20211230Application.pdf

LISA D. NORDSTROM
Lead Counsel
[e-mail]
December 30, 2021
VIA ELECTRONIC EMAIL
Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, Idaho 83720-0074
Re: Case No. IPC-E-21-43
Idaho Power Company’s 2021 Integrated Resource Plan
Dear Ms. Noriyuki:
Attached for electronic filing, pursuant to Order No. 35058, is Idaho Power
Company’s 2021 Integrated Resource Plan.
Additionally, five (5) copies of Idaho Power Company’s 2021 Integrated Resource
Plan will be hand delivered.
If you have any questions about the attached documents, please do not hesitate to
contact me.
Very truly yours,
Lisa D. Nordstrom
LDN:sg
Attachments
RECEIVED
2021 DEC 30 AM 11:32
IDAHO PUBLIC
UTILITIES COMMISSION
APPLICATION - 1
LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]

Attorney for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S 2021 INTEGRATED
RESOURCE PLAN.
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CASE NO. IPC-E-21-43

APPLICATION

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), and in
accordance with Idaho Public Utilities Commission (“Commission”) Order Nos. 22299
and 30317, requests that the Commission acknowledge the Company’s 2021 Integrated
Resource Plan (“IRP” or “Plan”). In support of this request, Idaho Power states as
follows:
I. INTRODUCTION
1. Idaho Power’s 2021 IRP undertakes a comprehensive analysis of the
optimal mix of both demand- and supply-side resources available to reliably serve
customer demand and flexible capacity needs over the Plan’s 20-year planning horizon
from 2021 to 2040. Under Idaho Power’s improved AURORA long-term capacity
APPLICATION - 2
expansion (“LTCE”) approach—which Idaho Power utilized for the first time in this
IRP—resources are selected by the model from a variety of supply- and demand-side
options to develop portfolios that are least cost for various alternative scenarios. To
ensure that the resulting portfolios provide customers with least-cost, least-risk
resources, Idaho Power employed verification tests to validate the most economic
portfolio under numerous variations of resources and timing. Moreover, to confirm that
the AURORA-produced portfolios meet Idaho Power’s reliability requirements, Idaho
Power measured each portfolio’s reliability through the calculation of a portfolio loss of
load expectation (“LOLE”) on an annual basis. Based on this analysis, Idaho Power
selected a Preferred Portfolio and Short-Term Action Plan that are driven by and
include the following core resource actions:
 Add 120 megawatts (“MW”) of solar photovoltaic (“PV”) capacity in 2022;
 Convert Bridger units 1 and 2 from coal to natural gas by summer 2024;
 Seek to acquire significant resources to meet energy and capacity needs
in 2023 through 2027;
 Exit from Bridger unit 3 and Valmy unit 2 by year-end 2025;
 Energize B2H in 2026.
2. The complete 2021 IRP consists of five separate documents: (1) the 2021
Integrated Resource Plan; (2) Appendix A – Sales and Load Forecast; (3) Appendix B
– Demand-Side Management 2020 Annual Report; (4) Appendix C – Technical
Appendix. By the end of the first quarter of 2022, Idaho Power will also provide an
Appendix D – Transmission Supplement. A copy of the complete 2021 IRP (with the
exception of Appendix D) is provided as Attachment 1 and can also be found on the
APPLICATION - 3
Company’s website at www.idahopower.com/irp. Appendix D will be filed and
distributed to the service list in the first quarter of 2022. Interested parties may also
request a single printed copy of the 2021 IRP by contacting [e-mail].
II. IRP GOALS AND ASSUMPTIONS
3. The primary goals of Idaho Power’s 2021 IRP are to: (1) identify sufficient
resources to reliably serve the growing demand for energy within Idaho Power’s
service area throughout the 20-year planning period (2021-2040); (2) ensure the
selected resource portfolio balances cost and risk, while including environmental
considerations; (3) give balanced treatment to both supply-side resources and
demand-side measures; and (4) involve the public in the planning process in a
meaningful way.
4. The 2021 IRP assumes that during the 20-year planning period, Idaho
Power will continue to be responsible for acquiring resources sufficient to serve its
retail customers in its Idaho and Oregon service areas and will continue to operate as a
vertically integrated electric utility. During the 20-year planning period, Idaho Power’s
load is forecasted to grow by an average of 1.4 percent per year for energy demand
and 1.4 percent per year for peak-hour demand. Total customers are expected to
increase from more than 600,000 in 2021 to 847,000 by 2040.
5. Hydroelectric generation remains a large part of Idaho Power’s generation
fleet; however, hydroelectric plants are subject to variable water and weather
conditions. In response to public and regulatory input, Idaho Power continues to
develop more conservative streamflow projections and planning criteria for use in
resource adequacy planning.
APPLICATION - 4
6. The 2021 IRP examined demand-side management (“DSM”) programs,
which are designed to achieve prudent, cost-effective energy efficiency savings and
provide an optimal amount of peak reduction. Idaho Power also continues to provide
customers with tools and information to help them manage their own energy usage.
The Company achieves these objectives through the implementation and careful
management of incentive programs and through outreach and education.
7. Idaho Power’s resource planning process also evaluates transmission
capacity as a resource to serve retail customers. Transmission projects are often
regional resources, and Idaho Power coordinates transmission planning regionally as a
member of NorthernGrid. The delivery of energy, both within the Idaho Power system
and through regional transmission interconnections, is of increasing importance as
regional penetration of variable energy resources and their associated intermittent
production continues to increase. The timing of new transmission projects is subject to
complex permitting, siting, and regulatory requirements and coordination with co-
participants.
8. Finally, Idaho Power engages with public stakeholders when developing
its IRP. To incorporate stakeholder and public input, the Company worked with the
Integrated Resource Plan Advisory Council (“IRPAC”), comprising members of the
environmental community, major industrial customers, agricultural interests,
representatives from both this Commission and the Public Utility Commission of
Oregon, representatives from the Idaho Governor’s Office of Energy and Mineral
Resources, representatives from the Northwest Power and Conservation Council
(“NWPCC”), and others. Many members of the public also attended and participated.
APPLICATION - 5
A list of the 2021 IRPAC members can be found in Appendix C – Technical Report.
9. For the 2021 IRP, Idaho Power conducted twelve IRPAC meetings. The
Company also maintained an online forum for stakeholders to submit requests for
information, and for the Company to provide responses to information requests. The
