20220216IRP Appendix D.pdf

INTEGRATED RESOURCE PLAN
A VIEW
FROM ABOVE
2021IRP
FEBRUARY • 2022
APPENDIX D: TRANSMISSION SUPPLEMENT
Printed on recycled paper
SAFE HARBOR STATEMENT
This document may contain forward-looking statements,
and it is important to note that the future results could
differ materially from those discussed. A full discussion
of the factors that could cause future results to differ
materially can be found in Idaho Power’s filings with the
Securities and Exchange Commission.
Table of Contents
2021 Integrated Resource Plan—Appendix D Page i
TABLE OF CONTENTS
Table of Contents ........................................................................................................................... i
List of Tables ................................................................................................................................. v
List of Figures ............................................................................................................................... vi
List of Appendices ........................................................................................................................ vi
Executive Summary ....................................................................................................................... 1
2021 IRP B2H Project Update .................................................................................................. 1
B2H Background and Purpose ................................................................................................. 2
Gateway West Considerations in the 2021 IRP ....................................................................... 4
Existing Transmission Utilized for Firm Imports ...................................................................... 4
2022 Term Sheet and B2H Project Partner Update ....................................................................... 6
The 2022 B2H Term Sheet and the 2021 IRP ........................................................................... 6
B2H Related Terms .................................................................................................................. 6
Idaho Power and BPA Terms ................................................................................................... 6
Longhorn Station Terms .......................................................................................................... 7
Idaho Power and PAC Terms ................................................................................................... 8
B2H Revised Scope–Midline Series Capacitor ......................................................................... 9
Idaho Power’s Transmission System ........................................................................................... 10
Transmission Market Shifts and Constraints ......................................................................... 10
Idaho Power’s Existing Transmission Capacity ...................................................................... 11
Idaho to Northwest Path Description .............................................................................. 11
Montana–Idaho Path Utilization ..................................................................................... 12
Idaho to Northwest Path Utilization ................................................................................ 12
Transmission Capacity to the South ................................................................................ 13
Transmission in the 2021 IRP Load and Resource Balance .............................................. 13
Regional Planning—Studies and Conclusions ........................................................................ 15
B2H Development ....................................................................................................................... 16
B2H Design ............................................................................................................................ 16
Transmission Line Design ................................................................................................ 16
Transmission Line Structural Loading Considerations ..................................................... 17
Transmission Line Foundation Design ............................................................................. 18
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Page ii 2021 Integrated Resource Plan—Appendix D
Lightning Performance .................................................................................................... 19
Earthquake Performance ................................................................................................ 19
Wildfire ........................................................................................................................... 20
Wind Gusts/Tornados ..................................................................................................... 21
Ice .................................................................................................................................... 21
Landslide ......................................................................................................................... 21
Flood ............................................................................................................................... 21
Direct Physical Attack ...................................................................................................... 21
B2H Design Conclusions .................................................................................................. 22
B2H Capacity Interest ............................................................................................................ 22
Capacity Rating—WECC Rating Process ................................................................................ 23
B2H Project Coparticipants ................................................................................................... 23
PAC and BPA Needs ......................................................................................................... 23
PAC .................................................................................................................................. 24
BPA .................................................................................................................................. 26
Coparticipant Agreements .............................................................................................. 28
Coparticipant Expenses Paid to Date ............................................................................... 28
B2H Treasure Valley Integration Projects .............................................................................. 28
Hemingway–Bowmont #2 230 kV Line ............................................................................ 28
Bowmont–Hubbard 230 kV Line ...................................................................................... 29
B2H Integrated Resource Planning .............................................................................................. 30
Resource Needs Evaluation and Markets .............................................................................. 30
IRP Guideline Language—Transmission Evaluated on Comparable Basis ........................ 30
Boardman to Hemingway as a Resource ......................................................................... 30
Market Overview .................................................................................................................. 31
Power Markets ................................................................................................................ 31
Mid-C Market .................................................................................................................. 31
Mid-C and Idaho Power ................................................................................................... 33
Modeling of the Mid-C Market in the IRP ........................................................................ 34
B2H Capacity Analysis ........................................................................................................... 34
Capacity Costs ................................................................................................................. 34
Table of Contents
2021 Integrated Resource Plan—Appendix D Page iii
Energy Cost ..................................................................................................................... 35
B2H Comparison to Other Resources .............................................................................. 35
BPA Southeast Idaho Customer Loads .................................................................................. 36
B2H Benefits and Values ............................................................................................................. 37
Capacity ................................................................................................................................. 37
Clean Energy Future .............................................................................................................. 37
Leverage Regional Diversity .................................................................................................. 38
Capacity to Four Corners Market Hub ................................................................................... 39
Borah West and Midpoint West Capacity Upgrades ............................................................. 40
Improved Economic Efficiency .............................................................................................. 41
Renewable Integration .......................................................................................................... 41
Grid Reliability/Resiliency...................................................................................................... 41
Resource Reliability ............................................................................................................... 42
Contingency Reserves ........................................................................................................... 44
Reduced Electrical Losses ...................................................................................................... 45
Flexibility ............................................................................................................................... 46
EIM ........................................................................................................................................ 47
B2H Complements All Resource Types ............................................................................ 47
B2H Benefits to Oregon ......................................................................................................... 48
Economic and Tax Benefits .............................................................................................. 48
Local Area Electrical Benefits .......................................................................................... 49
Gateway West Project ................................................................................................................. 51
Project Background ............................................................................................................... 51
Idaho Power Segments ......................................................................................................... 52
2021 IRP Gateway West—Phase 1 (Partial Segment 8) .......................................................... 53
2021 IRP Gateway West—Phase 2 (Complete Segment 8) ..................................................... 53
2021 IRP Gateway West Transmission Assumptions ............................................................. 54
Base with B2H Portfolio Gateway West Transmission Assumptions ............................... 54
Base without B2H PAC Bridger Alignment Portfolio Gateway West Transmission
Assumptions .................................................................................................................... 55
Southwest Intertie Transmission Project-North .......................................................................... 57
Table of Contents
Page iv 2021 Integrated Resource Plan—Appendix D
Combined Major Transmission Projects in Idaho ........................................................................ 58
2021 IRP Portfolio Transmission Cost Assumptions .................................................................... 59
Transmission Line Estimates............................................................................................ 59
Substation Estimates ....................................................................................................... 60
Calibration of Cost Estimates .......................................................................................... 60
Costs Incurred to Date ..................................................................................................... 61
Additional Costs Applied to B2H ...................................................................................... 61
Cost-Estimate Conclusions .............................................................................................. 61
Transmission Revenue .......................................................................................................... 61
Risk .............................................................................................................................................. 63
Capacity, Cost, and In-Service Date Risk ................................................................................ 63
Liquidity and Market Sufficiency Risk .................................................................................... 63
Data Point 1: Peak Load Analysis from Table 8 ................................................................ 64
Data Point 2: 2019 Pacific Northwest Loads and Resources Study—BPA ....................... 64
Data Point 3: FERC Form 714 Load Data .......................................................................... 66
Data Point 4: Northwest and California Renewable Portfolio Standards......................... 66
Data Point 5: Potential Resources from Northwest Utility IRPs ....................................... 67
Market Sufficiency and Liquidity Conclusions ................................................................. 68
Siting Risk .............................................................................................................................. 68
Schedule Risk ........................................................................................................................ 68
Catastrophic Event Risk ......................................................................................................... 69
Project Activities ......................................................................................................................... 70
Schedule Update ................................................................................................................... 70
Permitting ....................................................................................................................... 70
Post-Permitting ............................................................................................................... 70
Conclusion ................................................................................................................................... 72
B2H Project History ............................................................................................................... 75
B2H Public Participation ........................................................................................................ 76
Project Activities ................................................................................................................... 78
2006 ................................................................................................................................ 78
2007 ................................................................................................................................ 78
Table of Contents
2021 Integrated Resource Plan—Appendix D Page v
2008 ................................................................................................................................ 78
2009 ................................................................................................................................ 78
2010 ................................................................................................................................ 78
2011 ................................................................................................................................ 78
2012 ................................................................................................................................ 79
2013 ................................................................................................................................ 79
2014 ................................................................................................................................ 79
2015 ................................................................................................................................ 79
2016 ................................................................................................................................ 79
2017 ................................................................................................................................ 79
2018 ................................................................................................................................ 79
2019 ................................................................................................................................ 80
2020 ................................................................................................................................ 80
2021 ................................................................................................................................ 80
B2H Route History ................................................................................................................. 80
LIST OF TABLES
Table 1. Pacific Northwest to Idaho Power west-to-east transmission capacity ..................... 12
Table 2. The Idaho to Northwest Path (WECC Path 14) summer allocation ............................ 12
Table 3. Third-party secured import transmission capacity .................................................... 14
Table 4. B2H Term Sheet capacity interests ............................................................................ 22
Table 5. Total capital dollars ($)/kilowatt (kW) for select resources considered in the
2021 IRP (2021$) ....................................................................................................... 34
Table 6. High-level differences between resource options ..................................................... 35
Table 7. BPA southeast (SE) Idaho Customers ........................................................................ 36
Table 8. 2030 peak load estimates—illustration of load diversity between western
regions ....................................................................................................................... 38
Table 9. List of transmission entities at Four Corners and Mona ............................................ 39
Table 10. NERC forced-outage rate information for different resources .................................. 43
Table 11. Change in Idaho Power contingency reserve obligation with B2H ............................ 45
Table 12. Idaho Power area losses from powerflow cases pre- and post-B2H .......................... 46
Table of Contents
Page vi 2021 Integrated Resource Plan—Appendix D
Table 13. Projected annual B2H tax expenditures by county* .................................................. 48
Table 14. Idaho Power internal path capacity and ownership .................................................. 55
Table 15. Preferred Portfolio (Base with B2H) transmission upgrades and capital costs .......... 59
Table 16. Base without B2H PAC Bridger alignment transmission upgrades and capital
costs .......................................................................................................................... 59
Table 17. Coal retirement forecast ........................................................................................... 65
Table 18. Potential New Resources Identified by Regional Utilities (PNUCC)* .......................... 67
LIST OF FIGURES
Figure 1. Idaho Power transmission system map ..................................................................... 11
Figure 2. Transmission tower components .............................................................................. 17
Figure 3. Northwest regional forecast (source: 2021 PNUCC) .................................................. 32
Figure 4. Additional generation required to achieve 0.05 LOLE by portfolio ............................ 44
Figure 5. Gateway West map ................................................................................................... 52
Figure 6. Gateway West map–Magic Valley to Treasure Valley segments (8 and 9) ................ 53
Figure 7. SWIP-North preliminary route ................................................................................... 57
Figure 8. Map of B2H, Gateway West, and SWIP North .............................................................. 58
Figure 9. BPA white book PNW surplus/deficit one-hour capacity (1937 critical water
year) .......................................................................................................................... 65
Figure 10. Peak coincident load data for most major Washington and Oregon utilities ............ 66
LIST OF APPENDICES
Appendix D-1. Transmission line alternatives to the proposed B2H 500 kV
transmission line ................................................................................................. 74
Appendix D-2. B2H project history, public participation, project activities, route history,
and a detailed list of notable project milestones................................................. 75
Executive Summary
2021 Integrated Resource Plan—Appendix D Page 1
EXECUTIVE SUMMARY
Idaho Power Company (Idaho Power or the company) developed Appendix D–Transmission
Supplement to detail many of the transmission cost and modeling assumptions utilized in the
2021 Integrated Resource Plan (IRP), as well as discuss other details related to transmission.
The primary focus of Appendix D will continue to be the Boardman to Hemingway Transmission
Line (B2H) project.
2021 IRP B2H Project Update
The B2H project is moving into the preliminary construction phase of the project. On January
18, 2022, after significant discussions, study efforts, and negotiations, the three B2H permit
funding parties, Idaho Power, PacifiCorp (PAC), and Bonneville Power Administration (BPA),
executed a Non-Binding Term Sheet that addresses B2H ownership, transmission service
considerations, and asset exchanges. The parties entered into this Term Sheet after 1) jointly
funding the permitting of the B2H project over the past decade, and 2) over two years of
discussions related to next steps associated with the B2H project. Since signing the B2H Permit
Funding Agreement in 2012, a decade has passed, and the parties’ capacity needs, strategies,
and goals associated with the project have shifted. The three parties negotiated the Term Sheet
as the framework for future agreements required between and among the parties.
As part of the Term Sheet, BPA will transition out of its role as a joint B2H permitting partner
and will instead take transmission service from Idaho Power to serve its southeast Idaho
customers. Idaho Power will increase its B2H ownership to 45.45% by acquiring BPA’s
planned share of B2H capacity. Idaho Power’s B2H capacity will increase from an average of
350 megawatts (MW) west-to-east to 750 MW west-to-east, and Idaho Power will utilize a
portion of its increased B2H capacity to provide BPA transmission service across
southern Idaho.
As part of the larger transaction, Idaho Power and PAC plan to complete an asset exchange to
align transmission ownership with each party’s long-term strategy. Idaho Power will acquire
PAC transmission assets and their related capacity sufficient to enable Idaho Power to utilize
200 MW of bidirectional transmission capacity between the Idaho Power system (Populus)
and Four Corners substation in New Mexico. Idaho Power will also acquire PAC assets around
the Goshen area necessary to provide transmission service to BPA to serve its southeast Idaho
customers. PAC will acquire Idaho Power transmission assets and their related capacity
sufficient to enable PAC to utilize 600 MW of east-to-west and 300 MW of west-to-east
transmission capacity across southern Idaho.
In the 2021 IRP, Idaho Power estimates that its 45.45% share of B2H costs will be approximately
$500 million (with no contingency) and evaluated a high-end cost of $600 million with a 30%
Executive Summary
Page 2 2021 Integrated Resource Plan—Appendix D
cost contingency for future expenses. The B2H cost estimate included Idaho Power’s costs for
local interconnection upgrades totaling approximately $35 million and additional system
upgrades totaling approximately $47 million.
B2H Background and Purpose
B2H is a planned 500 kilovolt (kV) transmission project that will span between the Hemingway
500 kV substation near Melba, Idaho, and the proposed Longhorn Station near Boardman,
Oregon. Once operational, B2H will provide Idaho Power increased access to reliable, low-cost
market energy purchases from the Pacific Northwest year-round, including when energy
demand from Idaho Power’s customers is at its highest. B2H has been a cost-effective resource
identified in each of Idaho Power’s IRPs since 2009 and continues to be a cornerstone of
Idaho Power’s 2021 IRP Preferred Portfolio. In the 2021 IRP, as has been the case in prior IRPs,
the B2H project is not simply evaluated as a transmission line, but rather as a resource that will
be used to serve Idaho Power load. That is, the B2H project, and the market purchases it will
facilitate, is evaluated in the same manner as a new gas plant, or a new
utility-scale solar plus storage project.
As a resource, the B2H project is demonstrated to be the most cost-effective method of serving
projected customer demand. As can be seen in the 2021 IRP, the lowest-cost resource portfolio
includes B2H, and the best non-B2H portfolio has a significant cost premium. As a resource
alone, B2H is the lowest-cost alternative to serve Idaho Power’s customers in Oregon and
Idaho. As a transmission line, B2H also offers incremental ancillary benefits and additional
operational flexibility.
In addition to being the least-cost resource to meet Idaho Power’s resource needs, the B2H
project received national recognition for the benefits it will provide. The B2H project was
selected by the Obama administration as one of seven nationally significant transmission
projects that, when built, will help increase electric reliability, integrate new renewable energy
into the grid, create jobs, and save consumers money. B2H was also acknowledged as
complementing the Trump Administration’s America First Energy Plan, which addresses all
forms of domestic energy production. In a November 17, 2017, United States Department of
the Interior press release,1 B2H was held up as a “priority focusing on infrastructure needs that
support America’s energy independence.” The release went on to say, “This project will help
stabilize the power grid in the Northwest, while creating jobs and carrying low-cost energy to
the families and businesses who need it.” Finally, B2H was identified by Americans for a Clean
Energy Grid as one of 22 high-voltage transmission projects that “could interconnect around
60,000 MW of new renewable capacity, increasing America’s wind and solar generation by

