20220216IRP Replacement Pages.pdf

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An IDACORP Company
LISA D. NORDSTROM
Lead Counsel
I [e-mail]
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February 16,2022
VIA ELECTRONIC EMAIL
Jan Noriyuki, Secretary
ldaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A(83714)
PO Box 83720
Boise, ldaho 83720-0074
Re: Case No. IPC-E-21-43
ldaho Power Company's 2021 lntegrated Resource Plan Appendix D and
Errata
Dear Ms. Noriyuki:
Attached for electronic filing is Appendix D to ldaho Power Company's (ldaho
Power or Company) 2021 lntegrated Resource Plan (lRP), which the Company had
stated would be filed in the first quarter of 2022. Additionally, the Company submits for
electronic filing eight (8) replacement pages with corrected portfolio cost information. As
explained and demonstrated below, these portfolio cost updates are immaterial in nature,
do not impact the selection of the Preferred Portfolio, and do not adjust any of the portfolio
rankings in the 2021 lRP.
Appendix D
Appendix D of ldaho Power's 2021 IRP includes updates on the Boardman to
Hemingway (B2H) project, including explanation of the finalized term sheet signed by
ldaho Power, PacifiCorp, and Bonneville Power Administration. ldaho Power previously
filed the term sheet in this docket on January 19,2022.
ln addition to updates and analysis related to the B2H project, Appendix D provides
information on ldaho Power's transmission system, how it is modeled in the lRP, and the
modeling and status of other potential transmission projects, such as Gateway West.
Replacement Pages
ln addition to Appendix D, ldaho Power is filing eight (8) replacement pages to the
main 2021 IRP report. ln the process of organizing IRP data files during completion of
Appendix D, Idaho Power identified two separate data discrepancies related to Bridger
Plant cost estimates. These updates result in immaterial cost changes to portfolios in the
2021 rRP.
Jan Noriyuki, Secretary
February 16,2022
Page 2
The first data issue arose because of the timing of revised estimates received by
the Company for costs related to the early exit of the Bridger Plant units. ldaho Power
continued to receive updated cost estimates throughout December 2021. To determine
portfolio costs in the lRP, ldaho Power inadvertently used the penultimate set of cost
estimates rather than the final cost estimates. For portfolios in which any of the Bridger
units are exited before end of book Iife, the revised costs increase the net present value
(NPV) of portfolios by between $4 and $6 million-an increase of between 0.041 percent
to 0.077 percent. This portfolio cost increase is de minimis in relation to total portfolio
costs of approximately $8 billion, and does not change the selection of the Preferred
Portfolio, nor does it change any of the portfolio rankings or sensitivity outcomes.
The second data issue, related to cost estimates for the Bridger Plant natural gas
conversion, was due to the inadvertent exclusion of fixed operations and maintenance
(O&M) costs associated with the conversion in IRP portfolio cost development. The IRP
planning team believed these costs were accounted for in ldaho Power's internalfinance
(p-worth) model. However, due to the newness of Bridger Plant conversion discussions,
this cost stream had not yet been incorporated into the p-worth. These fixed O&M costs
add between approximately $12-23 million to total NPV portfolio costs in the IRP-a cost
increase of between 0.2 percent to 0.3 percent to portfolios and sensitivities in which
either unit 1 or 2 is converted to natural gas. Similar to the issue above, this increase is
immaterial to the IRP analysis, does not change the selection of the Preferred Portfolio,
and has no impact on portfolio rankings or sensitivity outcomes.
Combined, these corrected data issues result in NPV portfolio cost increases of
between $5 million and $29 million on total NPV portfolio costs of approximately $8
billion-an increase of /ess than half of 1 percenf on affected portfolios. The table below
compares the NPV of a selection of portfolio costs as originally published compared to
the amended amounts included in the replacement pages. As the table demonstrates, the
portfolio cost increases resulting from these two issues do not change any aspect of
Preferred Portfolio selection or portfolio rankings.
2021 IRP portfolios, NPV years 2O2L-2O4O ($ x 1,000)
Portfolio
ORIGINAT
Planning Gas,
Planning
Carbon
UPDATED
Planning Gas,
Planning
Carbon
Total
Percentage
lncrease
Base with B2H
Base B2H PAC Bridger Alignment
Base without 82H
Base without 82H without Gateway West
Base without 82H PAC Bridger Alignment
57,91s,702
57,999,347
S8,192,830
58,44!,4L4
s8,18s,334
s7,942,428
s8,021,906
s8,2t9,281
58,470,10L
S8,207,893
o.34%
0.28%
0.32%
o.34%
o.28%
0.33%Base with 82H-High Gas High Carbon Test 57,997,339 58,024,064
Jan Noriyuki, Secretary
February 16,2022
Page 3
ldaho Power is committed to identifying and correcting issues in a straightforward
and transparent manner. To this end, the Company provides this update to ensure the
Commission and stakeholders are operating with the latest and most accurate
information. ldaho Power believes its thorough quality control process brought to light
these minor issues and allowed for a timely correction.
lf you have any questions about the attached documents, please do not hesitate
to contact me.