forum allowed stakeholders to develop their understanding of the IRP process,
particularly its key inputs, which enabled more meaningful stakeholder involvement
throughout the process.
III. IRP METHODOLOGY
10. Idaho Power’s IRP is designed to ensure the Company has sufficient
resources to reliably serve customer demand and flexible capacity needs over the 20-
year planning period.
A. Improved Capacity Expansion Modeling Approach
11. In Idaho Power’s 2019 IRP, Idaho Power used AURORA’s LTCE
platform with varied success. The LTCE was able to optimize for the entire western
interconnection; however, it was incapable of optimizing specifically for Idaho Power’s
service area. For this reason, the Company went through a manual optimization
process to determine an Idaho Power Preferred Portfolio. The manual optimization
approach complicated the IRP process, and it raised questions on the part of the
Commission and stakeholders. Therefore, in an effort to improve both the process and
results for the 2021 IRP, as well as future IRPs, the Company worked with the software
provider to add functionality allowing for co-optimization between the western
interconnection and Idaho Power. As a result, the resource portfolios developed in the
2021 IRP were optimized entirely within the LTCE platform, without manual
APPLICATION - 6
adjustments, specific to Idaho Power’s balancing area.
12. As part of the 2021 IRP process, the Company formulated future
scenarios based on economic, market, and regulatory considerations and then allowed
the AURORA model to select the optimal resources to address the conditions in each
scenario. The model selected from a wide variety of supply and demand-side resource
options to develop optimal portfolios that meet a 15.5 percent planning margin, and
regulated reserve requirements associated with balancing load, wind generation, and
solar generation. The model can also simulate the exit or retirement of existing
generation units, if economic, and can displace otherwise available resources that are
higher cost.
13. To ensure that the AURORA-produced portfolios provide customers with
affordable energy, Idaho Power employed verification tests to validate the most
economic portfolio under numerous variations of resources and timing. To verify that the
AURORA-produced portfolios meet Idaho Power’s reliability requirements, Idaho Power
measured each portfolio’s reliability through the calculation of a portfolio LOLE. For
those portfolios that did not achieve the minimum reliability threshold, an additional
reliability resource requirement cost was added to the portfolio cost.
14. For each of the AURORA-developed portfolios, Idaho Power conducted a
financial analysis of costs and benefits. The financial costs and benefits include:
 Construction costs
 Fuel costs
 Operations and maintenance costs
 Transmission upgrades associated with interconnecting new resource
APPLICATION - 7
options
 Natural gas pipeline reservation or new natural gas pipeline infrastructure
 Projected wholesale market purchases and sales
 Anticipated environmental controls
 Market value of renewable energy certificates (“REC”) for REC-eligible
resources
15. In addition, to enhance the risk-evaluation within the IRP, the Company
worked with the IRPAC to develop four unique future scenarios. Idaho Power ultimately
used these scenarios to test whether the decisions being made within the Action Plan
window are robust across multiple futures. The four future scenarios are:
 Rapid Electrification
 Climate Change
 100% Clean by 2035
 100% Clean by 2045
B. Boardman to Hemingway
16. Idaho Power’s 2021 IRP continues to analyze the addition of the
Boardman to Hemingway Transmission Line Project (“B2H”) to ensure that it remains a
prudent resource. In the 2021 IRP, the Company evaluated B2H based on the
Company owning 45% of the project, which represents a change from Idaho Power’s
share evaluated in the 2019 IRP. This increase in the Company’s assumed ownership
share is based upon ongoing negotiations among Idaho Power, PacifiCorp, and
Bonneville Power Administration. A detailed update with regard to B2H will be provided
as Appendix D, which will be filed with the Commission during the first quarter of 2022.
APPLICATION - 8
As part of the 2021 IRP, the Company provides an extensive evaluation of B2H
compared to portfolios that do not include B2H, as well as several sensitivities of the
project related to project cost contingency, Mid-Columbia market availability, and
project timing. The Preferred Portfolio, which includes B2H, is significantly more cost-
effective than the best alternative portfolio that did not include B2H, with the cost gap
between the portfolios having an NPV difference of about $270 million. This gap
provides substantial insulation to the various project risks that were evaluated.
C. Climate Change
17. Idaho Power’s 2021 IRP includes a new chapter addressing both the
mitigation of and adaption to climate change. In March of 2019, the Company
announced a goal to provide 100% clean energy by 2045. Complementing this clean
energy goal, the 2021 IRP shows that the Company will continue to rely on
hydropower, plan to end reliance on coal-fired operations by year-end 2028, as well as
continue to focus on energy efficiency and demand response programs, as they are
deemed economical and reliable. This chapter of the IRP also addresses measures
required to adapt to a changing climate, through risk mitigation and management. The
2021 IRP also includes a variety of modeling scenarios to conceive of a climate change
future and/or future with climate change policies or regulations.
IV. PREFERRED RESOURCE PORTFOLIO
18. A fundamental goal of the IRP process is to identify a selected, or
preferred, resource portfolio. The Preferred Portfolio identifies resource options and
timing to allow Idaho Power to continue to reliably serve customer demand, balancing
cost and risk over the 2021 to 2040 planning period.
APPLICATION - 9
19. Using the AURORA LTCE model, Idaho Power produced optimized
portfolios:
 With and without B2H;
 With and without portions of the Gateway West project;
 Allowing the model to choose Bridger Coal Plant exit date and natural gas
conversion date assumptions based on Idaho Power’s economics;
 Aligning with PacifiCorp’s Bridger Coal Plant exit date and natural gas
conversion date assumptions.1
20. These portfolios were compared against each other using various natural
gas price forecasts (planning and high) and carbon adder price forecasts (planning,
zero, and high). The planning case futures represent Idaho Power’s assessment of the
most likely future.
21. To validate the resource selection and the robustness of the Preferred
Portfolio, the Company performed the following additional scenario and sensitivity
analyses:
 The resources selected in the Action Plan window of the Preferred
Portfolio were compared to optimal resources selected for four future
scenarios to determine the changes that would need to be made in each
of those scenarios: Rapid Electrification, Climate Change, 100% Clean by
2035, and 100% Clean by 2045.