1 blm.gov/press-release/doi-announces-approval-transmission-line-project-oregon-and-idaho
Executive Summary
2021 Integrated Resource Plan—Appendix D Page 3
nearly 50% from current levels.2” The benefits B2H is expected to bring to the region and nation
have been recognized across both major political parties.3
Idaho Power is the project manager for the permitting phase of the B2H project. The B2H
project achieved a major milestone nearly ten years in the making with the release of the
Bureau of Land Management (BLM) Record of Decision (ROD) on November 17, 2017,
approving a right-of-way for the B2H project on BLM-administered land. Idaho Power also
received a ROD for B2H from the United States Forest Service in 2018 and from the United
States Navy in 2019. In 2021, the RODs issued by the BLM and the Forest Service were upheld
by the United States District Court for the District Court of Oregon. No parties appealed
that ruling.
For the State of Oregon permitting process, Idaho Power submitted the amended application
for Site Certificate to the Oregon Department of Energy (ODOE) in the summer of 2017. ODOE
issued a Proposed Order on July 2, 2020, that recommends approval of the project to Oregon’s
Energy Facility Siting Council (EFSC). Currently, EFSC is conducting a contested case proceeding
on the Proposed Order. EFSC is tasked with establishing siting standards for energy facilities in
Oregon and ensuring certain transmission line projects, including B2H, meet those standards.4
Before Idaho Power can begin construction on B2H, it must obtain a Site Certificate from EFSC.
The Oregon EFSC process is a standards-based process based on a fixed site boundary. For a
linear facility, like a transmission line, the process requires the transmission line boundary be
established (a route selected) and fully evaluated to determine if the project meets established
standards. Idaho Power must demonstrate a need for the project before EFSC will issue a Site
Certificate authorizing the construction of a transmission line (non-generating facility).
Idaho Power’s demonstration of need is based in part on the least-cost plan rule, for which the
requirements can be met through a commission acknowledgement of the resource in the
company’s IRP.5 The Oregon Public Utility Commission (OPUC) has already acknowledged the
construction of B2H in Idaho Power’s 2017 IRP and 2019 IRP. In this case, Idaho Power again
seeks to confirm its acknowledgement of B2H as reflected in the 2021 IRP.