Very truly yours,
X*!.(,,,t-t"^,
Lisa D. Nordstrom
LDN:sg
Attachments
CERTIFIGATE OF SERVICE
I HEREBY CERTIFY that on the 16th day of February 2022,1 served a true and
correct copy of ldaho Power Company's2021 lntegrated Resource Plan Appendix D and
Errata upon the following named parties by the method indicated below, and addressed
to the following;
Commission Staff
Dayn Hardie
Deputy Attorney General
ldaho Public Utilities Commission
11331W. Chinden Blvd., Bldg No. 8,
Suite 201-A (83714)
PO Box 83720
Boise, lD 83720-0074
ldaho Gonservation League
Benjamin J. Otto
Emma E. Sperry
ldaho Conservation League
710 N.6th Street
Boise, ldaho 83702
Kiki Tidwell
704 N. River Street #1
Hailey, lD 83333
Micron Technology, lnc.
Austin Rueschhoff
Thorvald A. Nelson
Austin Jensen
Holland & Hart LLP
555 17th Street, Suite 32OO
Denver, CO 80202
Jim Swier
Micron Technology, lnc.
8000 South Federal Way
Boise, lD 83707
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esperry@ idahoconservation. orq
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tnelson@hollandhart. com
hollandhart.com
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IDAHO POWER COMPANY'S2O2l INTEGRATED RESOURCE PLAN APPENDIX D AND ERRATA. 1
Clean Energy Opportunities for Idaho
Michael Heckler
Courtney White
3778 Plantation River Dr., Ste. 102
Boise, lD 83703
Kelsey Jae
Law for Conscious Leadership
920 N. Clover Dr.
Boise, lD 83703
Industrial Customers of ldaho Power
c/o Peter J. Richardson
Richardson Adams, PLLC
515 N. 27th Street
Boise, ldaho 83702
Dr. Don Reading
6070 Hill Road
Boise, ldaho 83703
Stop B2H Coalition
Jack Van Valkenburgh
Valkenburgh Law, PLLC
P.O. Box 531
Boise, ldaho 83701
Jim Kreider
Stop B2H Coalition
60366 Marvin Rd
La Grande, OR 97850
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cou rtnev@cleanenerqyopportu n ities. com
mt chael6clean en voooortunities.com
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IDAHO POWER COMPANY'S 2021 INTEGRATED RESOURCE PLAN APPENDIX D AND ERRATA - 2
&^-J=
Stacy Gust, Regulatory Administrative
Assistant
IDAHO POWER COMPANY'S 2021 INTEGRATED RESOURCE PLAN APPENDIX D AND ERRATA - 3
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
cAsE NO. tPC-E-2r-43
IDAHO POWER COMPANY
ATTACHMENT
LEGISTATIVE FORMAT
stmloPciil,ER,
Executive Summary
o Unit 2-Allowed to exit between year-end 2023 and year-end 2026 or convert to natural
gas as early as year-end 2023.lf converted to natural gas, the unit will operate
through 2034.
o Unit 3-Can exit no earlier than year-end 2025 and no later than year-end 2034.
o Unit 4-Can exit no earlier than year-end 2027 and no later than year-end 2034.
The results of the LTCE model indicate that the conversion of units 1 and 2 to natural gas in
2023 is economical. The Preferred Portfolio identifies exits for units 3 and 4 year-end 2025 and
2028, respectively. To ensure the robustness of these modeling outcomes, the company
performed a significant number of validation and verification studies around the Bridger
conversions and coal exit dates. These validation and verification studies are detailed in
Chapter 9.
Boardman to Hemingway
ldaho Power in the 2021 IRP requests acknowledgement of 82H based on the company owning
45% of the project. This ownership share, which represents a change from ldaho Power's21%o
share in the 2019 lRP, is the result of negotiations among ldaho Power, PacifiCorp, and
Bonneville Power Administration (BPA). Under such a structure, ldaho Power would absorb
BPA's previously assumed ownership share in exchange for BPA entering into a transmission
service agreement with ldaho Power. This arrangement, along with many other aspects of B2H,
will be detailed in Appendix D, which will be filed during the first quarter of 2022.
The Preferred Portfolio, which includes B2H, is significantly more cost-effective than the best
alternative portfolio that did not include B2H.
o Base with 82H Portfolio NPV (Preferred Portfoliol-$lp+SaTpn4million
o Base without 82H PAC Bridger Alignment Portfolio NPV-SS#S5+8,207.9million
o B2H NPV Cost Effectiveness Differential-5269€265-5 million
Under planning conditions, the Base with 82H (Preferred Portfolio) is approximately 527+266
million more cost effective than the best portfolio that did not include the 82H project.
Detailed portfolio costs can be found in Chapter L0.
Page 8 2021 lntegrated Resource Plan
sllmtf PollrER.
7. Transmission Planning
This arrangement, along with many other aspects of B2H, will be detailed in the Appendix D-
Transmission Supplement, which will be filed during the first quarter of 2022.
B2H's value to ldaho Power's customers is substantial, and it is a key least-cost resource.
The Preferred Portfolio, which includes B2H, is significantly more cost-effective than the best
alternative resource portfolio that did not include 82H.
o Base with 82H Portfolio NPV (Preferred Portfolio)-$lpt*lrymillion
o Base without 82H PAC Bridger Alignment Portfolio NPV-S8+e538,207'9 million
o 82H NPV Cost Effectiveness Differential-5269S2655 million
Under planning conditions, the Preferred Portfolio (Base with B2H) is approximately
$27e2Qq million more cost effective than the best portfolio that did not include the 82H
project. Detailed portfolio costs can be found in Chapter 10.