1 In the Matter of Rocky Mountain Power’s Filing for Acknowledgement of Its 2021 Integrated Resource
Plan, Case No. PAC-E-21-19, Updated Vol. 1 at 299, 322 (Sep 15, 2021).
APPLICATION - 10
 Both low and high cogeneration and small power producers (“CSPP”) wind
renewal assumptions were tested to determine the impact on the
resources selected within the Action Plan window.
 A sensitivity was evaluated to test the cost-effectiveness of the Southwest
Intertie Project (“SWIP”) North transmission project—a potential future
partnership opportunity.
 Validation and verification studies were performed to test coal exit dates,
Bridger unit natural gas conversions, and both supply-side and demand-
side resource additions.
 Various tests and sensitivities were performed on B2H project capacity,
cost, and timing assumptions.
22. Based on all of this analysis, Idaho Power selected its Preferred Portfolio,
which is identified as the Base with B2H portfolio. This Preferred Portfolio incorporates
positive changes toward clean, low-cost resources, with an increased focus on system
adequacy.
V. 2021 IRP ACTION PLAN (2021-2027)
23. The Action Plan for the 2021 IRP reflects near-term actionable items of
the Preferred Portfolio necessary to successfully position Idaho Power to provide
reliable, economic, and environmentally sound service to our customers into the future.
As noted above, the core resource actions include:
 The addition of 120 MW of solar photovoltaic capacity in 2022;
 Conversion of Bridger units 1 and 2 from coal to natural gas by summer
2024;
APPLICATION - 11
 Seek to acquire significant resources to meet capacity and energy needs
in 2023 through 2027;
 Exit from Bridger unit 3 and Valmy unit 2 by 2025;
 B2H online in 2026.
24. Below is a summary of the 2021 IRP’s Action Plan items through 2027:
Year Action
2022
Conduct ongoing B2H permitting activities. Negotiate and execute B2H partner construction
agreements. Once the agreements are in place, file for a certificate of public convenience and necessity
with state commissions.
2022 Discuss partnership opportunities related to SWIP-North with the project developer for more detailed
evaluation in future IRPs.
2022–2023 Jackpot Solar is contracted to provide 120 MW starting December 2022. Work with the developer to
determine, if necessary, mitigating measures if the project cannot meet the negotiated timeline.
2022–2024 Plan and coordinate with PacifiCorp and regulators for conversion to natural gas operation with a 2034
exit date for Bridger units 1 and 2. The conversion is targeted before the summer peak of 2024.
2022–2025 Issue a Request for Proposal (RFP) to procure resources to meet identified deficits in 2024 and 2025.
2022–2025 Plan and coordinate with PacifiCorp and regulators for the exit/closure of Bridger Unit 3 by year-end
2025 with Bridger Unit 4 following the Action Plan window in 2028.
2022–2025 Redesign existing DR programs then determine the amount of additional DR necessary to meet the
identified need.
2022–2026 Conduct preliminary construction activities, acquire long-lead materials, and construct the B2H project.
2022–2027 Implement cost-effective energy efficiency measures each year as identified in the energy efficiency
potential assessment.
2022–2027 Work with large-load customers to support their energy needs with solar resources.
2022–2027 Finalize candidate locations for distributed storage projects and implement where possible to defer
T&D investments as identified in the Action Plan.
2025 Exit Valmy Unit 2 by December 31, 2025.
2025–2026 Subject to coordination with PacifiCorp, and B2H in-service prior to summer 2026, exit Bridger Unit 3 by
December 31, 2025.

