
Base Power Cost, Projected Power Cost estimatg the true up and true up of the true up, earnings sharing by schedule,
and the power cost adjustment by schedule.
https://docs.idahopower.com/pdfs/aboutus/ratesregulatorv/tariffs/48.pdf
STOP REQUEST NO. 12
ln OPUC staff DR 33 the company provides in attachment2,"2025 Northwest Gen" which is a summary from a2025
heavy summer load Western Electricity Coordinating Council ("WECC") power flow case that lists allthe dispatchable
resources expected to be available in 2025 in the Northwest and Canada.
Please show the cost of market purchases from the mid-c for this time period. How do the market purchases from the
mid-c during this period compare to the PPA for Jackpot Solar for the same time period?
STOP REQUEST NO. 13
Based on the anticipated coal retirements in the mid -c, Table 9.10 Coal retirement forecast p L2L, how will this
STOP BzH Coalition Production Requests 1- 30 in IPC-E-1$19 Page 6 of 14
reduce the congestion on Path 14 W-E?
How many MW travel along Path 14 W-E from these units on a monthly/daily/hourly schedule for the past 10 years?
STOP REQUEST NO. 14
On pdf p 303 of the 2019 Amended lntegrated Resource Plan, "Data Point 2. Pacific Northwest Power Supply Adequacy
Assessment for 2023-Northwest Power Conservation Council Report" the company discusses the increased resource
inadequacy as expressed as a loss-of-load probability (LOLP). This LOLP will exceed and grow beyond the 5 percent
threshold for years. Under normal market conditions as supply decreases the price increases.
Please describe the analysis the company did to factor in the price increase in the mid - c due to this resource
inadequacy. Show the price increases the company input into AURORA. lf AURORA supplied the prices please show
those. tf both occurred show these too.
STOP REQUEST NO. 15
The company states, "ldaho Power assumed two 100 MW BPA long-term point-to-point reservations will not continue
starting July 2026. BPA agreed to this arrangement with ldaho Power while awaiting B2H, and the service is only
conditionally firm.
How is this annuat revenue credit loss calculated in the portfolios? What are the effects of the annual revenue credit
toss to the cost ultimately borne by customers/ratepayers per the B2H Cost Treatment in the IRP section?
STOP REQUEST NO. 16
ln OPUC staff DR 33 the company states that, "lt is worth noting that intermittent renewable resources can be
purchased as a firm product if the selling party takes steps to "firm" up the product. For example, ldaho Power had over
13,OOO MWh of frm purchases from Avangrid Renewables from 2OL7-20L9."
How many contracts of this nature has the company considered, purchased, are in negotiation to purchase, and
turned down? tf some were turned down please explain why. What is the MW value of each?
STOP REQUEST NO. 17
The 2018 Variable Energy Resource (VER) Study (2019 Amended lntegrated Resource Plan pdf p 37) used an
approximation method to convert hourly rules imposed on a one-year historical test year to monthly rules imposed on a
twenty year forecast period with changing resources.
How does the margin of error derived from a one-year historical test year to monthly rules imposed on a twenty year
forecast period with changing resources associated with tables 8.1 and 8.2 change over the 20 year period? Please
provide this data in an excelformat.
STOP REqUEST NO. 18
tn LC 70 PacifiCorp's (PAC) 2019 lRP, a 54% partner in the B2H, they are having trouble modeling the B2H topology in the
lRP. ]n that docket it appears that the topography of 82H cannot be analyzed because an additional transmission path,
Hemingway to South-Central Oregon / Northern California, is needed to link the "bubbles".
How does this topography issue and the need to analyze a Hemingway to South-Central Oregon / Northern California
transmission project impact the company? lf PAC decides to build the Hemingway to South-Central Oregon / Northern
Catifornia transmission proiect how will that impact transmission loads and revenue on the B2H? Willthe company
STOP B2H Coalition Production Requests 1- 30 in IPC-E-19-19 Page 7 of 14
be a party to the Hemingway to South-Central Oreton / Northern California transmission project? (PAC response to
OPUC staff data request 91; see also OPUC staff opening comments p 49-50; and PACs final comments p 371
STOP REQUEST NO. 19
The Amended and Restated Joint Permitting Agreement was to have ended on March L5,2O2O. However, it was
extended to July t5,2020.