Finally, B2H is an important step in moving ldaho Power toward its 2045 clean energy goal.
The B2H 500-kV line adds significant regional capacity with some remaining unallocated
east-to-west capacity. Additional parties may reduce costs and further optimize the project for
all participants.
Project Participants
ln January 2OL2,ldaho Power entered into a joint funding agreement with PacifiCorp and BPA
to pursue permitting of the project. The agreement designates ldaho Power as the permitting
project manager for the B2H project. Table 7.2 shows each party's B2H capacity and permitting
cost allocation.
Table 7.2 B2H capacity and permitting cost allocation
ldaho Power BPA PacifiCorp
Capacity (MW) west to east
Capacity (MW) east to west
Permitting cost allocation
350: 200 winter/500 summer
85
27%
400: 550 winter/250 summer
97
24%
300
818
ss%
For the 2027lRP,ldaho Power modeled B2H assuming that BPA transitions from an ownership
stake in the B2H project to a service-based stake in the project. Further details regarding this
assumption will be provided in Appendix D, which is anticipated to be filed during the first
quarter of 2022. Table 7.3 shows what each party's new 82H capacity allocation would be,
given this assumption.
2021 lntegrated Resource Plan Page 81
3tml0PcillrER"
10. Modeling Analysis
Each of the portfolios designed under the AURORA LTCE process, that are in contention for the
Preferred Portfolio, were evaluated through three different hourly simulations shown in
Table 10.2.
Table 10.2 AURORA hourly simulations
Zero Carbon Planning Carbon High Carbon
Planning Gas
High Gas
The three combinations include the planning case scenarios as well as the bookends for natural
gas and carbon adder price forecasts.
The purpose of the AURORA hourly simulations is to compare how portfolios perform
throughout the 20-year timeframe of the lRP. These simulations include the costs associated
with adding generation resources (both supply-side and demand-side) and optimally
dispatching the resources to meet the constraints within the model. The results from the three
hourly simulations, where only the pricing forecasts were changed, are shown in Table 10.3.
These different portfolios and their associated costs can be compared as potential options for a
preferred portfolio.
Table 10.3 2021 IRP portfolios, NPV years 2O2L-2O40 ($ x 1,000)
xx
x
Portfolio Planning Gas,
Planning Carbon
Planning Gas, Zero
Carbon
High Gas,
High Carbon
Base with 82H
Base 82H PAC Bridger Alignment
Base without B2H
Base without B2H without Gateway West3s
Base without B2H PAC Bridger Alignment
it+tsluypn,q28
s7pe.e'347gg1eq
s8+e2f3e821g2sL
5&A4+*L4L479,1o1.
SzJfEp+gp&3
sw7,213,486
5t#B*1E5,su
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Stwpqsane7 Ssrs4ee+9575359
Base with B2H-High Gas High Carbon Test36 57+t#.4lL/-4p54 $sr+:+pas%$65q
3sThe company did not continue further evaluation of this portfolio beyond planning conditions due to the
portfolio's inferior performance (high-cost, poor reliability, and poor emissions performance).
36All portfolios were optimized with planning conditions. The "Base with 82H-High Gas High Carbon (HGHC)Test"
portfolio includes total renewables equivalent to the "Base without 82H" portfolio and was evaluated to test
82H as an independent variable. The results indicate that 82H remains cost effective, independent of gas price
and carbon price and that a pivot to even more renewables in a future with a high gas and carbon price would
be appropriate.
Page 130 2021 lntegrated Resource Plan
sllmt0ProllrER.
10. Modeling Analysis
This comparison, as well as the stochastic risk analysis applied to these portfolios (see the
Stochastic Risk Analysis section of this chapter), indicate the Base with B2H portfolio best
minimizes both cost and risk and is the appropriate choice for the Preferred Portfolio.
The scenarios listed in Table 10.4 were sensitivities tested on the Preferred Portfolio and are
included to show the associated costs. Each was evaluated under planning natural gas and
carbon adder forecasts.
Table 10.4 2021 IRP Sensitivities, NPV years 2O2t-2O40 ($ x 1,000)
Sensitivity
Preferred Portfolio (Base with B2H)
SWIP-North
CSPP Wind Renewal Low
CSPP Wind Renewal High
Cost
51W78n,428
9#7#auA.287
5+*e2#8szl19.311
5tw7p52f,3e
The validation and verification tests are listed in Table 1-0.5. These were modeling simulations
performed on the Preferred Portfolio, with changes to the resources identified in the Action
Plan window, to ensure the model was optimizing correctly and to test assumptions.
More details on the setup and expected outcome of each test are provided in Chapter 9.
Table 10.5 2021 IRP vatidation and verification tests, NPV years 2O21-2O4O (S x 1,000)
Validation & Verification Tests Cost
Preferred Portfolio (Base with B2H)
Demand Response
Energy Efficiency
Natural Gas in 2028 Rather than Solar and Storage
Bridger Exit Units 1 & 2 at the End of 2023
Bridger Exit Unit 2 at the End of 2O26
Bridger Unit 2 Delayed Gas Conversion (20271
Bridger Exit Unit 4in2027
Bridger Exit Units 3 and 4 in2028 and 2030
Geothermal
Biomass
Valmy Unit 2 Exit in 2023
Valmy Unit 2Exitin2024
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Portlolio Emission Results
The company is seeking to execute on the actions identified in the Action Plan window.