VI. FUFILLMENT OF 2019 IRP COMMITMENTS
25. During the Idaho Commission and stakeholder review of the Second
Amended 2019 IRP, Idaho Power received recommendations and committed to provide
APPLICATION - 12
additional analysis and/or discussion of a number of issues in its 2021 IRP.2 The
fulfillment of key commitments is discussed below.
26. Idaho Power committed to explore cost and reliability impacts from
reserve shortfalls as part of the 2021 IRP analysis.3 For the 2021 IRP, Idaho Power
adopted a reliability threshold of 0.05 days per year to better account for extreme
weather events that are becoming more frequent, factor in water availability uncertainty
year to year, as well as to align with the reliability threshold used by the NWPCC. The
portfolio reliability analysis results and the amount of additional generation (when
needed) that was added to each of the selected portfolios are shown in Appendix C -
Technical Report.
27. Idaho Power indicated it would apply additional value streams for storage
technologies in the 2021 IRP.4 The 2021 IRP contains additional valuation of benefits
like peak capacity, regulation reserves, spinning reserves, and locational benefits for
storage technology.
28. The Company committed to provide a sensitivity analysis about wind
replacement assumptions and their impacts on resource planning.5 The Company
performed CSPP wind renewal sensitivity studies in the 2021 IRP. The base
assumption is that 25 percent of CSPP wind developers will re-power. The Company
also performed CSPP Wind Renewal Low and High scenarios. These scenarios test the

2 In the Matter of Idaho Power Company’s 2019 Integrated Resource Plan, Case No. IPC-E-19-19, Order
No. 34959 (March 16, 2021).
3 Id. at 15.
4 Case No. IPC-E-19-19, Idaho Power’s Reply Comments at 46.
5 Order No. 34959 at 16.
APPLICATION - 13
25 percent renewal assumption by replacing it with 0 percent and 100 percent renewal
rates, respectively. These studies are discussed in Chapter 9 of the 2021 IRP.
29. The Company committed to evaluate market availability alongside
transmission capacity to determine capacity deficiencies.6 For the 2021 IRP, internally
set-aside transmission capacity needs to have a corresponding reservation on
neighboring systems to be considered as firm capacity from markets. A discussion of
transmission included in the load and resource balance7 is included in the Chapter 10
Capacity Planning Margin section. Regional resource adequacy (market depth) is
discussed in the Chapter 10, Regional Resource Adequacy section. Appendix D –
Transmission Supplement will also include a discussion on market depth.
30. The Company agreed to include contingency reserve requirements
necessary as a result of transmission customers in the load and resource balance
evaluation.8 A discussion of transmission customer contingency reserves in the
planning reserve margin will be included in the forthcoming Appendix D – Transmission
Supplement.
31. Idaho Power agreed its future IRPs would analyze class-level peak
contribution and include sensitivity or probability bands of its system peak forecast.9 The
inclusion, results and methodology used to develop class-level impacts to peak using
conformed hourly forecast are discussed in Appendix A of the 2021 IRP. The Company
included high and low sensitivity bands around the load forecast as guideposts for the

6 Id.
7 The load and resource balance table is included in Appendix C – Technical Appendix on pages 18-37.
8 Order No. 34959 at 16.
9 Case No. IPC-E-19-19, Idaho Power’s Reply Comments at 57; Order No. 34959 at 15.
APPLICATION - 14
employed stochastic analysis. A table showing a discussion of the Company’s Idaho
commitments and compliance is attached as Attachment 2.
VII. COMMUNICATIONS AND SERVICE OF PLEADINGS
32. Idaho Power requests that any notices, inquiries, and communications
regarding this request be provided to:
Lisa D. Nordstrom
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Timothy E. Tatum
Alison Williams
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]

VIII. REQUEST FOR ACKNOWLEDGEMENT
33. Idaho Power respectfully requests that the Commission issue its order
acknowledging the Company’s 2021 IRP and finding that the 2021 IRP meets both the
procedural and substantive requirements of Commission Order Nos. 22299 and 30317.
DATED at Boise, Idaho, this 30th day of December 2021.