Please provide the original and the 120 day extension to the Amended and Restated Joint Permitting Agreement{s}.
STOP REqUEST NO. 20
What is the amount allocated to the Amended and Restated Joint Permitting Agreement? How much has been spent
to date? How much is this under/over budget. Are ratepayers paying for any ofthese expenses currently?
STOP REQUEST NO. 21
During the company's 2OL7 IRP it stated that it will not receive special ratemaking treatment by FERC in the form of a
200 basis point incentive Return on Equity (lncentive ROE) pursuant to FERC Order No. 5791 and a FERC Order on
Petition for Declaratory Order issued by FERC on October 21,2@8.2
Please reaffirm that the company will not receive special ratemaking treatment by FERC in the form of a 200 basis
point incentive Return on Equity (lncentive ROE).
STOP REQUEST NO. 22
ln the audio for the OPUC Special Public Meetine LC 74 ldaho Power IRP Commission Workshop on 4l2tl2O the
retirements of the Bridger units were discussed. ln discussing exit strategies and alignment with PacifiCorp IRP (a0:50)
the company said that they had a framework in terms of a process that they used with the Valmy plant.
ln the companv's final comments in the Oregon docket on Valmv of the 2017 IRP on pdf p 42 the company states
lnitial discussions yielded on executed Term Sheet signed on December 29, 2077, loying out initiol provisions.T}4 tdaho
Power ond NV Energy ore now in the process of determining the fixed ond vorioble cost responsibilities ond finolizing o
Definitive Agreement providing for ldoho Power's conclusive exit from both Volmy units. ldoho Power's discussions with
low firms thot hove experience with dissolving portnerships ond power plont closures suggest thot the industry averoge is
opproximately two-yeors to reoch on ogreement between portners.
As stated above, the industry average for dissolving partnerships is approximately 2 years. The first closure for unit 1 is
slated tor 2022 in the lRP. The company is less than 2 years out from this date. There should be a draft term sheet and
Definitive Agreement.
ls there a prory built into the IRP to express these costs? lf yes please explain the development of the prory and cost
to the lRP. What is the estimated impact to rate payers. Please share all materialthe company has on the Term sheet
and the Definitive Agreement. lf a proxy is not built into the IRP to express these costs why?
' FERC Order No. 679, Promoting Transmission lnvestment through Pricing Reform, luly 20,2005. The order is available at
https://www.ferc.eovlwhats-new/comm-meet/072006/E-3. odf
'onDgn oN PETITIoN FOR DECLARATORY ORDER, October 2L,2oO8 in Docket ELO8-75-O0o The Order is available at
httos://www.ferc.sov/whats-new/comm-meet/2008/101508/E-3 1.odf
STOP B2H Coalition Production Requests 1- 30 in IPC-E-19-19 page 8 of 14
STOP REQUEST NO. 23
On the 4l2Ll2O call with the Commission there was a discussion about WECC vs the company's optimized portfolios. The
company discussed how they removed some WECC resources from of the company's portfolios because they were not
in the best interest of the company's rate payer. This pushed most renewable actualizations out to 2030. However, it
was unclear if B2H was a WECC resource or a company resource.
Please clarify if the B2H is a WECC or company resource. What resources were removed from the WECC optimized
portfolios that did not benefit the company's ratepayers. Please list the resources removed, the proposed in seruice
date, MW nameplate capacity, and capacity value.
STOP REQUEST NO.24
This is a restatement of IPUC Staff Request No 25 with different language in bold.
Please provide, in EXCEL format with formulae and links intact, the Company's estimate of the costs of B2H to ldaho
ratepayers broken down by ldaho and Oregon customer rate schedules, including, but
not limited to:
a. Rate Base Total
b. Allowance for Funds Used During Construction (AFUDC)
c. Permitting Costs and Permits Received and Filed
d. Pre-Construction Cost
e. Construction Cost
f. Unforeseen expenses
g. Expected Cost Overrun
h. Warranty Cost
STOP REQUEST NO.25
The Company states that it included costs for local interconnection upgrades totaling SZt million in its B2H cost analysis.
ln the B2H Integration Breakdown it shows overheads of LO%.
ls this 10% overhead included in the 20% contingency or is it in addition to? tf in addition to the 20% contingency
why?