2 See https://cleanenergygrid.org/wp-content/uploads/2021/09/Transmission-Projects-Ready-to-Go.pdf.
3 The importance of high-voltage transmission to a decarbonized future continues to receive attention from
experts and scholars alike. In 2021, Princeton University published the Net-zero America Report, which asserts
that the United States will need to expand its high voltage transmission system by 60% by 2030, and may need
to triple it by 2050 to meet net zero futures.
https://www.dropbox.com/s/ptp92f65lgds5n2/Princeton%20NZA%20FINAL%20REPORT%20(29Oct2021).pdf?dl=0
4 See generally Oregon Revised Statute (ORS) 469.300-469.563, 469.590-469.619, and 469.930-469.992.
5 OAR 345-023-0020(2). Idaho Power is also requesting satisfaction of the need standard under EFSC’s System
Reliability Rule, OAR 345-023-0030.
Executive Summary
Page 4 2021 Integrated Resource Plan—Appendix D
As of the date of this report, Idaho Power expects ODOE to issue its decision on the Site
Certificate in 2022. To achieve a 2026 in-service date, as shown in the near-term Action Plan,
preliminary construction activities have commenced in parallel to EFSC permitting activities.
Preliminary construction activities include, but are not limited to: geotechnical explorations,
detailed ground surveys, sectional surveys, right-of-way (ROW) option acquisition activities,
detailed design, and construction bid package development. After the Oregon permitting
process and preliminary construction activities conclude, construction activities can commence.
Gateway West Considerations in the 2021 IRP
In the 2021 IRP, Idaho Power performed extensive evaluations on the Gateway West project.
The project was ultimately not included as part of the 2021 IRP Preferred Portfolio; however,
many portfolios, including most portfolios that did not include B2H, identified at least one
phase of Gateway West as being necessary to facilitate the large renewable buildouts required.
Idaho Power expects that resource development in southern Idaho by the company, or other
third-party’s, and geographically diverse resource adequacy needs will drive the need for
Gateway West in the coming years. The company will continue to evaluate Gateway West in
future IRPs.
Existing Transmission Utilized for Firm Imports
As detailed in the 2021 IRP Report Chapter 11–Transmission Market Shifts and Constraints,
Idaho Power has reduced the existing transmission assumed available for market purchases
within the Load and Resource Balance from approximately 900 MW in the 2019 IRP to
approximately 710 MW in the 2021 IRP during the peak-load month of July.
The company decreased this availability due to transmission constraints and the company’s
decreasing ability to access markets. Since the August 2020 energy emergency event in
California, the Idaho Power transmission service queue has been flooded with multi-year
requests totaling more than 1,000 MW as of April 2021, looking to move energy from the
Mid-Columbia market (Mid-C) across Idaho Power’s transmission system to the south.
While the company is able to reserve its own transmission for use by its customers,
the transmission service requests just outside of Idaho Power’s service area have placed
additional pressure on an already constrained market, limiting the company’s access to capacity
at Mid-C. The company also began to secure long-term rights across other transmission
providers, and by summer 2023, the company will have added 380 MW of long-term firm
transmission rights across third-party systems to the company’s border. The company sought to
purchase more additional firm transmission capacity, but it was not available. These 380 MW,
in addition to the company’s 330 MW emergency transmission capacity (capacity benefit
margin), account for the 710 MW available for July market purchases across existing
transmission in the 2021 IRP.
Executive Summary
2021 Integrated Resource Plan—Appendix D Page 5
More information about existing transmission availability assumptions can be found in
the Transmission Capacity Between Idaho Power and the Pacific Northwest section of
this appendix.
2022 Term Sheet and B2H Project Partner Update
Page 6 2021 Integrated Resource Plan—Appendix D
2022 TERM SHEET AND B2H PROJECT PARTNER UPDATE
The 2022 B2H Term Sheet and the 2021 IRP
The B2H Term Sheet items reflected below were all factored into the development and
execution of Idaho Power’s 2021 IRP.
B2H Related Terms
The B2H project is moving into the preliminary construction phase. On January 18, 2022,
and after significant discussions, study efforts, and negotiations, the three B2H permit funding
parties, Idaho Power, PAC, and BPA, executed a Non-Binding Term Sheet that addresses B2H
ownership, transmission service considerations, and asset exchanges. The parties entered into
this Term Sheet after 1) jointly permitting the B2H project over the past decade, and 2) over
two years of discussions related to next steps associated with the B2H project. A decade has
passed since signing of the B2H Transmission Project Joint Permit Funding Agreement in 2012,
and the parties’ capacity needs, strategies, and goals associated with the project have shifted.
The three parties negotiated the Term Sheet as the framework for future agreements required
between and among the parties.
Per the Term Sheet, BPA will transition out of its role as a joint B2H permit funding
coparticipant and will instead rely on B2H by taking transmission service from Idaho Power to
serve its customers. To accommodate this change, Idaho Power will increase its B2H ownership
share to 45.45% by acquiring BPA’s B2H capacity. Idaho Power’s B2H capacity will increase from
an average of 350 MW west-to-east to 750 MW west-to-east and Idaho Power will utilize a
portion of its increased B2H capacity to provide BPA network transmission service across
southern Idaho.
PAC’s B2H interest is not impacted by BPA transitioning out of the project and their B2H
capacity will remain at 300 MW west-to-east and 600 MW east-to-west.
There remains 400 MW of unallocated B2H east-to-west capacity.
Idaho Power and BPA Terms
B2H Development Risk: The Term Sheet reflects BPA’s intent to transition out of its role as a
joint B2H permitting partner and to rely on the completed B2H project to take transmission
service from Idaho Power to serve its customers in southeast Idaho. The Term Sheet adjusts the
funding and ownership percentages as follows:
• In addition to its current 21% ownership, Idaho Power will assume BPA’s 24% ownership
share in B2H; and Idaho Power will provide transmission service across southern Idaho
to BPA’s customers through Network Integration Transmission Service Agreements
2022 Term Sheet and B2H Project Partner Update
2021 Integrated Resource Plan—Appendix D Page 7
(NITSA) under Idaho Power’s Open Access Transmission Tariff. These NITSAs will remain
in effect for a minimum 20-year period.
• In concert with the NITSAs, Idaho Power will acquire BPA’s B2H permitting interest and,
on a going-forward basis, will fund 45% of B2H project development costs for permitting
and pre-construction. In the event Idaho Power is unable to secure B2H permits or state
Certificates of Public Convenience and Necessity, BPA will compensate Idaho Power for
24% (based on BPA’s funding obligations before the transfer of BPA’s permitting interest
to Idaho Power) of the permitting and preconstruction costs incurred after BPA’s
interest transfers to Idaho Power.
Permitting Cost Reimbursement: In concert with the NITSAs, starting ten years after B2H is
placed in service, Idaho Power will reimburse BPA for the value of the permitting costs paid by
BPA. Interest will accumulate on the permitting balance starting on the B2H in-service date.
BPA Wheeling Revenue will Offset BPA Related Costs: BPA’s transmission service payments to
Idaho Power under the NITSAs will offset Idaho Power’s costs associated with BPA’s usage of
the B2H project over time, and, therefore, Idaho Power’s customers will not be harmed by the
changes to the arrangement.
Idaho Power Wheeling Across BPA Transmission: In a related transaction, Idaho Power will
secure 500 MW of point-to-point transmission service (PTP) from BPA from the Mid-Columbia
market (Mid-C) to the proposed Longhorn Station, which will provide Idaho Power a direct
connection to the Mid-C market with flexible long-term BPA wheeling rights.
Longhorn Station Terms
The B2H project will interconnect with the proposed BPA Longhorn Station near Boardman,
Oregon, which BPA will own and operate. BPA is in the process of evaluating the construction of
the proposed Longhorn Station to satisfy an interconnection request of a BPA customer and
anticipates making a decision regarding its construction later in 2022.
Funding the Longhorn Station: Under the Term Sheet, BPA will fund Idaho Power’s share,
about $14 million, of the interconnection costs to the proposed Longhorn Station.
Funding of the B2H Connection to Longhorn: Idaho Power and PAC will fund assets and
associated costs, to be reimbursed by BPA, that are required to directly connect B2H to the
Longhorn Station. BPA will satisfy its reimbursement obligations to Idaho Power via
transmission service credits associated with Idaho Power’s 500 MW of PTP service across BPA
from Mid-C to Longhorn Station.
Funding the B2H Series Capacitor at Longhorn: Idaho Power and PAC will fund and own the
B2H series capacitor and associated equipment at Longhorn Station. Idaho Power and/or PAC
2022 Term Sheet and B2H Project Partner Update
Page 8 2021 Integrated Resource Plan—Appendix D
will have access to the Longhorn Station to perform maintenance and inspections on jointly
owned equipment in the Longhorn Station.
Idaho Power and PAC Terms
In addition to the transactions directly related to construction and operation of B2H,
Idaho Power and PAC have agreed to exchange certain assets and take other actions as follows
upon completion of B2H, conditioned on reaching definitive agreements:
Idaho Power Assets to be Acquired from PAC: Idaho Power will acquire PAC transmission
assets and their related capacity sufficient to enable Idaho Power to utilize 200 MW of
bidirectional transmission capacity between the Idaho Power system (Populus Substation in
Idaho) and Four Corners Substation in New Mexico. Idaho Power will also acquire PAC assets
around the Goshen, Idaho, area necessary to provide transmission service to BPA to serve their
southeast Idaho customers.
PAC Assets to be Acquired from Idaho Power: PAC will acquire Idaho Power transmission
assets and their related capacity sufficient to enable PAC to utilize 600 MW of east-to-west and
300 MW of west-to-east transmission capacity across southern Idaho.
PAC Point-to-Point Contracts: PAC will terminate its existing 510 MW of
east-to-west transmission service across southern Idaho Power and acquire 300 MW of
west-to-east conditional firm service. To achieve the 300 MW of west-to-east service, PAC will
obtain (through reassignment) BPA’s 200 MW of PTP west-to-east conditional firm service
across southern Idaho. PAC has procured 100 MW of incremental west-to-east conditional firm
service from Idaho Power across southern Idaho.
Additional Upgrades Required: Transmission capacity on the Idaho Power operated Borah
West and Midpoint West transmission paths must be upgraded to support additional
east-to-west schedules required by Idaho Power and PAC across southern Idaho. There are two
system upgrade projects identified to reinforce Borah West and Midpoint West to enable these
increased east-to-west transmission flows through Idaho:
1. Midpoint-Kinport 345 kV Series Capacitor Addition: The addition of a series capacitor on
the existing Midpoint–Kinport 345 kV line will increase the Borah West path rating by
approximately 500 MW. This series capacitor allows for more optimal distribution of
flows on the existing 345 kV lines west of Borah Station near American Falls, Idaho.
2. Midpoint 500/345 kV Second Transformer Addition: The existing single 500/345 kV
transformer bank is a bottleneck for increased flows across the Idaho system. A second
500/345 kV transformer will need to be installed to increase the capacity of the existing
2022 Term Sheet and B2H Project Partner Update
2021 Integrated Resource Plan—Appendix D Page 9
Midpoint–Hemingway 500 kV line to accommodate higher east-to-west transfers across
southern Idaho.
In the 2021 IRP, Idaho Power conservatively assumed that the full cost (about $47 million)
of these upgrades will be funded by the company. The actual cost responsibility will be
determined as Idaho Power and PAC perform detailed analysis associated with the
asset exchange.
B2H Revised Scope–Midline Series Capacitor
Idaho Power and PAC will construct a B2H midline series capacitor substation around the
mid-point of the B2H transmission line. This midline series capacitor—identified through joint
planning studies by Idaho Power, PAC, and BPA—is required to address interactions between
B2H and other existing transmission paths and to meet the three parties’ needs. This midline
substation was not included in the original project scope and will require additional permitting.
It is anticipated that this additional permitting will not delay the B2H in-service date.
Idaho Power’s Transmission System
Page 10 2021 Integrated Resource Plan—Appendix D
IDAHO POWER’S TRANSMISSION SYSTEM
Idaho Power’s transmission system is a critical component of Idaho Power’s system enabling
Idaho Power to provide reliable and fair-priced energy services. A map of Idaho Power’s
transmission system is shown in Figure 7.1 of the 2021 IRP and in Figure 1 of this appendix.
Transmission lines facilitate the delivery of economic resources and allow resources to be sited
where most cost effective. In most instances, the most economic/best location for resources is
not immediately next to major load centers (i.e., hydro along the Snake River, wind in
Wyoming, solar in the Desert Southwest). For much of its history, Idaho Power has relied upon
resources outside of its major load pockets to economically serve its customers. The existing
transmission lines between Idaho Power and the Pacific Northwest have been particularly
valuable. Idaho Power fully utilizes the capacity of these lines. Additional transmission capacity
is required to access resources to serve incremental increases in peak demand. The B2H project
is the mechanism to increase capacity between the Pacific Northwest and Idaho Power’s
service area.
Transmission lines are constructed and operated at different operating voltages depending on
purpose, location and distance. Idaho Power operates transmission lines at 138 kV,
161 kV, 230 kV, 345 kV, and 500 kV. Idaho Power also operates sub-transmission lines at 46 kV
and 69 kV. The higher the voltage, the greater the capacity of the line, but also greater
construction cost and physical size requirements.
The utility industry often compares transmission lines to roads and highways.
Typically, lower-voltage transmission lines (such as 138 kV) are used to facilitate delivery of
energy to substations to serve load, like a two-lane highway, while high-voltage transmission
lines are used for bulk transfer of energy from one region to another, like an interstate
highway. Much like roads and highways, transmission lines can become congested.
Depending on the capacity needs, economics, distance, and intermediate substation
requirements, either 230 kV, 345 kV, or 500 kV transmission lines are chosen.
Transmission Market Shifts and Constraints
As discussed in the Transmission Market Shifts and Constraints section of Chapter 11 of the
2021 IRP, starting on page 168, the company made significant adjustments to its transmission
availability assumptions.
As a result of recent and significant market changes, for the years 2023 through 2025,
Idaho Power has reduced the transmission availability within the Load and Resource Balance
from approximately 900 MW in the 2019 IRP to approximately 710 MW in the 2021 IRP during
the peak-load month of July. The following sections detail the makeup of this 710 MW.
Idaho Power’s Transmission System
2021 Integrated Resource Plan—Appendix D Page 11
Idaho Power’s Existing Transmission Capacity
A transmission path is one or more transmission lines that collectively transmit power to and
from one geographic area to another.
Idaho to Northwest Path Description
Idaho Power owns 1,280 MW of transmission capacity between the Pacific Northwest
transmission system and Idaho Power’s transmission system. Of this capacity, 1,200 MW are on
the Idaho to Northwest path (Western Electricity Coordinating Council [WECC] Path 14),
and 80 MW are on the Montana–Idaho path (WECC Path 18). The Idaho to Northwest
transmission path is comprised of three 230 kV lines, one 500 kV line, and one 115 kV line.
The capacity limit on the path is established through a WECC rating process based on
equipment overload ratings resulting from the loss of the most critical element on the
transmission system. Collectively, these lines between Idaho and the Northwest have a transfer
capacity rating that is greater than the individual rating of each line but less than the sum of
the individual capacity ratings of each line. Figure 1 shows an overview of Idaho Power’s
high-voltage transmission system.
Figure 1. Idaho Power transmission system map
Idaho Power’s Transmission System
Page 12 2021 Integrated Resource Plan—Appendix D
Table 1 details the capacity allocation between the Pacific Northwest and Idaho Power in 2021.
The shaded rows represent capacity amounts that can be used to serve Idaho Power’s native
load customers, although Capacity Benefit Margin (CBM) can only be accessed as firm capacity
if Idaho Power is in an energy emergency.
Table 1. Pacific Northwest to Idaho Power west-to-east transmission capacity
Firm Transmission Usage (Pacific Northwest to Idaho Power) Capacity (July MW)
BPA Load Service (Network Customer) 332
Fighting Creek (PURPA) 4
Transmission Reliability Margin (TRM) 281
Capacity Benefit Margin (CBM) 330
Subtotal 947
Pacific Northwest Purchase (Idaho Power Load Service) 333
Total 1,280
Montana–Idaho Path Utilization
Idaho Power’s share of the Montana–Idaho path includes 80 MW of capacity on a 230 kV line
interconnecting with BPA or Avista and a 161 kV line interconnecting with Northwestern
Energy. The 161 kV line is not included in the total Pacific Northwest to Idaho Power import
capacity due to commercial constraints beyond the Idaho Power border. To utilize the 80 MW
capacity connection, Idaho Power must purchase transmission service from either Avista or
BPA. This transmission system connects the purchased resource in the Pacific Northwest to
Idaho Power’s transmission system. Avista or BPA transmits, or wheels, the power across
their transmission system and delivers the power to Idaho Power’s transmission system.
The Montana–Idaho path is identified in Figure 1 above.
Idaho to Northwest Path Utilization
To use Idaho Power’s share of the Idaho to Northwest capacity, Idaho Power must purchase
transmission service from Avista, BPA, or PAC. Table 2 details a typical summer allocation of the
Idaho to Northwest capacity:
Table 2. The Idaho to Northwest Path (WECC Path 14) summer allocation
Transmission Provider Idaho to Northwest Allocation (Summer West-to-East) (MW)
Avista (to Idaho Power) 340
BPA (to Idaho Power) 350
PAC (to Idaho Power) 510
Total Capability to Idaho Power 1,200*
* During times of very low generation at Brownlee, Oxbow, and Hells Canyon hydro plants, the Idaho to Northwest path total capability can
increase to as much as 1,340 MW; low generation at these power plants does not correspond with Idaho Power’s system peak.
Idaho Power’s Transmission System
2021 Integrated Resource Plan—Appendix D Page 13
Avista, BPA, and PAC share an allocation of capacity on the western side of the Idaho to
Northwest path, and Idaho Power owns 100% of the capacity on the eastern side of the Idaho
to Northwest path. For Idaho Power to transact across the path and serve customer load,
Idaho Power’s Load Servicing Operations must purchase transmission service from Avista,
BPA, or PAC to connect the selling entity, via a contract transmission path, to Idaho Power.
Construction of B2H will add 1,050 MW of capacity to the Idaho to Northwest path in the
west-to-east direction, of which Idaho Power will own 750 MW and plans to utilize 500 MW the
summer months (April–September) and 200 MW in the winter months (January–March and
October–December) for Idaho Power customer service. The remainder of the Idaho Power
capacity will mainly be used for incremental network transmission service to BPA southeast
Idaho customers. A total breakdown of capacity rights of the B2H permitting coparticipants can
be found in the B2H Capacity Interest section of this report. The Idaho to Northwest path is
identified in Figure 1 above.
Transmission Capacity to the South
Referencing Figure 1, the company owns or controls transmission capacity between utilities in
the south, and Idaho Power via the Idaho–NV Energy path (aka Idaho–Sierra path or WECC Path
16) and Path C (WECC Path 20).
Idaho Power utilizes the Idaho–NV Energy path to import Valmy energy, and the path rating is
360 MW in the south-to-north direction. There is no firm transmission availability across
Nevada to leverage this 360 MW of import capacity to access Desert Southwest markets.
PAC is the owner and operator of the Path C transmission lines. Idaho Power has secured
50 MW of transmission capacity between the months of June and October to access the Desert
Southwest markets. This 50 MW makes up a part of the 2021 IRP’s approximately 710 MW of
transmission capacity detailed in the Load and Resource Balance.
Transmission in the 2021 IRP Load and Resource Balance
Due to the market shifts referenced in the Transmission Market Shifts and Constraints
section, transmission capacity has been constrained. Table 3 details the amount of Mid-C to
Idaho Power and Desert Southwest to Idaho Power capacity to which the company will have
rights by 2023.
Idaho Power’s Transmission System
Page 14 2021 Integrated Resource Plan—Appendix D
Table 3. Third-party secured import transmission capacity
Third-Party Provider Market Capacity (MW)
Avista via Lolo Pacific Northwest 200
PAC via Walla Walla Pacific Northwest 80
BPA via La Grande Pacific Northwest 50
PAC via Red Butte (Utah/Nevada border) Desert Southwest 50
Subtotal 380
Emergency Transmission (CBM) Pacific Northwest 330
Total 710