LISA D. NORDSTROM
Attorney for Idaho Power Company

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-21-43

IDAHO POWER COMPANY

ATTACHMENT 1

2021 INTEGRATED RESOURCE PLAN
SEE ATTACHED DOCUMENTS

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-21-43

IDAHO POWER COMPANY

ATTACHMENT 2

IRP COMMITMENTS AND COMPLIANCE
Reference Topic IRP Requirement, Recommendation or Commitment How the Item is Addressed in the 2021 IRP
Order No. 34959, p. 15 Modeling Idaho Power commits to explore cost and reliability impacts from reserve
shortfalls as part of the 2021 IRP analysis
For the 2021 IRP, Idaho Power is adopting a reliability threshold of 0.05 days per year to better
account for extreme weather events that are becoming more frequent, as well as to align with
the reliability threshold used by the Northwest Power & Conservation Council (NWPCC). The
portfolio reliability analysis results are shown in the Technical Appendix and the amount of
additional generation (when needed) that was added to each of the selected portfolios.
Idaho Power's Reply Comments, p.
46
DERs The Company plans to apply additional value streams for storage
technologies in the 2021 lRP.
The Company applied several benefits to storage technologies such as: peak capacity,
regulation reserves, spinning reserves, and locational benefits.
Order No. 34959, p. 14 Load and Resource
Balance
The Company agrees and commits to providing the L&RB table in future
lRPs.
The load and resource balance table is provided in the Technical Appendix.
Order No. 34959, p. 16 QF/Load and
Resource Balance
The Company's next IRP will include a sensitivity analysis about wind
replacement assumptions and their impacts on resource planning.
The Company performed CSPP wind renewal sensitivity studies in the 2021 IRP as discussed in
Chapter 9. Portfolio. The base assumption is that 25% of CSPP wind developers will re-power.
The Company also performed the CSPP Wind Renewal Low and High scenarios. These scenarios
test the 25% renewal assumption by replacing it with 0% and 100% renewal rates. These
studies are discussed in Chapter 9. Portfolios.
Order No. 34959, p. 16 Load and Resource
Balance
Idaho Power agrees with Staff that market availability alongside
transmission capacity should be looked at when determining capacity
deficiencies and will review these concepts when developing the L&RB to
be included in the 2021 lRP.
For the 2021 IRP, internally set aside transmission capacity needs to have a corresponding
reservation on neighboring systems to be considered as firm capacity purchases from markets.
This in response to the Valmy #2 exit study where the availability of third-party transmission
was analyzed. A discussion of transmission included in the L&RB is included in the Chapter 10.
Capacity Planning Margin. Regional resource adequacy (market depth) is discussed separately
in Chapter 10. Regional Resource Adequacy. Appendix D will also include a discussion on
market depth.
Order No. 34959, p. 16 Load and Resource
Balance
The Company agrees that contingency reserve requirements necessary as a
result of transmission customers should play a role in the L&RB evaluation.
Contingency reserves are part of the planning reserve margin. A discussion of transmission
customer contingency reserves will be included in the forthcoming Appendix D transmission
supplement.
Staff's Comments, p. 15 and Order
No. 34959, p. 16
Load and Resource
Balance
In the future the Company will provide better definitions of resource
categories and will change the labeling per Staffs recommendation.
"Existing EE" to "Energy Efficiency"
Labels in the L&RB were updated to provide clearer definitions.
Order No. 34959, p. 15 and Idaho
Power's Reply Comments, p. 57
Load Forecast Idaho Power agreed that class peak dynamics are important to know and
therefore, in response to Staff’s recommendation, proposed that class-level
AMI data be used to inform assignments of class contribution to system
peak
The inclusion, results and methodology used to develop class level impacts to peak using
conformed hourly forecast are discussed in Appendix A of 2021 IRP.
Order No. 34959, p. 15 and Idaho
Power's Reply Comments, p. 57
Load Forecast Idaho Power also agreed its future IRPs would analyze class-level peak
contribution and include sensitivity or probability
bands of its system peak forecast.
See above for peak contribution. In addition, the Company included high and low sensitivity
bands around the load forecast are and included in Appendix A of 2021 IRP. These sensitivity
bands around the load forecast are guideposts for the stochastic analysis used.
Order No. 34959, p. 18 Load Forecast Idaho Power acknowledged that customer-generators accounted for one-
half of one percent of retail customers when the 2019 IRP was developed
but that recent adoption of solar is “relatively strong” in Idaho Power’s
service territory, and the higher values will be reflected in the 2021 load
forecast.
The Company included a decrement to the load forecast for net metered customer generators.
Details on methodology are included in Appendix A of 2021 IRP. Notice and discussion in
regard was held with stakeholders and Staff's of both Idaho and Oregon during March 11,
2021 IRPAC.
Order No. 21-184, p. 8 and
Appendix A, p. 4 and 35
Energy Efficiency Adopts Staff's recommendation that Idaho Power report on the impact that
the Idaho cost evaluation change may have, in conjunction with Idaho