Ref IPUC Staff Request No 24 - STOP DR 30
STOP REQUEST NO. 26
ln the OPUC's 2013 Plan acknowledeement in Order No. 14 253 at pdf p 6 it states, "ldaho Power does not reguest
acknowledgment of Gateway West as a supply side resource. lnstead, the company asserts that Gateway West is
reasonable to address transmission system constraints and provide for future least cost resource development.
What is the future least cost resource development the company envisioned in 2013?
STOP REQUEST NO. 27
ln response to IPUC staff request 49a the company's answer is very confusing. The question and answer are
Question: Page 28 of the Amended 2019 lntegrated Resource Plan Appendix C states the first capacity deficit is 42 MW
in July 2029, which has not changed from the first capacity deficit in the original 2019 lntegrated Resource Plan
Appendix C. Since the Company's originalfiling, severalchanges have occurred (e.g.approvalof Jackpot Solar). Please
answer the following questions:
STOP B2H Coalition Production Requests 1- 30 in IPC-E-19-19 Page 9 of 14
a. Please list any other changes that have occurred since the original IRP
was filed and that should be included in deficit calculations for the Amended 2019
lntegration Resource Plan Appendix C.
Answer:
The capacity deficit did not change in the Amended 2019 IRP because no resource changes occurred that would require
adjusting the calculation. Capacity deficit is determined using ldaho Powe/s current load and resource balance, as well
as committed generation additions and retirements. ln contrast, potential resource additions or retirements do not
factor into the calculation. As such, Jackpot Solar was not considered because it was not a definitive addition at the time
of analysis. Additionally, the retirement of Bridger was not a factor because the plant's retirement dates are uncertain.
How would adding Jackpots 10O MW of capacity reduce the import f,ow from the PNW on B2H? How willthis in turn
reduce overall revenue and the annual revenue credit loss to customers/ratepayers per the B2H Cost Treatment in
the IRP section?
STOP REQUEST NO. 28
ln CUB's opening comments ln the OPUC docket they state, .. from the Company's Distribution System Planning
presentation (OPUC Docket UM 2005), that ldaho Power currently has a92% AMI deployment in Oregon and targeting
for a99% deployment by the end of 2020.
What are lPCs plan to utilize the AMI? Please tell us what features are activated and what new features will be
activated to assist ratepayers. When willthese time based rate designs be deployed and how many MW of demand
response do you anticipate by category:
1) critical peak pricing {CPPI,2l variable peak pricing (VPPI,
3) time-of-use (TOUI pricing, and
4l critical peak rebates (CPRI? Pdf o47
STOP REQUEST NO. 29
What technigue or techniques does ldaho Power incorporate into their modeling, in Appendix A: Sales and Load
Forecast, to account for forecast erro6 in past lRPs?
STOP REQUEST NO. 30
Please refer to STOP Request No. 20
When the B2H is not built what will be the rate payer responsibility for all permitting expenses incurred?
Please name your response file to include the request number and provide all responses in electronic format. Please
contact Jim Kreider ([e-mail]) with any questions.
STOP B2H Coalition Production Requests 1- 30 in IPC-E-19-19 Page 10 of 14
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 5th of June 2020, a true and correct copy of the within and foregoing FIRST PRODUCflON
REQUEST OF THE STOP B2H COALITION TO IDAHO POWER in Docket No. IPC-E-19-19 was served, pursuant to
Commission Order No. 34602, exclusively via electronic mailto:
Commission Staff
Edward Jewell
Deputy Attorney General
ldaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 2O1-A
Boise,ldaho 837L4
ldaHydro
C. Tom Arkoosh
ARKOOSH LAW OFFICES
802 West Bannock Street, Suite LP 103
Box 2900
Boise,ldaho 83701
ldaho Conservation League
Benjamin J. Otto
ldaho Conservation League
710 North 5h Street
Boise,ldaho 83702
tdaho Sierra Club
Julian Aris, Associate Attorney
2101 Webster Street, Suite 1300
Oakland, California 946t2
Gloria D. Smith, Managing Attorney
2101 Webster Street, Suite 1300
Oakland, California 946L2
STOP B2H Coalition Production Requests 1- 30 in IPC-E-1$19
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stacie.foor@ a rkoosh.com
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Page 11 of 14
Ana Boyd, Research Analyst
2101Webster Street, Suite 1300
Oakland, California 94612
lndustrial Customers of ldaho Power
Peter J. Richardson
RICHARDSON ADAMS, PLLC
515 North 27s Street (83702)
P.O. Box 7218
Boise,ldaho 83707
Dr. Don Reading
5070 HillRoad
Boise,ldaho 83703
M icron Technology, lnc.