Therefore, the company evaluated the COz emissions within the Action Plan window for each
portfolio in contention for the Preferred Portfolio, along with the SWIP-North portfolio.
2021 Integrated Resource Plan Page 131
=tmlpPcilrrER.10. Modeling Analysis
Figure 10.2 compares the full 20-year emissions of the company's 2019 Preferred Portfolio to
the top contending portfolios in the 2021 lRP. ln Figure L0.2, the 2019 Preferred Portfolio is on
the far left, adjacent to the 2021 Preferred Portfolio on its immediate right. Compared to the
2019 Preferred Portfolio, the 2021 Preferred Portfolio has cumulative emissions reductions of
about 21%. As can be seen on Figure 10.2, the other 202tportfolios each reflect reduced
emissions as compared to the 2019 Preferred Portfolio and are sorted by present value
portfolio cost from left to right. The costs associated with each portfolio are shown in the
yellow highlights. While 2021 IRP portfolios are shown on Figure 10.1to have relatively similar
emissions output during the Action Plan window, three portfolios have lower projected
emissions than the 2021- Preferred Portfolio over the full 20-year planning horizon.
However, it is important to note that each of those three portfolios present higher expected
cost. The information presented on Figures 10.1 and 10.2 demonstrate that ldaho Power's COz
emissions can be expected to trend downward over time. ldaho Power will continue to evaluate
resource needs and alternatives that balance cost and risk, including the relative potential
COz emissions.
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2021 lntegrated Resource Plan Page 133
sllmlpPcl,rrER,
10. Modeling Analysis
SWIP-North Opportunity Evaluation
The SWIP-North opportunity evaluation tests whether ldaho Power customers would
potentially benefit from ldaho Power's involvement in the project. Based on the NPV cost
results detailed in Table 10.4, the SWIP-North project appears to be worth further exploration.
o Preferred Portfolio (Base with B2H) NPv-$ry
o SWIP-North Portfolio NPV-SW
ln this opportunity evaluation, the company made assumptions about SWIP-North, and its cost
and capacity benefits, which are detailed more in Chapter 7. The company is not familiar with
any current partnership arrangements associated with the project, whether there are
opportunities to participate in the project, or the feasibility of the project in general and its
associated in-service date. Given the possible benefits to ldaho Power customers, the company
will engage the SWIP-North project developer and look to perform a more detailed evaluation
of SWIP-North in future lRPs.
82H Robustness Testing
The company evaluated B2H assuming five different planning margin contributions,
four different costs (various contingency amounts), and two different in-service dates to
consider the robustness of the 82H project.
B2H Copacity Evaluation
When the B2H project is placed into service, currently scheduled for pre-summer 2026,
the company will have access to as much as 550 MW of summer capacity. ln recent lRPs,
the company has planned to utilize 500 MW of B2H capacity to access the Mid-C markets and
purchase power.
As part of the 202LlRP, the company looked at portfolio costs assuming the company can
access 350 MW, 400 MW, 450 MW, 500 MW (the Preferred Portfolio), and 550 MW of capacity.
The sensitivities with capacity amounts less than 500 MW are set up to evaluate risk related to
reduced market access. The 550 MW capacity amount sensitivity quantifies potential benefits
associated with leveraging additional market purchases to avoid the need for a new resource.
To evaluate the impact of different B2H capacity levels, the company added or subtracted
comparable capacity in the form of battery storage (the least-cost alternative to providing
sufficient amounts of capacity) to maintain an adequate planning margin, while maintaining the
same cost of B2H (i.e., B2H capacity's contribution toward the planning margin is reduced with
no offsetting cost reduction). The resulting total portfolio costs are detailed in Table 10.8.
Page 144 2021 lntegrated Resource Plan
3llmloPo[,ER.
10. Modeling Analysis
Table 10.8 B2H capacity sensitivities
Portfolio NPV Potential Offsetting Costs Not lncluded (NPV)
Base 82H Portfolio-350 MW Planning Contribution
Base 82H Portfolio-400 MW Planning Contribution
Base 82H Portfolio-450 MW Planning Contribution
Base B2H Portfolio (500 MW)
Base 82H Portfolio-550 MW Planning Contribution
Base without B2H PAC Bridger Alignment Portfolio
(for comparison)
s8p4+CpE9
million
sTpeegplg
million
5t+*7gp
million
srpJszj,42
million
S1x*'+721L
million
s8+859299
million
551 million
S34 million
$17 million
so
SO
N/A
Table 10.8 shows that even with a substantially reduced planning margin contribution,
B2H portfolios remain cost effective. Additionally, if the company is able to access an additional
50 MW from the Mid-C market, that may present a cost-saving opportunity for customers.
The "Potential Offsetting Costs Not lncluded" column represents the possibility of selling
wheeling service utilizing the B2H capacity that is not being utilized by the company in the given
scenario. This offsetting cost is not factored into the portfolio NPV.
B2H Cost Risk Evoludtion
A transmission line such as 82H requires significant planning, organization, labor, and material
over a multi-year process to complete and place in-service. Evaluating cost risks to ensure
cost-effectiveness (i.e., a tipping point analysis) is an important consideration when planning
for such a project. Table 10.9 details the cost of the B2H project with Oyo,7oyo,2O%, and 30%
cost contingencies.