The B2H project will add 750 MW of Idaho Power owned transmission capacity between BPA
and Idaho Power. Additionally, Idaho Power plans to secure 500 MW of point-to-point
transmission service across BPA’s transmission system to connect B2H to the Mid-C market
hub. As part of the Term Sheet, Idaho Power will also acquire from PAC 200 MW of
south-to-north transmission ownership from the Desert Southwest market hub (Four Corners)
to the Idaho Power system. However, Idaho Power did not specifically allocate any
incremental summer capacity associated with the Four Corners capacity into the Load and
Resource Balance.
More Details Related to CBM: CBM is transmission capacity Idaho Power sets aside on the
company’s transmission system, as unavailable for firm use, for the purposes of accessing
reserve energy to recover from severe conditions such as unplanned generation outages or
energy emergencies. Reserve generation capacity is critical and CBM allows a utility to reduce
the amount of reserve generation capacity on its system by providing transmission availability
to another market, in this case the Pacific Northwest. An energy emergency must be declared
by Idaho Power before the CBM transmission capacity becomes firm. To access the market,
transmission beyond Idaho Power on third party providers must be acquired. The company
anticipates this third-party transmission will be available during an energy emergency event.
Idaho Power includes the 330 MW of emergency transmission (CBM) toward meeting a 15.5%
planning margin. In future IRP’s, Idaho Power will continue to evaluate how CBM applies in the
context of Idaho Power’s Load and Resource Balance, specifically if the company is a member of
a regional resource adequacy program.
More Details Related to TRM: TRM is transmission capacity that Idaho Power sets aside as
unavailable for firm use, for the purposes of grid reliability to ensure a safe and reliable
transmission system. Idaho Power’s TRM methodology, approved by the Federal Energy
Regulatory Commission (FERC) in 2002, requires Idaho Power to set aside transmission capacity
based on the average loop flow on the Idaho to Northwest path. In the west, electrical power is
scheduled through a contract-path methodology, which means if 100 MW is purchased and
Idaho Power’s Transmission System
2021 Integrated Resource Plan—Appendix D Page 15
scheduled over a path, that 100 MW is decremented from the path’s total availability.
However, physics dictates the actual power flow over the path (based on the path of least
resistance), so actual flows don’t equal contract-path schedules. The difference between
scheduled and actual flow is referred to as unscheduled flow or loop flow. The average adverse
loop flow across the Idaho to Northwest path during the month of July is 281 MW.
Regional Planning—Studies and Conclusions
Idaho Power is active in NorthernGrid, a regional transmission planning association of 13
member utilities. The NorthernGrid was formed in early 2020. Previously, dating back to 2007,
Idaho Power was a member of the Northern Tier Transmission Group. NorthernGrid operates in
compliance with FERC Orders 890 and 1000.
NorthernGrid membership includes Avista, Berkshire Hathaway Energy Canada, BPA, Chelan
County Public Utility District (PUD), Grant County PUD, Idaho Power, NorthWestern Energy,
NV Energy, PAC (Rocky Mountain Power and Pacific Power), Portland General Electric,
Puget Sound Energy, Seattle City Light, Snohomish County PUD, and Tacoma Power.
Biennially, NorthernGrid will develop a regional transmission plan using a public stakeholder
process to evaluate transmission needs resulting members’ load forecasts; local transmission
plans; IRPs; generation interconnection queues; other proposed resource development and
forecast uses of the transmission system by wholesale transmission customers. The 2020–2021
regional transmission plan was published in December 2021 and can be found in the
NorthernGrid website: northerngrid.net.
B2H is a regionally significant project; it was identified as a key transmission component of each
Northern Tier Transmission Group biennial regional transmission plan for 10 years 2010–2019.
The B2H project is similarly a major component of the 2020–2021 NorthernGrid regional
transmission plan, published in December 20216. Regional transmission planning efforts are
widely regarded as producing efficient and cost-effective pathways to meet the load and
resource needs of a region.

6 See https://www.northerngrid.net/private-media/documents/2020-2021_Regional_Transmission_Plan.pdf
B2H Development
Page 16 2021 Integrated Resource Plan—Appendix D
B2H DEVELOPMENT
For details related to B2H project history, public participation, project activities, route history,
and a detailed list of notable project milestones, please reference Appendix D-2 at the end of
this Appendix.
B2H Design
B2H is routed and designed to withstand catastrophic events, including, but not limited to,
the following:
• Lightning
• Earthquake
• Fire
• Wind/tornado
• Ice
• Landslide
• Flood
• Direct physical attack
The following sections provide more information about the design of the B2H transmission line
and address each of the catastrophic events listed above.
Transmission Line Design
The details below are not inclusive of every design aspect of the transmission line but provide a
brief overview of the design criteria. The B2H project will be designed and constructed to meet
or exceed all required safety and reliability criteria.
The basic purpose of a transmission line is to move power from one substation to another for
eventual distribution of electricity to end users. The basic components of a transmission line
are the structures/towers, conductors, insulators, foundations to support the structures,
and shield wires to prevent lighting from striking conductors. See Figure 2 for a cross-section of
a transmission line.
For a single-circuit transmission line, such as B2H, power is transmitted via three-phase
conductors (a phase can also have multiple conductors, called a bundle configuration).
These conductors are typically comprised of a steel core to give the conductor tensile strength
and reduce sag and of aluminum outer strands. Aluminum is used because of its high
conductivity to weight ratio.
B2H Development
2021 Integrated Resource Plan—Appendix D Page 17
Shield wires, typically either steel or aluminum and occasionally including fiber optic cables
inside for communication, are the highest wires on the structure. Their main purpose is to
protect the phase conductors from a lightning strike.
Structures are designed to
support the phase conductors and
shield wires and keep them safely
in the air. For the B2H project,
structures were chosen to be
primarily steel lattice tower
structures, which provide an
economical means to support
large conductors for long spans
over long distances.7 The typical
structure height for B2H is
approximately 135 feet tall
(structure height will vary
depending on location) with a
structure located roughly every
1,400 feet on average. The tower
height and span length were
optimized to minimize ground
impacts and material
requirements; taller structures
could allow for longer spans
(fewer structures on average per
mile) but would be costlier due to
material requirements. Again, the B2H
tower and conductors were engineered to maximize benefits and minimize costs and impacts.
Transmission Line Structural Loading Considerations
Reliability and resiliency are designed into transmission lines. Overhead transmission lines have
been in existence for over 100 years, and many codes and regulations govern the design and
operation of transmission lines. Safety, reliability, and electrical performance are all
incorporated into the design of transmission lines. Idaho Power’s Energy Facility Siting

7 H-frame towers, rather than lattice towers, will be used in certain locations to mitigate scenic impacts.
Figure 2.

B2H Development
Page 18 2021 Integrated Resource Plan—Appendix D
Council (EFSC) application includes an exhaustive list of standards. Several notable standards
are as follows:
• American Concrete Institute 318—Building Code Requirements for Structural Concrete
• American National Standards Institute (ANSI) standards (for material specs)
• American Society of Civil Engineers (ASCE) Manual No.74—Guidelines for Electrical
Transmission Line Structural Loading
• National Electrical Safety Code (NESC)
• Occupational Safety and Health Administration (OSHA) 1910.269 April 11, 2014
(for worker safety requirements)
• National Fire Protection Association (NFPA) 780—Guide for Improving the Lightning
Performance of Transmission Lines
NESC provides for minimum guidelines and industry standards for safeguarding persons from
hazards arising from the construction, maintenance, and operation of electric supply and
communication lines and equipment. The B2H project will be designed, constructed,
and operated at standards that meet, and in most cases, exceed, the provisions of NESC.
Physical loads induced onto transmission structures and foundations supporting the phase
conductors and shield wires for the B2H project are derived from three phenomena:
wind, ice, and tension. Under certain conditions, ice can build up on phase conductors and
shield wires of transmission lines. When transverse wind loading is also applied to these iced
conductors, it can produce structural loading on towers and foundations far greater than
normal operating conditions produce. Design weather cases for the B2H project exceed the
requirements in the NESC. As an example, for a high wind case, NESC recommends 90 miles per
hour (mph) winds. The criteria proposed for this project is 100 mph wind on the conductors and
120 mph wind on the structures. There are multiple loading conditions that will be incorporated
into the design of the B2H project, including unbalanced longitudinal loads, differential ice
loads, broken phase conductors, broken sub-phase conductors, heavy ice loads, extreme wind
loads, extreme ice and wind loads, construction loads, and full dead-end structure loads.
Transmission Line Foundation Design
The 500 kV single-circuit lattice steel structures require a foundation for each leg of the
structure. The foundation diameter and depth shall be determined during final design and are
dependent on the type of soil or rock present. The foundations will be designed to comply with
the allowable bearing and shear strengths of the soil where placed. Soil borings shall be taken
at key locations along the project route, and subsequent soil reports and investigations shall
govern specific foundation designs as appropriate.
B2H Development
2021 Integrated Resource Plan—Appendix D Page 19
The 2017 NESC Rule 250A4 observes the structure capacity obtained by designing for NESC
wind and ice loads at the specified strength requirements is sufficient to resist earthquake
ground motions. Additionally, ASCE Manual No. 74 states transmission structures need not be
designed for ground-induced vibrations caused by earthquake motion; historically, transmission
structures have performed well under earthquake events,8, 9 and transmission structure
loadings caused by wind/ice combinations and broken wire forces exceed earthquake loads.
It is common industry practice to design transmission line structures to withstand wind and ice
loads that are equal to, or greater, than these NESC requirements.
Lightning Performance
The B2H project is in an area that historically experiences 20 lightning storm days per year.10
This is relatively low compared to other parts of the United States. The transmission line will be
designed to not exceed a lightning outage rate of one per 100 miles per year. This will be
accomplished by proper shield wire placement and structure/shield wire grounding to
adequately dissipate a lightning strike on the shield wires or structures if it were to occur.
The electrical grounding requirements for the project will be determined by performing ground
resistance testing throughout the project alignment, and by designing adequately sized
counterpoise or using driven ground rods with grounding attachments to the steel rebar cages
within the caisson foundations as appropriate.
Earthquake Performance
Experience has demonstrated that high-voltage transmission lines are very resistant to
ground-motion forces caused by earthquake, so much so that national standards do not require
these forces be directly considered in the design. However, secondary hazards can affect a
transmission line, such as landslides, liquefaction, and lateral spreading. The design process
considers these geologic hazards using multiple information streams throughout the siting and
design process. For the current route, Idaho Power evaluated geologic hazards using available
electronic (geographic information system [GIS]) data, such as fault lines, areas of unstable
and/or steep soils, mapped and potential landslide areas, etc. Towers located in potential
geologic hazards are investigated further to determine risk. Additional analysis may include
field reconnaissance to gauge the stability of the area and subsurface investigation to
determine the soil strata and depth of hazard. At the time of this report, no high-risk geologic