Austin Rueschhoff
Thorvald A. Nelson
Holland & Hart, LLP
555 Seventeenth Street, Suite 3200
Denver, Colorado 80202
Jim Swier
Micron Technology, lnc.
8000 South Federal Way
Boise,ldaho 83707
X Email [e-mail]
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_f,_Email ana. bovd@sierraclu b.org
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tnelson@ hollandhart.com
aclee@ hollandha rt.com
glsarganoamari@ hollandhart.com
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STOP B2H Coalition Production Requests 1- 30 in IPC-E-19-19 Page 12 of 14
LISA NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOISE |DAHO 83702
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STOP B2H Coalition Productlon Requests 1- 30 ln IPC-E-19-19 Page 13 of 14
TOPIC/KEYWORD: PORTFOLIOS
STAFF'S DATA REQUEST NO.33:
Please see Appendix D, page {. Given resource adequacy concerns in the Pacific
Northwest, to what extent has the Company considered market prices impacting the
economics of buying electric power on the market? ln other words, what types of
resources is the Gompany assuming will be available to generate power and
subsequently buy at Mid-C to export power across B2H?
ldaho Power speaks to market price risk on page 53 and liquidity and sufficiency risk starting on
page 54 of Appendix D.
ldaho Power assumes that hydro, wind, solar, storage, natural gas (depending on the assumed
future scenario), and other resources will be available in the future. For context, Protected
lnformation Attachment 1 titled "July Aug Purchases NW 2016-2019", is a summary of ldaho
Power's firm purchases from the Pacific Northwest during the months of July and August from
2016 to 2019. Over the identified timeframe, ldaho Power purchased over 709,000 megawatt-
hours ("MWh') of firm energy from 26 different counter-parties at Mid-C. ldaho Power expects
that these counter-parties will continue to transact at Mid-C in the future and firm energy will
continue to be available.
It is worth noting that intermittent renewable resources can be purchased as a firm product if the
selling party takes steps to "firm" up the product. For example, ldaho Power had over 13,000
MWh of firm purchases from Avangrid Renewables from 2017-2019.
Additionally, Attachment 2, titled "2025 Northwest Gen" is a summary from a 2025 heavy
summer load Western Electricity Coordinating Council ("WECC") power flow case that lists all
the dispatchable resources expected to be available in 2025 in the Northwest and Canada. The
total capability of all the resources is over 73,000 megawatts ('MW") (compared to ldaho
Power's 500 MW summertime interest in Boardman to Hemmingway ('B2H')). As discussed in
the Market Sufficiency Risk section of IRP Appendix D, the Northwest and Canadian regions are
winter-peaking, so surplus resource capability is available for summer demand. A 2025 list was
compiled because a base case for a year further out in the future was not readily available.
Finally, Attachment 3, titled "Aurora-WECC Buildout-Resource Adequacy P16" summarizes the
incremental resource buildout for the entire WECC for the Preferred Portfolio. Please refer to
the summary starting on row 81 for resource additions in the Pacific Northwest. These
incremental resources, combined with the existing resources, are what is being exported out of
the Pacific Northwest when purchases and sales are occurring in AURORA modeling.
ln aggregate, the information in the IRP and in the attachments provided in response to this
request demonstrates that it is reasonable to expect there will be sufficient resources to import
over the B2H line in the future.
Attachment 1 produced in response to this Request contains protected information and
will be provided in accordance with General Protective Order No. 20-068.