Table 10.9 82H cost sensitivities
82H Cost
ldaho Power Share TOTAL
B2H Cost
2021IRP NPV
B2H O% Contingency
B2H 70% Contingency
B2H 2Oo/o Contingency
B2H 30% Contingency
5485 million
5526 million
5566 million
S5o7 million
S159.6 million
S178.4 million
S197.2 million
52t6.t million
Utilizing the numbers in Table L0.8 and comparing them to the difference between the
Preferred Portfolio (Base with B2H) and the Base without 82H PAC Bridger Alignment portfolio,
the B2H project would have to increase significantly beyond a30% contingency before the
project would no longer be cost-effective. While this is already a significant margin, it should be
noted that there are other unquantified benefits to the B2H project that if quantified,
2021 lntegrated Resource Plan Page 145
s3lmloPo,l,ER,
10. Modellng Analysis
would further widen this gap. These items will be discussed in more detail in the forthcoming
Appendix D-Tronsmission Supplement, which is anticipated to be filed in the first quarter
of 2022.
B2H ln-Service Date Risk Evoluation
The current planned in-service date for 82H is prior to the summer of 2026. This date is
necessary to meet the peak demand growth needs, as well as fill in for the Valmy Unit 2 exit
occurring at the end of 2025, and to facilitate the exit of Bridger Unit 3, as recommended as
part of the Preferred Portfolio.
Should the B2H in-service date slip to 2027 due to a delay in receiving a permit, supply chain
constraints, or other unforeseen issues, the exit of Bridger Unit 3 will certainly be delayed,
and other new resources will be required in2026. Table 10.10 details the cost change of B2H
adjusting to 2027, and the new comparison to the Base without B2H PAC Bridger Alignment
portfolio (the best 82H-excluded portfolio).
Table 10.10 BZH2027 portfolio costs, cost sensitivities ($ x 1,000)
Portfolio Costs Portfolio Cost Compared to
B2H2027 Portfolio
Preferred Portfolio (Base with B2H)
Base with B2Hin2027
Base without 82H PAC Alignment
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Slippage in the schedule from2026to2027 would not be idealfor ldaho Power customers.
However, 82H remains the most cost-effective long-term resource.
Regional Resource Adequacy
Northwest Seosonol Resource Availobility Forecast
ldaho Power experiences its peak demand in late June or early July while the regional adequacy
assessments suggest potential capacity deficits in late summer or winter. ln the case of late
summer, ldaho Power's demand has generally declined substantially; ldaho Power's irrigation
customer demand begins to decrease starting in midJuly. For winter adequacy, ldaho Power
generally has excess resource capacity to support the region.
The assessment of regional resource adequacy is useful in understanding the liquidity of
regional wholesale electric markets. For the 2021 lRP, ldaho Power reviewed the Pocific
Northwest Loods and Resources Study by the BPA (White Book). For illustrative purposes,
ldaho Power also downloaded FERC 714 load data for the major Washington and Oregon Pacific
Northwest entities to show the difference in regional demand between summer and winter.
Page 146 2021 lntegrated Resource Plan
BEFORE THE
IDAHO PUBTIC UTITITIES COMMISSION
cAsE NO. IPC-E-21-43
IDAHO POWER COMPANY
ATTACHMENT
CLEAN FORMAT
<ltmloPo,rrER"
Executive Summary
o Unit 2-Allowed to exit between year-end 2023 and year-end 2026 or convert to natural
gas as early as year-end 2023.lf converted to natural gas, the unit will operate
through 2034.
o Unit 3-Can exit no earlier than year-end 2025 and no later than year-end 2034.
o Unit 4-Can exit no earlier than year-end 2027 and no later than year-end 2034.
The results of the LTCE model indicate that the conversion of units 1 and 2 to natural gas in
2023 is economical. The Preferred Portfolio identifies exits for units 3 and 4 year-end 2025 and
2028, respectively. To ensure the robustness of these modeling outcomes, the company
performed a significant number of validation and verification studies around the Bridger
conversions and coal exit dates. These validation and verification studies are detailed in
Chapter 9.
Boardman to Hemingway
ldaho Power in the 2021 IRP requests acknowledgement of B2H based on the company owning
45% of the project. This ownership share, which represents a change from ldaho Power's27Yo
share in the 2019 lRP, is the result of negotiations among ldaho Power, PacifiCorp, and
Bonneville Power Administration (BPA). Under such a structure, ldaho Power would absorb
BPA's previously assumed ownership share in exchange for BPA entering into a transmission
service agreement with ldaho Power. This arrangement, along with many other aspects of B2H,
will be detailed in Appendix D, which will be filed during the first quarter of 2022.
The Preferred Portfolio, which includes 82H, is significantly more cost-effective than the best
alternative portfolio that did not include 82H.
o Base with 82H Portfolio NPV (Preferred Portfolio)-$7,942.4 million
o Base without 82H PAC Bridger Alignment Portfolio NPV-S8,207.9million
o B2H NPV Cost Effectiveness Differential-5265.5 million
Under planning conditions, the Base with B2H (Preferred Portfolio) is approximately 5256
million more cost effective than the best portfolio that did not include the B2H project.