Power's obligation to evaluate efficiency potential consistent with Oregon
cost assessment methodologies as part of the next IRP and for the
Company to do a comprehensive review of Energy Trust of Oregon's
efficiency measures from 2018 through 2020, and share the results.
Idaho Power performed a comprehensive review of ETO's piloted efficiency measures from
2018 to 2020. The results were presented to the Company's EEAG in August 2020.
Idaho
Oregon
Order No. 21-184, p. 9 Valmy Unit 2 In regards to Valmy Unit 2, we direct Idaho Power to provide the results of
the analysis in its 2021 IRP to either confirm the proposed 2022 exit or
provide clarification on next steps in the event the early exit is not
supported by analysis.
Idaho Power conducted a system reliability analysis to evaluate the timing of exit from Valmy
Unit 2. The results of the analysis were filed in IPUC docket IPC-E-21-12 and in OPUC docket LC
74. Additionally, in the 2021 IRP early exit of Unit 2 was evaluated as part of the AURORA
capacity expansion modeling, but the AURORA model did not select Unit 2 for exit earlier than
2025, see Chapter 8. Planning Period Forecasts.
Order No. 21-184, p. 10 and
Appendix A, p. 12
Jim Bridger Units 1
and 2
Early exit from Jim Bridger Units 1 and 2 We will review the additional
analysis and updates on negotiation with PacifiCorp in Idaho Power's 2021
IRP. More information regarding Jim Bridger 1 and 2 exits should be
provided in the 2021 IRP, including a reliability impact analysis similar to
the one proposed for Valmy
For the 2021 IRP, Idaho Power used AURORA’s LTCE model to determine the best Bridger
operating option specific to Idaho Power’s system subject to the following constraints:
•Unit 1—Allowed to exit year-end 2023 or convert to natural gas. If converted to natural gas,
the unit will operate through 2034.
•Unit 2—Allowed to exit between year-end 2023 and year-end 2026 or convert to natural gas
as early as year-end 2023. If converted to natural gas, the unit will operate through 2034.
•Unit 3—Can exit no earlier than year-end 2025 and no later than year-end 2034.
•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.
Order No. 21-184, p. 11 and
Appendix A, p. 23
Jim Bridger Units 1
and 2
Update the Commission as soon as it knows the outcome of PacifiCorp’s
negotiation with the Wyoming DEQ regarding continued use of Jim Bridger
Units 1 and 2 without SCR investments.
The negotiation between the Environmental Protection Agency (“EPA”), state of Wyoming, and
PacifiCorp to resolve Jim Bridger units 1 and 2 compliance with the Federal Clean Air Act
Regional Haze (“RH”) rules is ongoing. On November 15, Wyoming Governor Gordon issued a
notice of intent to sue alleging that EPA failed to perform a nondiscretionary duty under the
Clean Air Act when it failed to approve or disapprove Wyoming’s RH State Implementation
Plan revision for Bridger within the time prescribed by law. On November 16, the Wyoming
Public Service Commission initiated an investigation to determine the effects on rates,
generation adequacy, system reliability, and other aspects of operations by the potential
discontinuation of operations at Jim Bridger Unit 2 due to the EPA’s inaction on the Wyoming
Regional Haze State Implementation Plan.
Order No. 21-184, p. 16 B2H We decline to determine that 20 percent is the appropriate cost
contingency for B2H, but expect Idaho Power to explain and support the
cost contingency assigned to this project in the 2021 IRP.
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. Chapter 10. Modeling Analysis -Table 10.9 details the cost of the B2H project
with 0%, 10%, 20%, and 30% cost contingencies. 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 30% contingency before the project would no longer be cost-effective.
Order No. 21-184, p. 16 B2H We expect Idaho Power to analyze closely whether expanding its ownership
share from 21 percent, and relying on OATT revenues to offset its
additional costs is truly comparable, in terms of risks and financial impacts,
to joint ownership. Where differences may exist, we expect that Idaho
Power will explain how those risks are mitigated or considered in its
analyses.
Idaho 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 Idaho Power’s 21%
share in the 2019 IRP, is the result of negotiations among Idaho Power, PacifiCorp, and
Bonneville Power Administration (BPA). Under such a structure, Idaho Power would absorb
BPA’s previously assumed ownership share in exchange for BPA entering into a transmission
service agreement with Idaho 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.
Order No. 21-184, p. 17 B2H Market resource conditions must continue to be reviewed and tested. Regional Resource Adequacy is discussed in Chapter 10. Modeling Analysis. For the 2021 IRP,
Idaho Power reviewed the Pacific Northwest Loads and Resources Study by the BPA (White
Book). For illustrative purposes, Idaho 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.
Order No. 21-184, p. 17 B2H Idaho Power should update its estimated B2H project costs prior to
submitting its 2021 IRP
As part of the 2021 IRP the Company refreshed its overall cost estimate which is included in
the B2H costs modeled in the IRP analysis.
Order No. 21-184, p. 18 Demand Response Adopt Staff's recommendation - DR needs comprehensive review. DR
needs to be a priority for Idaho Power, and it needs to carefully review how