Page 17
Reference STOP REQUEST NO. 5
STOP OPUC DR 5 p 11-12 IPC's Reply Comments
STOP B2H argues that the Company's Capacity Benefit Margin ("CBM") can and should be used as a resource to offset
the need for 82H.35 STOP 82H suggests that unspecified other resources could instead be used to support system
reliability, freeing dedicated CBM transmission capacity and avoiding the need for additional transmission.36
By way of background, CBM is transmission capacity set aside for system emergencies, thereby allowing transmission
customers to reduce the amount of internal generation they must supply to maintain an adequate planning margin.
Given that this transmission must be available in emergencies, transmission capacity allocated to CBM is unavailable for
firm use.37
Here, ldaho Power has 330 MW of transmission capacity dedicated to CBM. However, if ldaho Power were to replace
the emergency reserve provided by CBM with another on-system resource, then the Company would be in precisely the
same position for resource planning purposes-in need of generation to meet that same 330 MW-because emergency
support not provided by CBM would need to be provided by something else. Indeed, STOP 82H overlooks the fact that,
by serving as an emergency resource in ldaho Powe/s Planning Margin, the 330 MW of CBM is alreody included as a
resource in the lRP. Thus, reducing or eliminating CBM simply moves the need for capacity from one bucket (serving
load)to another bucket (Planning Margin), while having zero impact on the Company's overallsystem need.38
Moreover, STOP 82H is incorrect that the financial impact of maintaining CBM capacity as an emergency resource costs
customers Sg million each year.39 To reach this figure, STOP 82H incorrectly assumes that ldaho Power pays the full
point-to-point transmission rate to reserve the necessary transmission capacity. This is simply not true. ldaho Power's
transmission costs are included in the development of the revenue requirement for the Company's retail customers,
with revenues received from transmission customers offsetting those costs.4O Although the network transmission
revenue requirement computed as part of ldaho Powe/s transmission formula rate includes an addition associated with
CBM, and ldaho Powe/s network customers pay their load ratio share of this revenue requirement, there is no
additionolcost to the Company's retail customers.
35 STOP B2H's Amended Opening Comments at 19.
36 STOP B2H's Amended Opening Comments at 20
37 ldaho Powe/s Amended 2019 lRP, App. D at 14.
38 STOP B2H advances a number of related points premised on the idea that eliminating CBM will increase the capacity ldaho Power has available
to meet minimum resource margins. Given that CBM is already included in ldaho Power/s Planning Margin, these arguments are based on the same
flawed premise. STOP B2H's Amended Opening Comments at2t-23.
39 STOP 82H's Amended Opening Comments at 21.
40 ln the Motter of ldoho Power Co., Request for o Gen. Rote Revision, Docket UE 233, Order No. 12-055, App. A at 16 (Feb. 23,20L21(showing
transmission costs in the Company's revenue requirement calculation),
OPUC Data Request 91
Transmission, Battery Storage, Action Plan - Given all the benefits of 82H listed on
page 78 in the 2019 lRP, please provide a detailed explanation of why the Company did
not include 82H in any of its new transmission integration options in System Optimizer.
Response to OPUC Data Request 91
The company interprets the question to be asking why Boardman to Hemingway (B2H)
was not included "among" the new transmission options modeled in the System
Optimizer (SO) model, as no transmission option is included "in" another modeled
transmission option in the 2019 lntegrated Resource Plan (lRP). Based on the foregoing
understanding, the company responds as follows:
ln the IRP topology, the B2H project requires two transmission paths linking three
"bubbles" for proper representation. Specifically required are transmission paths from
Borah to Hemingway, and from Hemingway to South-Central Oregon / Northern
California. Using the transmission option methodology, the SO model cannot
endogenously enforce the simultaneous inclusion of both parts of the 82H option when
the project is selected. The Hemingway bubbles' interconnections are essential to the
value of B2H, precluding the simplification of the option to only consider a path from
Borah to South-Centra! Oregon/Northern California. Please also refer the company's
response to OPUC Data Request 84, subpart (b).