8 Risk Assessment of Transmission System under Earthquake Loading. J.M. Eidinger, and L. Kemper, Jr. Electrical
Transmission and Substation Structures 2012, Pg. 183-192, ASCE 2013.
9 Earthquake Resistant Construction of Electric Transmission and Telecommunication Facilities Serving the Federal
Government Report. Felix Y. Yokel. Federal Emergency Management Agency (FEMA). September 1990.
10 USDA RUS Bulletin 1751-801.
B2H Development
Page 20 2021 Integrated Resource Plan—Appendix D
hazard areas have been identified. If—during the process of final design—an area is found to be
high risk, the first option would be to micro-site, route around, or span over the hazard.
If avoidance is not feasible, the design team would seek to stabilize the hazard. Engineering
options for stabilization include designing an array of sacrificial foundations above the tower
foundation to anchor the soil or improving the subsurface soils by injecting grout or outside
aggregates into the ground. If the geotechnical investigation determines the problematic soils
are relatively shallow, the tower foundations can be designed to pass through the weaker soils
and embed into competent soils.
Wildfire
The transmission line steel structures are constructed of non-flammable materials, so wildfires
do not pose a physical threat to the transmission line itself. However, heavy smoke from
wildfires in the immediate area of the transmission line can cause flashover/arcing between the
phase conductors and electrically grounded components. Standard operation is to de-energize
transmission lines when fire is present in the immediate area of the line. Transmission lines
generally remain in-service when smoke is present from wildfires not in the immediate vicinity
of the transmission line. When compared to other resource alternatives, B2H may be more
resilient to smoke. For instance, solar PV is susceptible to smoke, which can move into areas
even if fires are not in the immediate vicinity of the solar generation. For example, the recent
forest fires events in the Pacific Northwest caused heavy smoke along the proposed B2H
corridor and in the Pacific Northwest in general. In the event of heavy smoke, the B2H line
would likely still operate so long as the fires are not in the immediate area, whereas solar PV
would likely operate at a much-reduced capacity.
Idaho Power has developed a Wildfire Mitigation Plan (WMP)11. This plan details how
Idaho Power uses situational awareness of wildfire and weather conditions to change the way
the system is operated. It also includes best practices that internal and contract crews follow
for construction and maintenance activities during wildfire season, vegetation management
practices, system and distribution hardening efforts. B2H has been included in this analysis as
part of the planning process. Idaho Power filed an updated WMP to the OPUC by December 31,
2021, that included a Public Safety Power Shutoff plan and other items required. The updated
plan will also be filed with the IPUC, likely in the first quarter of 2022. This plan will be reviewed
annually and updated with new information and lessons learned as required.

11 docs.idahopower.com/pdfs/Safety/2022Wildfire%20MitigationPlan.pdf
B2H Development
2021 Integrated Resource Plan—Appendix D Page 21
Wind Gusts/Tornados
Tornados are unlikely along the B2H route. As noted in the Transmission Line Structural Loading
Considerations section, the B2H transmission line is designed to withstand extreme wind
loading combined with ice loading.
Ice
Ice formation around the phase conductors and around the shield wires can add a substantial
amount of incremental weight to the transmission line, putting extra force on the steel
structures and foundations. As described in the Transmission Line Structural Loading
Considerations section, the B2H transmission line is designed to withstand heavy ice loading
combined with heavy wind loading.
Landslide
The siting and design process considers geologic hazards, such as landslides, liquefaction,
and lateral spreading. See the Earthquake Performance section. Through the siting and design
process, steep, unstable slopes are avoided, especially where evidence of past landslides is
evident. During the preliminary construction phase, geotechnical surveys and ground surveys
(light detection and ranging [LiDAR] surveys) help verify potentially hazardous conditions. If a
potentially hazardous area cannot be avoided, the design process will seek to stabilize the area.
Flood
The identification and avoidance of flood zones was incorporated into the siting process and
will be further incorporated into the design process. Foundations and structures can be
designed to withstand flood conditions.
Direct Physical Attack
A direct physical attack on the B2H transmission line will remove the line’s ability to deliver
power to customers. In the case of a direct attack, B2H is fundamentally no different than any
other supply-side resource should a direct physical attack occur on a specific resource.
However, because the B2H project is connected to the transmission grid, a direct physical
attack on any specific generation site in the Pacific Northwest or Mountain West region will not
limit B2H’s ability to deliver power from other generation in the region. In this context,
B2H provides additional ability for generation resources to serve load if a physical attack were
to occur on a specific resource or location within the region and therefore increases the
resiliency of the electric grid as a whole.
If a direct physical attack were to occur on the B2H transmission line and force the line out of
service, the rest of the grid would adjust to account for the loss of the line. Per the WECC
facility rating process, the B2H capacity rating is such that an outage of the B2H line would not
B2H Development
Page 22 2021 Integrated Resource Plan—Appendix D
overload any other system element beyond equipment emergency ratings. Idaho Power also
keeps a supply of emergency transmission towers that can be very quickly deployed to replace
a damaged tower allowing the transmission line to be quickly returned to service.
B2H Design Conclusions
As evidenced in this section, the B2H project is designed to withstand a wide range of physical
conditions and extreme events. Because transmission lines are so vital to our electrical grid,
design standards are stringent. B2H will adhere to, and in most cases, exceed, the required
codes or standards observed for high voltage transmission line design. This approach to the
design, construction, and operation of the B2H project will establish utmost reliability for the
life of the transmission line. Additionally, as discussed in the Direct Physical Attack section,
transmission lines add to the resiliency of the grid by providing additional paths for electricity
should one or more generation resources or transmission lines experience a catastrophic event.
B2H Capacity Interest
At the beginning of 2022, Idaho Power, PAC, and BPA executed a Non-Binding Term Sheet that
addresses B2H ownership, transmission service considerations, and asset exchanges. As part of
the Term Sheet, BPA will transition out of its role as a joint B2H permitting partner and will
instead take transmission service from Idaho Power to serve its customers. Idaho Power will
increase its B2H ownership to 45.45% by acquiring BPA’s B2H capacity and will utilize a portion
of this increased capacity to provide BPA transmission service across southern Idaho.
In the 2021 IRP, the company modeled B2H assuming the company’s Term Sheet specified
45.45% project ownership share.
The Term Sheet defines Idaho Power and PAC’s capacity interests in the B2H project and is
representative of how Idaho Power studied B2H in the 2021 IRP. Table 4 details the B2H
capacity interests of PAC and Idaho Power.
Table 4. B2H Term Sheet capacity interests
Capacity Interest
(West-to-East)
Capacity Interest
(East-to-West)
Ownership %
Idaho Power 750 MW 0 MW 45.45%
PAC 300 MW 600 MW 54.55%
Unallocated 400 MW