Detailed portfolio costs can be found in Chapter 10.
Page 8 2021 lntegrated Resource Plan
=tmloPci[rER.7. Transmlssion Planning
This arrangement, along with many other aspects of B2H, will be detailed in the Appendix D-
Transmission Supplement, which will be filed during the first quarter of 2022.
B2H's value to ldaho Power's customers is substantial, and it is a key least-cost resource.
The Preferred Portfolio, which includes B2H, is significantly more cost-effective than the best
alternative resource portfolio that did not include B2H.
o Base with B2H Portfolio NPV (Preferred Portfolio)-$7,942.4 million
o Base without 82H PAC Bridger Alignment Portfolio NPV-S8,207.9 million
o 82H NPV Cost Effectiveness Differential-5265.5 million
Under planning conditions, the Preferred Portfolio (Base with 82H) is approximately
5265 million more cost effective than the best portfolio that did not include the B2H project.
Detailed portfolio costs can be found in Chapter 10.
Finally, B2H is an important step in moving ldaho Power toward its 2045 clean energy goal.
The 82H 500-kV line adds significant regional capacity with some remaining unallocated
east-to-west capacity. Additional parties may reduce costs and further optimize the project for
all participants.
Project Participonts
ln January 2072,ldaho Power entered into a joint funding agreement with PacifiCorp and BPA
to pursue permitting of the project. The agreement designates ldaho Power as the permitting
project manager for the B2H project. Table 7.2 shows each party's B2H capacity and permitting
cost allocation.
Table 7.2 B2H capacity and permitting cost allocation
ldaho Power BPA PacifiCorp
Capacity (MW) west to east
Capacity (MW) east to west
Permitting cost allocation
350: 200 winter/500 summer
85
27o/"
400: 550 winter/250 summer
97
24%
300
818
s5%
For the 2021 1RP, ldaho Power modeled B2H assuming that BPA transitions from an ownership
stake in the B2H project to a service-based stake in the project. Further details regarding this
assumption will be provided in Appendix D, which is anticipated to be filed during the first
quarter of 2022. Table 7.3 shows what each party's new B2H capacity allocation would be,
given this assumption.
2021 lntegrated Resource Plan Page 81
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10. Modeling Analysis
Each of the portfolios designed under the AURORA LTCE process, that are in contention for the
Preferred Portfolio, were evaluated through three different hourly simulations shown in
Table 10.2.
Table 10.2 AURORA hourly simulations
Zero Carbon Planning Carbon High Carbon
Planning Gas
High Gas
The three combinations include the planning case scenarios as well as the bookends for natural
gas and carbon adder price forecasts.
The purpose of the AURORA hourly simulations is to compare how portfolios perform
throughout the 20-year timeframe of the lRP. These simulations include the costs associated
with adding generation resources (both supply-side and demand-side) and optimally
dispatching the resources to meet the constraints within the model. The results from the three
hourly simulations, where only the pricing forecasts were changed, are shown in Table 10.3.
These different portfolios and their associated costs can be compared as potential options for a
preferred portfolio.
Table 10.3 2021 IRP portfolios, NPV years 2021-2040 ($ x 1,000)
xx
x
Portfolio Planning Gas,
Planning Carbon
Planning Gas,
Zero Carbon
High Gas,
High Carbon
Base with 82H
Base B2H PAC Bridger Alignment
Base without B2H
Base without B2H without Gateway West3s
Base without B2H PAC Bridger Alignment
$7,942,428
s8,021,905
58,219,28L
s8,470,101
s8,207,893
57,213,486
57,17s,sL4
s7,810,996
s7,6LO,787
s9,8s8,725
s9,9ss,484
s9,501,435
s9,57s,4s0
Base with B2H-High Gas High Carbon Test36 58,024,054 s9,4s1,660
3s The company did not continue further evaluation of this portfolio beyond planning conditions due to the
portfolio's inferior performance (high-cost, poor reliability, and poor emissions performance).
36All portfolios were optimized with planning conditions. The "Base with 82H-High Gas High Carbon (HGHC) Test"
portfolio includes total renewables equivalent to the "Base withoutBzH" portfolio and was evaluated to test
82H as an independent variable. The results indicate that 82H remains cost effective, independent of gas price
and carbon price and that a pivot to even more renewables in a future with a high gas and carbon price would
be appropriate.
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3lml0PCilrrER.
10, Modeling Analysis
This comparison, as well as the stochastic risk analysis applied to these portfolios (see the
Stochastic Risk Analysis section of this chapter), indicate the Base with B2H portfolio best
minimizes both cost and risk and is the appropriate choice for the Preferred Portfolio.
The scenarios listed in Table 10.4 were sensitivities tested on the Preferred Portfolio and are
included to show the associated costs. Each was evaluated under planning natural gas and
ca rbon adder forecasts.
Table 10.4 2021 IRP Sensitivities, NPV years 2O2L-2O4O ($ x 1,000)
Sensitivity
Preferred Portfolio (Base with B2H)
SWIP-North
CSPP Wind Renewal Low
CSPP Wind Renewal High
Cost
57,942,428
57,9L4,287
S7,919,311
57,952,730
The validation and verification tests are listed in Table 1.0.5. These were modeling simulations
performed on the Preferred Portfolio, with changes to the resources identified in the Action
Plan window, to ensure the model was optimizing correctly and to test assumptions.