LC 70 Staff Attachment A
Page/74
OPUC staff openint comments p 49-50
Boardman to Hemingway
ln the 2017 ldaho Power Company lRP, the Oregon Commission acknowledged 82H construction.l00 lt is
unfortunate that PacifiCorp failed to include 82H as an endogenous transmission modeling option, since
it would serve as a major artery enabling Wyoming wind to be exported to Oregon load and the Pacific
Northwest. Staff questions whether PacifiCorp's Utah reinforcement projects, including Gateway South,
have value for Oregon customers without 82H to connect them with Oregon load. Therefore, Staff
cannot recommend acknowledgement of the projects at this time.
When Staff asked PacifiCorp why 82H was not included as an endogenous transmission option in the IRP
in a data request, the Company stated that the 82H project requires two transmission paths linking
three "bubbles" for proper representation, and therefore is too complex for endogenous selection in SO.
Specifically, the Company claims that transmission paths from Borah to Hemingway, and from
Hemingway to South-Central Oregon / Northern California are required. Additionally, PacifiCorp said the
"Hemingway bubbles' interconnections are essential to the value of 82H, precluding the simplification of
the option to only consider a path from Borah to South-Central Oregon/Northern California."101
PacifiCorp's explanation of why 82H cannot be modeled endogenously seems counterintuitive. The
Company seems to be evaluating 82H as a connecting resource to California, but 82H will facilitate
connection between the Mona substation and Mid-C hubs, enabling bidirectionalflows, and therefore
does not need a path to California to estimate important project benefits. The Company's narrative
appears to conflate Midpoint-to-Summer Lake flow with B2H, and appears to ignore the planned series
compensation allowing for more differentiated flow across this path. Staff plans to investigate this claim
further in order to understand why the Company views B2H as too complex to be viewed as a
connection between two nodes.
ln summary, the 82H line appears to be a simple connection between two System Optimizer nodes, and
Staff has not yet heard a thorough explanation of why PacifiCorp cannot allow it to be selected
endogenously.
ln Staffs opinion, the Company's very limited analysis of B2H calls into question whether major
transmission investments were evaluated on consistent and comparable basis. Staff would be highly
interested in seeing analysis that reverses the order of the construdion of projects, allowing PTC wind to
be constructed closer to Oregon load along with the shorter 82H line in2024. Charting of projected line
utilization in both directions would also be helpful for Energy Gateway and jointly planned line
segments. Staff would like to work with the Company to investigate the possibility of obtaining
information showing actual current flows, and how those flows are projected to change in each
direction with each additional segment of Energy Gateway on an hourly basis, across a calendar year,
and in aggregate by summing line flows in both directions.
Conclusion
The burden rests on PacifiCorp to demonstrate the benefits of Gateway South and Utah reinforcements
to Oregon customers, and Staff cannot recommend acknowledgment of this project until the Company
demonstrates these benefits. The Company has failed to sufficiently assess arterial transmission projects
100 See Order No. 18-176. Pages 9-11.
101 See PacifiCorp response to Staff Data Request 91, included in Attachment A to these initial comments.
50
recognized and acknowledged by the Commission (82H), while seeming to place favorable assumptions
on projects that reinforce reliability in other states (Energy Gateway South).
Recommendation:
- Staff requests PacifiCorp provide a charting of projected line utilization in both directions for
Case P-26 (with EGS and B2H), for P4SCNW (preferred portfolio), and for P45CP (preferred
portfolio plus Dave Johnston wind in 2O2Tl.lnformation requested includes a depiction of
actual current flows, and how those flows are projected to change in each direction with each
additional segment of Energy Gateway on an hourly basis, across a calendar year, and in
aggregate by summing line flows in both directions.
- PacifiCorp should report on the possibility of completing B2H in2O24 to pair with PTC wind
near to the Western BAA.
PAC final coments p 37
With respect to
B2H, ldaho Power is the project manager on the B2H project and as such has the primary
responsibility of reviewing possible cost saving measures. PacifiCorp, as a party to the
permitting agreement, has an opportunity to provide lessons learned to ldaho Power and will
provide information if PacifiCorp remains a participant in the construction phase of the project, but the decision to
incorporate any lessons learned will be in agreement with parties involved in
the project moving fonrard.