Idaho Power plans to have 750 MW of west-to-east capacity and a share of any east-to-west
capacity that is ultimately unallocated—at this time, 45.45% of 400 MW, or 182 MW of
east-to-west capacity associated with B2H. This represents an increase over the 2019 IRP when
Idaho Power’s interest was seasonally shaped, with 500 MW of west-to-east capacity from April
B2H Development
2021 Integrated Resource Plan—Appendix D Page 23
through September, 200 MW of west-to-east capacity from January through March and
October through December, and a reduced share of any unallocated capacity. Focusing on the
west-to-east capacity, the difference between the 2019 IRP and the 2021 IRP represents a
250 MW increase in the summer capacity and a 550 MW increase in the winter capacity.
Idaho Power will provide transmission service to BPA utilizing much of this incremental
capacity. In both the summer and winter seasons, BPA’s load forecast through the 2040 IRP
planning period is less than this incremental capacity.
Capacity Rating—WECC Rating Process
Early in B2H project development, Idaho Power coordinated with other utilities in the Western
Interconnection via a peer-reviewed process known as the WECC Path Rating Process.
Through the WECC Path Rating Process, Idaho Power worked with other western utilities to
determine the maximum rating (power flow limit) across the transmission line under various
stresses, such as high winter or high summer peak load, light load, high wind generation,
and high hydro generation on the bulk power system. Based on industry standards to test
reliability and resilience, Idaho Power simulated various outages, including the outage of B2H,
while modeling these various stresses to ensure the power grid was capable of reliably
operating with increased power flow. Through this process, Idaho Power also ensured the
B2H project did not negatively impact the ratings of other transmission projects in the
Western Interconnection.
Idaho Power completed the WECC Path Rating Process in November 2012 and achieved a WECC
Accepted Rating of 1,050 MW in the west-to-east direction and 1,000 MW in the east-to-west
direction. The B2H project, when constructed, will add significant reliability, resilience, and
flexibility to the Northwest power grid.
B2H Project Coparticipants
PAC and BPA Needs
PAC and BPA are coparticipants in the permitting of the B2H project (also referred to as
funders), with BPA planning to transition out per the Term Sheet discussed previously.
Collectively, Idaho Power, PAC, and BPA represent a very large electric service footprint in the
western US. The fact that three large utilities have each identified the value of the B2H project
indicates the regional significance of the project and the value the project brings to customers
throughout the West. More information about PAC’s and BPA’s needs and interest in the B2H
project can be found in the following sections.
B2H Development
Page 24 2021 Integrated Resource Plan—Appendix D
PAC
The following information was provided by PAC:
PAC is a locally managed, wholly owned subsidiary of Berkshire Hathaway Energy Company.
PAC is a leading western United States energy services provider and the largest single owner of
transmission in the West, serving 1.9 million retail customers in six western states. PAC is
comprised of two business units: Pacific Power (serving Oregon, Washington, and California)
and Rocky Mountain Power (serving Utah, Idaho, and Wyoming). Visit pacificorp.com for
more information.
PAC’s existing transmission path between the two balancing areas (PacifiCorp West [PACW] and
PacifiCorp East [PACE]) consists of a single line (Midpoint, Idaho, to Summer Lake, Oregon)
fully used during key operating periods, including winter peak periods in the Pacific Northwest
and summer peak in the Intermountain West. PAC has invested in the permitting of the B2H
project because of the strategic value of connecting the two regions. As a potential owner in
the project, PAC would be able to use its bidirectional capacity to increase reliability and to
enable more efficient use of existing and future resources for its customers. The following lists
additional B2H benefits:
• Customers: PAC continues to invest to meet customers' needs, making only critical
investments now to ensure future reliability, security, and safety. The B2H project will
bolster reliability, security, and safety for PAC customers as the regional supply mix
transitions.
• Renewables: The B2H project has been identified as a strategic project that can
facilitate the transfer of geographically diverse renewable resources, in addition to
other resources, across PAC’s two balancing authority areas. Transmission line
infrastructure, like B2H, is needed to maintain a robust electrical grid while integrating
clean, renewable energy resources across the Pacific Northwest and Mountain West
states. The PAC 2021 IRP Preferred Portfolio includes substantial new renewables
facilitated by incremental transmission investments, demand-side management (DSM)
resources, and significant storage resources. By the end of 2024, PAC’s preferred
portfolio includes more than 3,000 MW of renewables and nearly 700 MW of battery
storage. At the end of the 20-year planning horizon in 2040, PAC’s 2021 IRP Preferred
Portfolio includes approximately 9,250 MW of new wind and solar. To support the
addition of the new renewable resources typically located remotely from load centers
and retirement of coal resources requires continued investment in a robust transmission
system required to move resources across and between both PAC balancing areas.
• Regional Benefit: PAC, as a past member of the regional planning entity Northern Tier
Transmission Group (NTTG), supported the inclusion of B2H in the NTTG 2018–2019
B2H Development
2021 Integrated Resource Plan—Appendix D Page 25
regional plan. PAC as a current member of the regional planning organization
NorthernGrid has supported the inclusion of B2H into the 2020–2021 regional plan.
From a regional perspective, the B2H project is a cost-effective investment that will
provide regional solutions to identified regional needs. The project resolves possible
system issues as identified in the NTTG 2018–2019 regional plan and the NorthernGrid
2020–2021 regional plan.
• Balancing Area Operating Efficiencies: PAC operates and controls two balancing areas.
After the addition of B2H and portions of Gateway West, more transmission capacity
will exist between PAC's two balancing areas, providing the ability to increase operating
efficiencies. B2H will provide PAC 300 MW of additional west-to-east capability and
600 MW of east-to-west capability to move resources between PAC's two balancing
authority areas.
• Regional Resource Adequacy: PAC is participating in the ongoing effort to evaluate and
develop a regional resource adequacy program with other utilities that are members of
the Northwest Power Pool. The B2H project is anticipated to provide incremental
transmission infrastructure that will broaden access to a more diverse resource base,
which will provide opportunities to reduce the cost of maintaining adequate resource
supplies in the region.
• Grid Resiliency: The Midpoint-to-Summer Lake 500 kV transmission line is the only line
connecting PAC's east and west control areas. The loss of this line has the potential to
reduce transfers by 1,090 MW. When B2H is built, the new transmission line will provide
redundancy by adding an additional 1,000 MW of capacity between the Hemingway
Substation and the Pacific Northwest. This additional asset would mitigate the impact
when the existing line is lost.
• Oregon and Washington Renewable Portfolio Standards and Other State Legislation:
New legislation and rules for recently passed legislation are being developed to meet
state specific policy objectives that are expected to drive the need for additional
renewable resources. As these laws are enacted and rules are developed, PAC will
evaluate how the B2H transmission line can help facilitate meeting state policy
objectives by providing incremental access to geographically diverse renewable
resources and other flexible capacity resources that will be needed to maintain
reliability. PAC believes that investment in transmission infrastructure projects, like B2H
and other Energy Gateway segments, are necessary to integrate and balance
intermittent renewable resources cost effectively and reliably.
• EIM: PAC was a leader in implementing the western energy imbalance market (EIM).
The real-time market helps optimize the electric grid, lowering costs, enhancing
B2H Development
Page 26 2021 Integrated Resource Plan—Appendix D
reliability, and more effectively integrating resources. PAC believes the B2H project
could help advance the objectives of the EIM and has the potential of benefitting PAC
customers and the broader region.
• Grid Reliability: The loss of the Hemingway–Summer Lake 500 kV transmission line,
the only 500 kV connection between the Pacific Northwest and Idaho Power,
during peak summer load is one of the most severe possible contingencies the
Idaho Power transmission system can experience. Once Hemingway–Summer Lake
500 kV disconnects, the transfer capability of the Idaho to Northwest path is reduced by
over 700 MW in the west-to-east direction. After the addition of B2H, there will be two
major 500 kV connections between the Pacific Northwest and Idaho Power.
The Hemingway–Summer Lake 500 kV outage would become much less severe to
Idaho Power’s transmission system. Additionally, loss of the Hemingway–Summer Lake
500 kV line with heavy east-to-west power transfer out of Idaho to the Pacific
Northwest results in significant system impacts. In this disturbance, an existing
remedial action scheme (power system logic used to protect power system equipment)
will disconnect over 1,000 MW of generation at the Jim Bridger Power Plant to reduce
path transfers and protect bulk transmission lines and apparatus. Due to the magnitude
of the generation loss, recovery from this disturbance can be extremely difficult.
After the addition of B2H, this enormous amount of generation shedding will no longer
be required. With two 500 kV lines between Idaho and the Pacific Northwest, the loss of
one can be absorbed by the other. Keeping 1,000 MW of generation on the system for
major system outages is important for grid stability.
BPA
BPA is a nonprofit federal power marketing administration based in the Pacific Northwest.
BPA provides approximately 27% of the electric power used in the Pacific Northwest. BPA also
operates and maintains about three-fourths of the high-voltage transmission in its service area.
BPA’s area includes Idaho, Oregon, Washington, western Montana, and small parts of eastern
Montana, California, Nevada, Utah, and Wyoming. For more information, visit bpa.gov.
On January 19, 2022, BPA sent a letter to the region about B2H. This letter can be found on the
following webpage:
bpa.gov/transmission/CustomerInvolvement/SEIdahoLoadService/Pages/default.aspx
Excerpt from the BPA letter to the region:
The B2H with Transfer Service proposal presents a unique opportunity for BPA
and other regional parties to work collaboratively together to support their
respective goals of delivering firm, reliable, cost-effective power and
B2H Development
2021 Integrated Resource Plan—Appendix D Page 27
transmission service for their customers. The expected benefits of B2H with
Transfer Service to the region in general, and BPA specifically, are multifaceted.
Regionally, B2H would increase the resiliency of the regional transmission
system, including during severe weather conditions and during outages of other
transmission facilities. Moreover, the combination of the B2H project
(including the Midline Series Capacitor Project) along with other provisions in the
Term Sheet would help to address existing operational issues involving
transmission facilities in Oregon and Idaho. BPA also believes that the B2H
project could support public policy objectives of bringing renewable resources to
the region by reducing east to west transmission congestion between renewable
resources located in Wyoming and Idaho and load centers on the west coast.
Finally, it would also provide an additional outlet for surplus non-emitting
resources from Washington and Oregon to displace remote emitting resources
at certain times of the year.
For BPA specifically, the B2H with Transfer Service proposal would provide firm,
stable, long-term transmission path to deliver federal power to BPA’s SILS
customers at an economical cost. The proposal would eliminate the
double-wheel arrangement BPA currently uses to reach its loads, substantially
reduce the risk of curtailments, and save BPA transmission and power purchase
costs that occur under the interim plan. The B2H with Transfer Service
proposal also avoids the complexities and complications of joint ownership
and asset swaps originally considered in the B2H with Asset Swap proposal.
Finally, B2H with Transfer Service results in greater projected transmission
revenues for BPA as Idaho Power wheels over the federal transmission system to
get to B2H. BPA will present its business case describing these savings and
revenue projections and the overall value proposition for B2H with Transfer
Service at a future workshop.
Additionally for BPA, the building of B2H will provide reinforcement for the
Idaho-to-Northwest transmission path, also known as WECC Path 14.
The substantial expansion of capacity across this path would likely be able to
support reliable and cost effective long-term firm transmission service to several
BPA customers, including BPA’s other power customers currently located in
Idaho Power’s service territory. The increase in capacity at Path 14 would ensure
these customers’ access to federal power using the BPA network as well as the
transmission capacity from the owners of the B2H project for their future load
growth for years to come.
B2H Development
Page 28 2021 Integrated Resource Plan—Appendix D
As a federal agency, BPA has responsibilities to comply with the National Environmental Policy
Act (NEPA) and other legal requirements prior to making a final decision or taking any final
agency action, such as committing to enter into transmission service contracts associated with
the B2H project. Coincident with the signing of the Term Sheet, BPA has initiated a multi-step
public process detailed in the aforementioned letter.
Coparticipant Agreements
Idaho Power, BPA, and PAC (collectively, the funders) entered a Joint Permit Funding
Agreement on January 12, 2012. The agreement has been amended several times since 2012.
The Amended and Restated Boardman to Hemingway Transmission Project Joint Permit
Funding Agreement provides for the permitting (state and federal), siting, acquisition of
ROW over public lands, the funding of preconstruction objectives, and acquisition of
ROW options.
On January 18, 2022, the three B2H permit funding participants, Idaho Power, PAC, and BPA,
executed a Non-Binding Term Sheet that addresses B2H ownership, transmission service
considerations, and asset exchanges. The Term Sheet is described in the 2022 Term Sheet and
B2H Project Partner Update section of this appendix.
Coparticipant Expenses Paid to Date
Approximately $125 million, including allowance for funds used during construction (AFUDC),
have been expended on the B2H project through December 31, 2021. Pursuant to the terms of
the joint funding arrangements, Idaho Power has received approximately $81 million of that
amount as reimbursement from the project coparticipants as of December 31, 2021.
Coparticipants are obligated to reimburse Idaho Power for their share of any future project
permitting expenditures incurred by Idaho Power.
B2H Treasure Valley Integration Projects
The addition of the B2H project will require two 230 kV system integration projects to be
completed on the Idaho Power system to create transmission capacity between Hemingway
Substation and the Treasure Valley load area. These projects are estimated to cost
approximately $35 million.
Hemingway–Bowmont #2 230 kV Line
A second transmission circuit will be added on the existing 13-mile Hemingway–Bowmont
230 kV line between the existing Hemingway Station near Melba, Idaho, to the existing
Bowmont Station south of Nampa, Idaho.
B2H Development
2021 Integrated Resource Plan—Appendix D Page 29
Bowmont–Hubbard 230 kV Line
Integrating B2H into the Idaho Power system also will require a new 230 kV line from the
existing Bowmont Station to the existing Hubbard Station east of Kuna, Idaho. This 16-mile line
will be co-located with an existing 138-kV line on rebuilt transmission structures.

B2H Integrated Resource Planning
Page 30 2021 Integrated Resource Plan—Appendix D
B2H INTEGRATED RESOURCE PLANNING
Resource Needs Evaluation and Markets
A primary goal of the IRP is to ensure Idaho Power’s system has sufficient resources to reliably
serve customer demand and flexible capacity needs over the 20-year planning period.
The company has historically developed portfolios to eliminate resource deficiencies identified
in a 20-year Load and Resource Balance. Under this process, Idaho Power developed portfolios
which were quantifiably demonstrated to eliminate the identified resource deficiencies,
and qualitatively varied by resource type, where the varied resource types that were
considered reflected the company’s understanding that the financial performance of a resource
class is dependent on future conditions in energy markets and energy policy.
For the 2021 IRP, Idaho Power elected to use the AURORA model’s long term capacity
expansion modeling capability to develop optimal resource portfolios. Details regarding
AURORA and the company’s portfolio development process can be found in the main 2021
IRP report.
IRP Guideline Language—Transmission Evaluated on Comparable Basis
In Order No. 07-002, the OPUC adopted guidelines regarding integrated resource planning.12
Guideline 5: Transmission. Portfolio analysis should include costs to the utility for
the fuel transportation and electric transmission required for each resource
being considered. In addition, utilities should consider fuel transportation and
electric transmission facilities as resource options, taking into account their value
for making additional purchases and sales, accessing less costly resources in
remote locations, acquiring alternative fuel supplies, and improving reliability.
Boardman to Hemingway as a Resource
B2H has proven to be a cost-effective resource through successive IRPs. When evaluating and
comparing alternative resources, two major cost considerations exist: 1) the installation costs of
the project (capital and other fixed costs), and 2) the energy costs of the project
(variable costs). Installation costs are derived through cost estimates to install the various
projects. B2H has the lowest fixed cost per kW of any resource evaluated, and the energy costs
associated with Mid-C purchases are also very competitive. Energy costs are calculated through
a detailed modeling analysis, using the AURORA software. Energy prices are derived based on
inputs into the model, such as gas price, coal price, nuclear price, hydro conditions,
and variable operations and maintenance (O&M).

12 apps.puc.state.or.us/orders/2007ords/07-002.pdf
B2H Integrated Resource Planning
2021 Integrated Resource Plan—Appendix D Page 31
Market Overview
Power Markets
A power market hub is an aggregation of transaction points (often referred to as bus points or
buses). Hubs create a common point to buy and sell energy, creating one transaction point for
bilateral transactions. Hubs also create price signals for geographical regions.
Six characteristics of successful electric trading markets include the following:
1. The geographic location is a natural supply/demand balancing point for a particular
region with adequate available transmission.
2. Reliable contractual standards exist for the delivery and receipt of the energy.
3. There is transparent pricing at the market with no single player nor group of players
with the ability to manipulate the market price.
4. Homogeneous pricing exists across the market.
5. Convenient tools are in place to execute trades and aggregate transactions.
6. Most importantly, there is a critical mass of buyers and sellers that respond to the five
characteristics listed above and actively trade the market on a consistent basis. This is
the definition of liquidity, which is clearly the most critical requirement of a successful
trading hub.
Mid-C Market
The Mid-C electric energy market hub is a hub where power is transacted both physically and
financially (derivative). Power is traded both physically and financially in different blocks:
long term, monthly, balance-of-month, day ahead, and hourly. Much of the activity for
balance-of-month and beyond is traded and cleared through a clearing exchange,
the Intercontinental Exchange (ICE). For short-term transactions, such as day-ahead and real
time (hourly), trades are made primarily between buyers and sellers negotiating price,
quantity, and point of delivery over the phone (bilateral transactions). In the Pacific
Northwest, most of the price negotiations begin with prices displayed for Mid-C on the ICE
trading platform.
The Mid-C market exhibits all six characteristics of a successful electric trading market discussed
above. Figure 3 shows the relative capacity of resources in the Northwest. This figure from the
Pacific Northwest Utilities Conference Committee (PNUCC) assumes 8th percentile (critical)
hydro generation and other resources set at utility defined peak capacity values. Even at critical
hydro generation, the amount of hydro generation in the Northwest is significant.
B2H Integrated Resource Planning
Page 32 2021 Integrated Resource Plan—Appendix D