DR could fill out peak needs, with potentially lower costs than alternative
resources.
As part of the 2021 IRP the Company performed a rigorous examination of the potential for
expanded demand response, Idaho Power utilized a Northwest Power and Conservation
Council (NWPCC) assessment of DR potential for the Northwest region to determine the DR
potential that may be available in Idaho Power’s service area. Based on this assessment, Idaho
Power estimated approximately 580 MW of DR potential in its service area and concluded that
any needed capacity from demand response would be shifted to later hours of the day than
what the current DR programs were designed for. Based on the results of the analysis, Idaho
Power submitted filings with both the IPUC and OPUC to modify the program parameters
based on these proposed changes to the programs. This is further discussed in Chapter 6.
Demand-Side Resources.
Order No. 21-184, p. 18 and
Appendix A, p. 4 and 41
Demand Response The 2021 IRP should model expanded DR with a LCOC based on real
programmatic approximations for acquiring the said amount of incremental
additional DR; LCOC estimates representative of incremental increases
(e.g., 10 percent increase, 20 percent increase, 30 percent increase, 50
percent increase); or some other mutually agreed upon approach to more
rationally model this key variable.
Based on the results of its comprehensive review, DR was evaluated in the 2021 IRP modeling
process by using the 584 MW of DR potential including an estimate of 300 MW of capacity
from the modified DR programs. Therefore, a maximum of approximately 280 additional MW
of DR (584 MW minus 300 MW, rounded down) was available for selection in the AURORA
model when analyzing the future load and resource balance.
Order No. 21-184, p. 18 Load Forecast We determine that Staff should work with Idaho Power to review the
current framework and alternatives, and that Idaho Power should work
with Staff and stakeholders to update its methodology. After working with
stakeholders, Idaho Power should be prepared to justify its final chosen
approach in its next IRP.
The Company held a workshop and received feedback on Load Forecasting models and cross
validation tests it proposes to use with stakeholders and the Staff's of Idaho and Oregon Feb
23, 2021. Further the Company up held conference calls and feedback sessions with Idaho
Staff April 1, 2021 and April 29, 2021; and Oregon Staff on August 26, 2021 in regards.
Order No. 21-184 - Appendix A, p. 4
and p. 38 and Idaho Power's Final
Comments, p. 70
Load Forecast Include load forecasting improvements with respect to indicator variables
and out-of sample testing
Efforts with respect are noted above. In addition, Appendix A of 2021 IRP includes additional
discussion.
Order No. 21-184 - Appendix A, p. 4
and 38 and Idaho Power's Final
Comments, p. 70
Load Forecast Present the impacts of the economic recession caused by COVID-19 on long-
term load growth
Impacts of COVID-19 was presented to stakeholders and Staff's of both Idaho and Oregon on
the March 11, 2021 IRPAC. Narrative discussion is also included in Appendix A of 2021 IRP.
Order No. 21-184 - Appendix A, p. 4
and 38
Load
Forecast/Modeling
Address whether the upper and lower bounds on the Company’s customer
load stochastic risk analysis are wide enough.
The Company did evaluate the stochastic risk bands in preparation of the 2021 IRP and
concluded they were reasonable and did not need revision. To assess the reasonableness of
the stochastic error bounds as they relate to customer load, the upper and lower bounds were
compared to the load forecast 90/10 error bounds. For both the upper and lower bound, the
stochastic values were found to fall slightly outside of the 90/10 bounds which is to be
expected. The stochastic process produces 20 scenarios which could be expected to test a
larger bound of 95/5.
Order No. 21-184, p. 19 and
Appendix A, p. 67
QF In addition to adopting Staff's recommendation to come up with
reasonable assumptions through a sensitivity analysis, we direct that, in the
next IRP, Idaho Power explain how the sensitivities resulting from the study
would affect the IRP's preferred portfolio and action plan if incorporated.
The Company performed CSPP wind renewal sensitivity studies in the 2021 IRP and its
discussed in Chapter 9. Portfolio. The base assumption is that 25% of CSPP wind developers
will re-power. The Company also performed the CSPP Wind Renewal Low and High scenarios.
These scenarios test the 25% renewal assumption by replacing it with 0% and 100% renewal
rates. These studies are discussed in Chapter 9. Portfolios.
Order No. 21-184, p. 17 DERs Idaho Power should model renewables plus storage as part of IRP planning. The 2021 IRP includes renewables plus storage as a supply-side resource option. The various
supply-side resources considered in the 2021 IRP are discussed in Chapter 5. Future Supply-
Side Generation and Storage Resources. The resource attributes for the solar plus storage
resource are found in Table 8.4.
Order No. 21-184 - Appendix A, p.
49
DERs Perform the Company’s approved capacity factor approximation method
using all the new data that has become available.
With sufficient historical generation data available, the Company was able to calculate the
Effective Load Carrying Capability of solar in compliance with Order No. 16-362.