More details on the setup and expected outcome of each test are provided in Chapter 9.
Table 10.5 2021 IRP validation and verification tests, NPV years 2OZ1-2O4O ($ x 1,000)
Validation & Verification Tests Cost
Preferred Portfolio (Base with B2H)
Demand Response
Energy Efficiency
Natural Gas in 2028 Rather than Solar and Storage
Bridger Exit Units 1 & 2 at the End of 2023
Bridger Exit Unit 2 at the End of 2026
Bridger Unit 2 Delayed Gas Conversion (20271
Bridger Exit Unit 4in2027
Bridger Exit Units 3 and 4 in 2028 and 2030
Geothermal
Biomass
Valmy Unit 2 Exit in 2023
Valmy Unit 2Exitin2024
57,942,428
57,944,368
s8,169,838
s8,078,54s
s8,077,80s
S8,014,30s
s7,962,66s
S7,951,878
57,99i,4s3
s8,000,s06
s7,994,989
57,es7,tt6
S7,956,390
Portfolio Emission Results
The company is seeking to execute on the actions identified in the Action Plan window.
Therefore, the company evaluated the COz emissions within the Action PIan window for each
portfolio in contention for the Preferred Portfolio, along with the SWIP-North portfolio.
2021 lntegrated Resource Plan Page 131
etmlpF0[,ER.
10. Modeling Analysis
Figure 10.2 compares the full 20-year emissions of the company's 2019 Preferred Portfolio to
the top contending portfolios in the 2021 lRP. ln Figure 10.2, the 2019 Preferred Portfolio is on
the far left, adjacent to the 2O2L Preferred Portfolio on its immediate right. Compared to the
2019 Preferred Portfolio, the 2021 Preferred Portfolio has cumulative emissions reductions of
about 2t%. As can be seen on Figure 10.2, the other 2021 portfolios each reflect reduced
emissions as compared to the 2019 Preferred Portfolio and are sorted by present value
portfolio cost from left to right. The costs associated with each portfolio are shown in the
yellow highlights. While 2021 IRP portfolios are shown on Figure 10.1to have relatively similar
emissions output during the Action Plan window, three portfolios have lower projected
emissions than the 2O2L Preferred Portfolio over the full 2O-year planning horizon.
However, it is important to note that each of those three portfolios present higher expected
cost. The information presented on Figures 10.1 and 10.2 demonstrate that ldaho Power's COz
emissions can be expected to trend downward over time. ldaho Power will continue to evaluate
resource needs and alternatives that balance cost and risk, including the relative potential
COz emissions.
coFtot
g
.9
.c
E
otJ
5tmo,(m
50,0qo@
45,(m,(m
40,60,0@
3too,0(D
30,@0,06
25,@O,0G)
20,oo,(m
rtmqo@
ro,(m,(m
5,0@,@0
3a0lLs
2019Pretered 202lPrettred 8a*with82H-llcHc BageB2HPACBridEer 8a*withoetS2HPAC 8a*WthoutS2HPo.tfolio Portfolio (Ba* Wfth Tst Alignrcnt B,id8e, Ali8mnt
82H)
a2O21 a2U) r2021 42024 r2015 r.1026 )Q, a)UB r2029 120-10 12031 !2032 r2O3l r20l.r r2OJ5 .2036 olol/ 2018
8are wilhoul 82H
withiltGWw
2019 2Glt)
Figure 10.2 Estimated portfolio emissions lrom2O2l-2040
ln conclusion, the Preferred Portfolio (Base with B2H) strikes an appropriate balance of cost,
risk, and emissions reductions over the Action Plan window. The Preferred Portfolio also lays a
cost-effective foundation to build upon for further emissions reductions into the future.
t-:ximr
2021 lntegrated Resource Plan Page 133
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10. Modeling Analysis
SWI P-North Opportunity Eval uation
The SWIP-North opportunity evaluation tests whether ldaho Power customers would
potentially benefit from ldaho Power's involvement in the project. Based on the NPV cost
results detailed in Table 10.4, the SWIP-North project appears to be worth further exploration.
o Preferred Portfolio (Base with B2H) NPV-57,942,428
o SWIP-North Portfolio NPV-S7,9L4,287
ln this opportunity evaluation, the company made assumptions about SWIP-North, and its cost
and capacity benefits, which are detailed more in Chapter 7. The company is not familiar with
any current partnership arrangements associated with the project, whether there are
opportunities to participate in the project, or the feasibility of the project in general and its
associated in-service date. Given the possible benefits to ldaho Power customers, the company
will engage the SWIP-North project developer and look to perform a more detailed evaluation
of SWIP-North in future lRPs.
82H Robustness Testing
The company evaluated 82H assuming five different planning margin contributions,
four different costs (various contingency amounts), and two different in-service dates to
consider the robustness ofthe 82H project.
B2H Capacity Evaluation
When the B2H project is placed into service, currently scheduled for pre-summer 2026,
the company will have access to as much as 550 MW of summer capacity. ln recent lRPs,
the company has planned to utilize 500 MW of B2H capacity to access the Mid-C markets and
purchase power.
As part of the 2021 lRP, the company looked at portfolio costs assuming the company can
access 350 MW, 400 MW, 450 MW, 500 MW (the Preferred Portfolio), and 550 MW of capacity.