Figure 3. Northwest regional forecast (source: 2021 PNUCC)13
In the western United States, the other major market hubs are California–Oregon Border (COB),
Four Corners (Arizona–New Mexico border), Mead (Nevada), Mona (Utah), Palo Verde
(Arizona), and SP15 (California). The Mid-C market is very liquid. In 2020, on a day-ahead
trading basis, daily average trading volume during heavy-load hours during June and July
ranged from nearly 14,000 megawatt-hours (MWh) to nearly 32,000 MWh on the ICE platform
alone. When combining heavy-load hours with light-load hours, on a day-ahead trading basis,
the monthly volumes for June and July were each approximately 1,000,000 MWhs.
These volumes are in addition to daily broker trades and month-ahead trading volumes,
and only represent a fraction of the total transactions at Mid-C. Mid-C is by far the highest
volume market hub in the west; frequently, Mid-C volumes are greater than the other
hubs combined.
The following are some of the market participants that transact regularly at Mid-C. Additionally,
numerous other independent power producers trade at Mid-C.
• Avista Utility
• BPA
• Chelan County PUD
• Douglas County PUD
• Eugene Water and Electric Board
• Idaho Power

13 pnucc.org/system-planning/northwest-regional-forecast
B2H Integrated Resource Planning
2021 Integrated Resource Plan—Appendix D Page 33
• PAC
• Portland General Electric
• Powerex
• Puget Sound Energy
• Seattle City Light
• Tacoma Power
Energy traded at Mid-C is not necessarily physically generated in the Mid-Columbia River
geographic area. For instance, Powerex is a merchant of BC Hydro in British Columbia and
frequently buys and sells energy at Mid-C. A trade at Mid-C requires that transmission is
available to deliver the energy to Mid-C. Transmission wheeling charges must be accounted for
when transacting at Mid-C. Sellers at Mid-C must pay necessary transmission charges to deliver
power to Mid-C, and buyers must pay necessary transmission charges to deliver power to load.
Mid-C and Idaho Power
Historically, Idaho Power wholesale energy transactions have correlated well with the Mid-C
hub due to Idaho Power’s proximity to the market hub, because it is the most liquid hub in the
region, and because Idaho Power’s load peaks in different months than other Northwest
utilities. Energy at Mid-C can be delivered to, or received from, Idaho Power through a single
transmission wheel through Avista, BPA, or PAC. Additionally, long-term monthly price quotes
are readily available for Mid-C, making it an ideal basis for long-term planning.
Idaho Power uses the market to balance surplus and deficit positions between generation
resources and customer demand and to cost-effectively meet customer needs. For example,
when market purchases are more cost-effective than generating energy within Idaho Power’s
generation fleet, Idaho Power customers benefit from lower net power supply cost through
purchases instead of Idaho Power fuel expense. Idaho Power customers also benefit from the
sale of surplus energy. Surplus energy sales are made when Idaho Power’s resources are
greater than Idaho Power customer demand and when the incremental cost of these resources
are below market prices. Idaho Power customers benefit from these surplus energy sales as
offsets to net power supply costs through the power cost adjustment (PCA).
The Mid-C market could be used more to economically serve Idaho Power customers,
but Idaho Power’s ability to transact at Mid-C is limited due to transmission capacity constraints
between the Pacific Northwest and Idaho. In other words, sufficient transmission capacity is
currently unavailable during certain times of the year for Idaho Power to procure cost-effective
resources from Mid-C for its customers, even though generation supply is available at
the market.
B2H Integrated Resource Planning
Page 34 2021 Integrated Resource Plan—Appendix D
Modeling of the Mid-C Market in the IRP
As part of the IRP analysis, Idaho Power uses the AURORA model to derive energy prices at all
market hubs, including the Mid-C market. Energy prices are derived based on inputs into the
model, such as gas price, coal price, nuclear fuel price, hydro conditions, Variable Energy
Resources (VER) output, etc. Refer to main 2021 IRP document for more information on
AURORA, forecast assumptions and modeling.
Energy purchases from the market require transmission to wheel the energy from the source
to the utility purchasing the energy. Purchases from the Mid-C market would need to be
wheeled across the BPA system to get the energy to the proposed Longhorn Substation near
Boardman, Oregon. Idaho Power has submitted a transmission service request with BPA for this
capacity that is a component of the 2022 Term Sheet discussed throughout this appendix.
Transmission wheeling rates and wheeling losses are included in the AURORA database and are
part of the dispatch logic within the AURORA modeling. AURORA economically dispatches
generating units, which can be located across any system in the West. All market energy
purchases modeled in AURORA include these additional transmission costs and are included in
all portfolios and sensitivities.
B2H Capacity Analysis
Capacity Costs
Table 5 below provides capital costs for resource options found in the 2021 IRP to have the
lowest cost from a capacity perspective. The capital costs for B2H in the table below reflect the
inclusion of local interconnection costs for B2H.
Table 5. Total capital dollars ($)/kilowatt (kW) for select resources considered in the 2021 IRP (2021$)
Resource Type Total Capital $/kW Depreciable Life
B2H $6471 55 years
Combined-cycle combustion turbine (CCCT) (1x1) F Class (300 MW) $1,656 30 years
Simple-cycle combustion turbine —Frame F Class (170 MW) $900 35 years
Reciprocating Gas Engine (55.5 MW) $1,560 40 years
Solar PV—Utility-Scale 1-Axis (100 MW) + 4-hr Battery (100 MW) $2,150 30 years2
1 Uses the B2H 750-MW capacity.
2 Depreciable life assumed for the solar component is 30 years and is 15 years for the storage component.
The B2H total capital cost per kilowatt at peak is roughly 70% of the cost of the next lowest-cost
resource. Additionally, B2H, as a transmission line, will depreciate over 55 years compared to at
most 40 years for a gas plant or 30 years for a solar plant. The low up-front cost and slower
B2H Integrated Resource Planning
2021 Integrated Resource Plan—Appendix D Page 35
depreciation further reduces the rate impact to Idaho Power’s customers. The summation of
these factors show B2H is the lowest capital-cost resource by a substantial margin.
Energy Cost
B2H increases Idaho Power’s transmission capacity to the Pacific Northwest and enables
additional purchased power from the Mid-C hub at both peak times and when energy prices are
favorable relative to the costs of Idaho Power’s existing resource fleet. The company believes
that the increasing penetration of VERs, with their zero cost of energy, will depress market
prices in the future. The company will be able to leverage B2H to make economic low-cost
energy purchases.
B2H Comparison to Other Resources
The 2021 IRP provides an in-depth analysis of the B2H project compared to alternative resource
options. Table 6 summarizes some of the high-level differences between B2H and other notable
resource options.
Table 6. High-level differences between resource options
B2H
Reciprocating
engines CCCT
Lithium batteries
(4-Hr) 1-axis solar PV
Variable renewable 
Dispatchable capacity providing
   
Non-dispatchable
(coincidental)
capacity providing

Balancing, flexibility providing
   
Energy providing    
Variable costs (primary variable cost driver)
Mid-C market Natural gas Natural gas Purchased power No variable costs
Capital costs $647 per on-peak kW $1,560 per kW $1,656/kW $1,150 per kW $1,000 per kW
Fuel price risk  
Wholesale power
market price risk
 
Other Expanded access to
market (Mid-C)
providing abundant
clean, renewable
energy, highly reliable
(low forced outage),
as long-lived resource
promotes stability
in customer rates,
benefit to regional
grid, supports
Scalable
(modeled
generators
55.5-MW
nameplate),
relatively short-
lead, very
flexible
resource, range
driven by plant
configuration.
Relatively
short-lead
resource,
dispatchable,
recent
construction
experience.
Uncertainty related to
performance (e.g., # of
lifetime cycles),
dispatchable, scalable,
potential for
geographic dispersion.
Renewable, clean,
scalable (modeled
plants 100-MW
nameplate),
diminishing on-peak
contribution with
expanded
penetration,
short-lead resource,
variable.
B2H Integrated Resource Planning
Page 36 2021 Integrated Resource Plan—Appendix D
B2H Reciprocating engines CCCT Lithium batteries (4-Hr) 1-axis solar PV
Idaho Power’s clean
energy goal, long-lead
resource.
Notes:
1 Provided capital costs are in nominal 2021 dollars.
2 Solar is not dispatchable but tends to produce at fairly high levels during summer periods of high customer demand.
3 Lithium battery is a net energy consumer (roundtrip efficiency = 85%). Lithium battery provides energy during heavy load hours or
other high energy demand/high energy value periods; battery recharge costs tied primarily to Mid-C market costs or variable costs
of Idaho Power’s system resources during light load hours.
BPA Southeast Idaho Customer Loads
As described in the 2022 Term Sheet and B2H Project Partner Update section, BPA intends to
transition out of its role as a joint B2H permitting partner and to rely on the completed B2H
project to take transmission service from Idaho Power to serve its customers in southeast
Idaho. Idaho Power’s B2H capacity will increase from an average of 350 MW west-to-east to
750 MW west-to-east and Idaho Power will utilize a portion of its increased B2H capacity to
provide BPA network transmission service across southern Idaho. The six BPA southeast
customers that will be served via this new network transmission service are listed in Table 7.
Collectively, these BPA southeast Idaho customer loads are winter peaking and have a high
offset by internal BPA network resources, primarily Palisades Power Plant, during the summer
months. Given these characteristics, the load service coordinates very well with Idaho Power’s
planned summer peaking load pattern and expected B2H usage for imports to serve
Idaho Power native load customers.

Table 7. BPA southeast (SE) Idaho Customers
BPA SE Idaho Customers
City of Idaho Falls
Lower Valley Energy
Fall River Rural Electric Cooperative
City of Soda Springs
Salmon River Rural Electric Cooperative
Lost River Electric Cooperative
B2H Benefits and Values
2021 Integrated Resource Plan—Appendix D Page 37
B2H BENEFITS AND VALUES
Capacity
High-voltage transmission lines provide many significant benefits to the Western
Interconnection. The most significant benefit of the B2H project is the capacity benefit of the
transmission line. Idaho Power is developing the B2H project to create capacity to serve peak
customer demand. The capacity benefit is described in more detail in the B2H Integrated
Resource Planning section of this appendix.
The Pacific Northwest is a winter peaking region. Pacific Northwest utilities continue to install
and build generation capacity to meet winter peak regional needs. Idaho Power operates a
system with an early summer peak demand. Idaho Power’s peak occurs in the late June/early
July timeframe because of its irrigation load. Idaho Power’s peak aligns well with spring hydro
runoff conditions when the Pacific Northwest is flush with surplus power capacity.
The existing transmission system between the Pacific Northwest and Idaho Power is
constrained. Constructing B2H will alleviate this constraint and add 1,050 MW of transfer
capability between the Pacific Northwest and Idaho Power (2,050 MW total bi-directionally).
Both the Pacific Northwest and Idaho Power will significantly benefit from the addition of
transmission capacity between the regions by leveraging the diversity of their respective
seasonal demand and generation profiles. The Pacific Northwest has already built the power
plants and would benefit from selling energy to Idaho Power. Idaho Power needs resources to
serve peak load, and a transmission line to existing, underutilized power plants is much more
cost effective than building a new power plant.
Clean Energy Future
The benefits of B2H in aggregate reflect its importance to the achievement of Idaho Power’s
goal to provide 100% clean energy by 2045 without compromising the company’s commitment
to reliability and affordability. In-depth studies and experts, such as the American Clean Power
Association, cite the need for an expanded and robust transmission system in a decarbonized
future.14 Indeed, the Americans for a Clean Energy Grid highlighted B2H as one of 22 projects
that were needed to enable the interconnection of around 60,000 MW of additional renewable