Order No. 21-184 - Appendix A, p.
49
DERs Eliminate or raise the 80 MW cap on battery storage. This includes
standalone battery storage as well as storage paired with solar.
The 80 MW cap on battery storage was removed for the 2021 IRP. As evidence, the Company's
Preferred Portfolio includes almost 1,700 MW of battery storage resources.
Order No. 21-184 - Appendix A, p.
49
DERs Model the PTC for wind to the extent it is technically achievable by the
Company.
Where feasible, the Company included PTC for future wind resources. Costs of wind resources
are provided in Technical Appendix. Supply-Side Resource Data.
Order No. 21-184 - Appendix A, p.
49
DERs Revise its Wyoming cost inputs to include more reasonable cost
assumptions.
The Company's cost assumptions are provided in Technical Appendix. Supply-Side Resource
Data. Wyoming wind was given a 45% average capacity factor.
Order No. 21-184, p. 7 DERs Incorporate solar hosting capacity into the customer-owned generation
forecasts for the 2021 IRP.
Solar hosting capacity was assessed as a driver of the customer-owned generation forecast and
was determined to not materially impact the customer-owned generation forecast.
Order No. 21-184 - Appendix A, p.
21
DERs File the results of each of the VER studies with the Commission once they
are complete and notify the LC 74 service list.
Idaho Power worked in conjunction with a Technical Review Committee (TRC) for the
development of the 2020 VER Study and retained E3 to conduct the study. The study was filed
with the OPUC in docket UM 1730(6).
Order No. 21-184 - Appendix A, p. 4
and 32
Risk Report qualitative benefits and risks by portfolio in the 2021 IRP and in all
IRPs going forward in which a qualitative analysis plays a significant role.
Idaho Power included qualitative risk analysis and its found in Chapter 10. Modeling Analysis -
Qualitative Risk Analysis. Table 10.6 shows a Qualitative risk comparison between the
portfolios.
Order No. 21-184 - Appendix A, p. 4
and 32
Risk Implement a more robust measure of risk for evaluating portfolios. The
Company should incorporate risks or situations that are not used to create
the initial portfolios and should strive to incorporate qualitative risks into
the portfolio development process.
In addition to testing the portfolios against high gas and high carbon risk, the Company in
collaboration with the IRPAC developed four additional future scenarios to be run for the
purpose of risk evaluation: Rapid Electrification, climate change, 100% Clean by 2035 and
100% Clean by 2045. These are discussed in Chapter 9. Portfolios.
Order No. 21-184 - Appendix A, p. 4
and 32
Modeling Devote resources to improve optimization techniques and address this
issue in a 2021 IRP workshop. In particular, the Company should implement
techniques in its next IRP to optimize resource buildouts based on the
Company’s system only.
Idaho Power worked with Energy Exemplar, the AURORA software developer to ensure that
capacity expansion runs for the 2021 IRP were optimized specifically for Idaho Power's system.
The Company also performed model validation and verification tests to ensure the model is
operating as expected and to verify that the selected Preferred Portfolio represents a robust
optimization of cost and risk. The Company held an AURORA workshop on April 22, 2021 to
help stakeholders better understand the AURORA modeling.
Order No. 21-184 - Appendix A, p.
29
Modeling In the 2021 IRP improve portfolio naming conventions For the 2021 IRP, the Company developed a branching scenario analysis strategy to ensure that
it had reasonably identified an optimal solution specific to its customers. Figure 9.1 details the
initial branching evaluation where the company compared AURORA-optimized portfolios for a
base scenario (i.e., planning conditions for all key inputs such as load growth, natural gas price,
carbon price, etc.) for six potential future portfolios. Figure 9.2 details the additional
sensitivities and scenarios.
Idaho Power's Reply Comments, p.
47-48
Modeling Transmission capacity assumptions (for market purchases and what counts
toward planning margin) will be reevaluated in the 2021 lRP.
The determination of the Planning Margin is discussed in Chapter 9. Portfolios and in the LOLE
methodology is found in the Loss of Load Expectation section of Appendix C—Technical
Report. The Planning margin resource type breakdown is shown in Table 9.1
Order No. 21-184 - Appendix A, p.4-
5 and p. 43
Other Provide an update on the Oregon Residential Time-of-Day Pilot Plan,
including number of participants, total cost of the pilot since its 2019
launch, and peak capacity reduction by season, as well as propose an
alternative venue for reporting pilot results, given that the Smart Grid
Report will be suspended with the Commission approval of DSP guidelines.
In Chapter 6. Demand Size Resources, the Company provides an update on its Oregon TOU
offering.
Order No. 21-184 - Appendix A, p. 5
and p. 51
Other The Company should produce the Climate Change Risk Report referenced in
the 2017 IRP acknowledgment order and include it in the next IRP.
The climate change risk report is included as Chapter 3. Climate Change. This new chapter of
the IRP focuses on identifying climate-related risks, discussing the company’s approach to
monitoring and mitigating identified risks, and examining climate-related risk considerations in
the IRP.