The sensitivities with capacity amounts less than 500 MW are set up to evaluate risk related to
reduced market access. The 550 MW capacity amount sensitivity quantifies potential benefits
associated with leveraging additional market purchases to avoid the need for a new resource.
To evaluate the impact of different 82H capacity levels, the company added or subtracted
comparable capacity in the form of battery storage (the least-cost alternative to providing
sufficient amounts of capacity) to maintain an adequate planning margin, while maintaining the
same cost of B2H (i.e., B2H capacity's contribution toward the planning margin is reduced with
no offsetting cost reduction). The resulting total portfolio costs are detailed in Table 10.8.
Page 744 2021 lntegrated Resource Plan
sllmtoProll,ER.
10. Modeling Analysis
Table 10.8 82H capacity sensitivities
Portfolio NPV Potential Offsetting Costs Not lncluded (NPV)
Base 82H Portfolio-350 MW Planning Contribution
Base 82H Portfolio-400 MW Planning Contribution
Base B2H Portfolio-450 MW Planning Contribution
Base B2H Portfolio (500 MW)
Base B2H Portfolio-550 MW Planning Contribution
Base without 82H PAC Bridger Alignment Portfolio
(for comparison)
58,069 million
58,019 million
S7,979 miltion
57,942 million
Sz,gtt million
58,208 million
551 million
S34 million
S17 million
5o
so
N/A
Table i.0.8 shows that even with a substantially reduced planning margin contribution,
B2H portfolios remain cost effective. Additionally, if the company is able to access an additional
50 MW from the Mid-C market, that may present a cost-saving opportunity for customers.
The "Potential Offsetting Costs Not lncluded" column represents the possibility of selling
wheeling service utilizing the B2H capacity that is not being utilized by the company in the given
scenario. This offsetting cost is not factored into the portfolio NPV.
B2H Cost Risk Evaluotion
A transmission line such as B2H requires significant planning, organization, labor, and material
over a multi-year process to complete and place in-service. Evaluating cost risks to ensure
cost-effectiveness (i.e., a tipping point analysis) is an important consideration when planning
for such a project. Table 10.9 details the cost of the B2H project with Oyo, LOyo,2O%, and 30%
cost contingencies.
Table 10.9 BzH cost sensitivities
B2H Cost
ldaho Power Share TOTAL
B2H Cost
2021 IRP NPV
B2H Oo/o Contingency
B2H tO% Contingency
B2H 20% Contingency
B2H 30% Contingency
5485 million
5526 million
S56G million
$607 million
S1s9.6 million
S178.4 million
S197.2 million
5216.1 million
Utilizing the numbers in Table 10.8 and comparing them to the difference between the
Preferred Portfolio (Base with B2H) and the Base without B2H PAC Bridger Alignment portfolio,
the B2H project would have to increase significantly beyond a 3O% contingency before the
project would no longer be cost-effective. While this is already a significant margin, it should be
noted that there are other unquantified benefits to the B2H project that if quantified,
would further widen this gap. These items will be discussed in more detail in the forthcoming
2021 lntegrated Resource Plan Page 145
sltmlpPciirER,
10. Modeling Analysis
Appendix D-Transmission Supplement, which is anticipated to be filed in the first quarter
of 2022.
B2H ln-Service Dote Risk Evoluation
The current planned in-service date for B2H is prior to the summer of 2026. This date is
necessary to meet the peak demand growth needs, as well as fill in for the Valmy Unit 2 exit
occurring at the end of 2025, and to facilitate the exit of Bridger Unit 3, as recommended as
part of the Preferred Portfolio.
Should the B2H in-service date slip to 2027 due to a delay in receiving a permit, supply chain
constraints, or other unforeseen issues, the exit of Bridger Unit 3 will certainly be delayed,
and other new resources will be required in 2026. Table 10.10 details the cost change of B2H
adjusting to 2027, and the new comparison to the Base without B2H PAC Bridger Alignment
portfolio (the best 82H-excluded portfolio).
Table 10.10 B2H2027 portfolio costs, cost sensitivities (S x 1,000)
Portfolio Costs Portfolio Cost Compared to
B.2H2027 Portfolio
Preferred Portfolio (Base with B2H)
Base with B2Hin2027
Base without B2H PAC Alignment
-S5s,oso
S196,37s
Slippage in the schedule from2026to2027 would not be idealfor ldaho Power customers.
However, 82H remains the most cost-effective long-term resource.
Regional Resource Adequacy
Northwest Seosonal Resource Availability Forecast
ldaho Power experiences its peak demand in late June or early July while the regional adequacy
assessments suggest potential capacity deficits in late summer or winter. ln the case of late
summer, ldaho Power's demand has generally declined substantially; ldaho Power's irrigation
customer demand begins to decrease starting in midJuly. For winter adequacy, ldaho Power
generally has excess resource capacity to support the region.
The assessment of regional resource adequacy is useful in understanding the liquidity of
regional wholesale electric markets. For the 2O2L lRP,ldaho Power reviewed the Pocific
Northwest Loods ond Resources Study by the BPA (White Book). For illustrative purposes,
ldaho Power also downloaded FERC 714 load data for the major Washington and Oregon Pacific
Northwest entities to show the difference in regional demand between summer and winter.
57,942,428
s8,011,517
s8,207,893
Page 146 2021 lntegrated Resource Plan