14 cleanpower.org/wp-content/uploads/2021/01/June-2021_Transmission-Fact-Sheet.pdf
utilitydive.com/news/as-operators-update-grid-planning-for-renewables-transmission-remains-key/505065/
pv-magazine-usa.com/2019/08/30/clean-energy-groups-allies-call-for-overhaul-of-the-transmission-grid/
B2H Benefits and Values
Page 38 2021 Integrated Resource Plan—Appendix D
capacity in the United States.15 A Net Zero America report by Princeton16 concluded that the
United States will need to expand its electricity transmission system by 60% by 2030 in order to
achieve net-zero emissions by 2050.
Leverage Regional Diversity
In the early days of the electric grid, utilities built individual power plants to serve their local
load. Utilities quickly realized that if they interconnected their systems with low-cost
transmission, the resulting diversity of load reduced their need to build power plants.
Utilities also realized that transmission allowed them to build and share larger, more cost-
effective, and more efficient power plants. The same opportunities exist today. In fact, B2H is
being developed to take advantage of existing diversity.
Table 8 illustrates peak-load estimates, by utility and season, for 2030. As seen in the table,
there is significant diversity of load among the utilities and between the western and eastern
side of the entire Northwest. The “Maximum (MW)” column illustrates the minimum amount of
generating capacity that would be required if each utility were to individually plan and
construct generation to meet their own peak load need of 71,900 MW. When all utilities plan
together, the total generating capacity can be reduced to 63,500 MW, a more than 10%
reduction. Also note that the Western Northwest (NW) regions have a total winter peak that is
8,200 MW higher than its summer peak. On the other hand, the Eastern NW regions have a
total summer peak that is 9,400 MW more than its winter peak. Transmission connections
between the regions, such as B2H, are the key to sharing installed generation capacity.
Table 8. 2030 peak load estimates—illustration of load diversity between western regions
Region Summer Peak (MW) Winter Peak (MW) Maximum (MW)
Avista 2,200 2,400 2,400
BPA 10,100 12,900 12,900
British Columbia 9,100 12,200 12,200
Chelan 300 500 500
Douglas 300 500 500
Grant 1,500 1,400 1,500
PAC—West 3,800 4,000 4,000
Portland General 3,900 3,800 3,900
Puget Sound 4,200 5,200 5,200
Seattle City 1,200 1,600 1,600
Tacoma 600 900 900

15 https://cleanenergygrid.org/wp-content/uploads/2021/09/Transmission-Projects-Ready-to-Go.pdf
16 https://netzeroamerica.princeton.edu/img/Princeton_NZA_Interim_Report_15_Dec_2020_FINAL.pdf

B2H Benefits and Values
2021 Integrated Resource Plan—Appendix D Page 39
Region Summer Peak (MW) Winter Peak (MW) Maximum (MW)
Western NW Total 37,200 45,400 45,600
Idaho Power 4,500 2,900 4,500
Nevada 9,100 4,100 9,100
Northwestern Energy 2,100 2,100 2,100
PAC—East 10,600 7,800 10,600
Eastern NW Total 26,300 16,900 26,300
Total 63,500 62,300 71,900
Note: From EEI Load Data used for the WECC 2030 ADS PCM
Load diversity occurs seasonally, as illustrated in Table 8, but it also occurs sub-seasonally and
daily. An additional major variable in the Northwest is hydroelectric generation diversity.
Over the winter, water accumulates in the mountains through snowpack. As this snow melts,
water flows through the region’s hydroelectric dams, and northwest utilities generate a
significant amount of power. During the spring runoff, generation capacity available in the
Pacific Northwest can be significantly higher than in the winter or even late summer.
Idaho Power is fortunate to have a peak load that is coincident with the late spring/early
summer hydro runoff. Idaho Power’s peak load occurs in late June/early July, when hot weather
causes major air-conditioning load coincident with agricultural irrigation/pumping load.
Idaho Power’s time window for a significant peak is quite short, with agricultural
irrigation/pumping load starting to ramp down by mid-July.
Capacity to Four Corners Market Hub
As part of the 2022 Term Sheet detailed earlier in this appendix, Idaho Power will acquire PAC
transmission assets and their related capacity sufficient to enable Idaho Power to utilize
200 MW of bidirectional transmission capacity between the Idaho Power system (Populus)
and Four Corners, through Mona. Four Corners is a Desert Southwest market hub and eight
entities with transmission have connectivity to the Four Corners market hub. Idaho Power will
also have a connection to entities at Mona in central Utah.
Table 9. List of transmission entities at Four Corners and Mona
Entities with Transmission at Four Corners Entities with Transmission at Mona
Arizona Public Service Intermountain Power Agency (LADWP)
Salt River Project PAC
Tri State G&T
Western Area Power Admiration
Xcel Energy
PNM
Tucson Electric Power Company
PAC
B2H Benefits and Values
Page 40 2021 Integrated Resource Plan—Appendix D
Idaho Power believes that the acquired Four Corners capacity will provide the company with
long-term strategic value diverse from B2H. The Desert Southwest is rich with solar potential
which is expected to continue its significant growth in the future, New Mexico has significant
wind potential, and the number of Desert Southwest entities with a presence at this market
hub presents significant market diversity opportunities. Idaho Power believes additional access
to this market hub during the winter months will prove to be extremely valuable in a low
carbon future.
The transmission assets between Idaho and Four Corners will provide a valuable firm
transmission connection to a market hub that is diverse from Mid-C. In essence, the B2H
project is enabling two diverse connections to two major western market hubs. As a
conservative planning approach, this additional 200 MW of import capacity is set to zero in
planning margin calculations for the summer peaking months. The diversity of capacity from
multiple market hubs solidifies and supports that the overall B2H project capacity will achieve
500 MW of peak import capacity into Idaho Power.
Borah West and Midpoint West Capacity Upgrades
As part of the 2022 Term Sheet, transmission capacity on the Idaho Power operated Borah
West and Midpoint West transmission paths must be upgraded to support additional east-to-
west schedules required by Idaho Power and PAC across southern Idaho. There are two system
upgrade projects identified to reinforce Borah West and Midpoint West to enable these
increased east-to-west transmission flows through Idaho:
1. Midpoint–Kinport 345 kV Series Capacitor Addition: The addition of a series capacitor
on the existing Midpoint–Kinport 345 kV line will increase the Borah West path rating by
approximately 500 MW. This series capacitor allows for more optimal distribution of
flows on the existing 345 kV lines west of Borah Station near American Falls, Idaho.
2. Midpoint 500/345 kV Second Transformer Addition: The existing single 500/345 kV
transformer bank is a bottleneck for increased flows across the Idaho system. A second
500/345 kV transformer will need to be installed to increase the capacity of the existing
Midpoint–Hemingway 500 kV line to accommodate higher east-to-west transfers across
Idaho to Hemingway.
These upgrades will net an approximate 600 MW increase in capacity across southern Idaho
and enable PAC’s usage of its B2H capacity. Additionally, Idaho Power will be relieved of its
510 MW long-term point-to-point transmission service obligation across southern Idaho and be
able to repurpose this transmission to integrate new resources (many identified in the 2021 IRP
Preferred Portfolio) for Idaho Power customer benefit.
B2H Benefits and Values
2021 Integrated Resource Plan—Appendix D Page 41
Improved Economic Efficiency
Transmission congestion causes power prices on opposite sides of the congestion to diverge.
Transmission congestion is managed by dispatching higher cost, less efficient resources to
ensure the transmission system is operating securely and reliably. Congestion can have a
significant cost. During peak summer conditions, the Idaho to Northwest path in the
west-to-east direction can become constrained and power prices in Idaho and to the east can
generally be high, while power prices in the Pacific Northwest can be depressed due to a
surplus of power availability without adequate transmission capacity to move the power out of
the region. The construction of B2H will help alleviate this constraint and create a win–win
scenario where generators in the Pacific Northwest will be able to gain further value from their
existing resource, and load-serving entities in the Mountain West region will be able to meet
load service needs at a lower cost. The reverse situation is true as well—the Pacific Northwest
will benefit from economical resources from the Mountain West region during certain times of
the year.
Renewable Integration
To facilitate a transition from coal and fossil fuel resources to meet Idaho Power and
surrounding states’ clean energy goals, the region requires new and upgraded transmission
capacity to integrate and balance variable energy resources like wind and solar.
Existing renewable generation is, at times, curtailed due to a lack of transmission capacity to
move the energy to load. B2H can facilitate the transfer of geographically diverse renewable
resources across the western grid and help ensure our clean energy grid of the future is robust
and reliable.
Grid Reliability/Resiliency
Transmission grid disturbances do occur. B2H will increase the robustness and reliability of the
regional transmission system by adding additional high-capacity bulk electric facilities designed
with the most up-to-date engineering standards. Major 500 kV transmission lines, such as B2H,
substantially increase the grid’s ability to recover from unexpected disturbances.
Unexpected disturbances are difficult to predict, but below are a few examples of disturbances
whose impacts would be reduced with the addition of B2H:
1. Loss of the Hemingway–Summer Lake 500 kV line with heavy west-to-east power
transfer into Idaho. The loss of the Hemingway–Summer Lake 500 kV transmission line,
the only 500 kV connection between the Pacific Northwest and Idaho Power,
during peak summer load is one of the worst possible contingencies the Idaho Power
transmission system can experience. Once Hemingway–Summer Lake 500 kV
disconnects, the transfer capability of the Idaho to Northwest path is reduced by over
B2H Benefits and Values
Page 42 2021 Integrated Resource Plan—Appendix D
700 MW in the west-to-east direction. After the addition of B2H, there will be two major
500 kV connections between the Pacific Northwest and Idaho Power.
The Hemingway–Summer Lake 500 kV outage would become much less severe to
Idaho Power’s transmission system.
2. Loss of the Hemingway–Summer Lake 500 kV line with heavy east-to-west power
transfer out of Idaho to the Pacific Northwest. In this disturbance, an existing remedial
action scheme (power system logic used to protect power system equipment)
will disconnect over 700 MW of generation at the Jim Bridger Power Plant or Wyoming
Wind to reduce path transfers and protect bulk transmission lines and apparatus. Due to
the magnitude of the generation loss, recovery from this disturbance can be extremely
difficult. After the addition of B2H, this sizable amount of generation shedding will no
longer be required. With two 500 kV lines between Idaho and the Pacific Northwest,
the loss of one can be absorbed by the other. Keeping 700 MW of generation on the
system for major system outages is important for grid stability.
3. Loss of a single 230 kV transmission tower in the Hells Canyon area. Idaho Power owns
two 230 kV transmission lines, co-located on the same transmission towers,
that connect Idaho to the Pacific Northwest. Because these lines are on a common
tower, Idaho Power must consider the simultaneous loss of these lines as a realistic
planning event. Historically, such an outage did occur on these lines in 2004 during a day
with high summer loads. By losing these lines, Idaho Power’s import capability was
dramatically reduced, and Idaho Power was forced to rotate customer outages for
several hours due to a lack of resource availability. After the addition of B2H, the impact
of this outage would be substantially reduced.
Resource Reliability
The forced outage rate of transmission lines has historically been lower than traditional
generation resources. Availability and contribution to resource adequacy on the power grid
vary significantly by resource type. The North American Electric Reliability Corporation (NERC)
has historically tracked transmission availability through a Transmission Availability Data System
(TADS) and generation availability through a Generation Availability Data System (GADS)
in North America. Outage statistics between transmission and generation differ, as transmission
varies in voltage class and total line length, while generators mostly differ in total size and fuel
type. A telling sign of the reliability of a generation resource is the equivalent forced outage
rate (EFORd). The EFORd is calculated based on the amount of time a generator or a
transmission line, is either de-rated, or completely forced out of service, while needed.
De-rating a generator or a transmission line, would be considered a partial outage, based on
the de-rate amount as a percentage of the total capacity.
B2H Benefits and Values
2021 Integrated Resource Plan—Appendix D Page 43
Table 10 provides the EFORd values used in the 2021 IRP. The EFORd values were obtained
from the company historical data and from the latest data available in GADS and TADS at the
time of the analysis.22
Table 10. NERC forced-outage rate information for different resources
Generation Type Unit Size EFORd
Coal All Sizes 6.34%–9.18%
Hydro All Sizes 3.6%
Gas Simple Cycle All Size 4.44%–7.3%
Gas Combined Cycle >200 MW 2.0%
New Transmission 400-599 kV 0.25%

From the NERC TADS data, a 300-mile, 500 kV transmission line (B2H) would be expected to
have an equivalent forced outage rate of 0.25%; the B2H transmission line is expected to have
99.75% availability when needed.
A transmission line with a forced outage rate of less than 1% is significantly more reliable than a
power plant, as shown in Table 10. Of course, a transmission line requires generating resources
to provide energy to the line to serve load. However, energy sold as “Firm” must be backed up
and delivered even if a source generator fails. Therefore, Firm energy purchases would have an
EFORd consistent with the transmission line, which is more reliable than traditional supply-side
generation. In the management of cost and risk, B2H will provide Idaho Power’s operators
additional flexibility when managing the Idaho Power resource portfolio.
As described in the 2021 IRP Appendix C–Technical Report, Idaho Power evaluated the Loss of
Load Expectation for each IRP portfolio. Figure 4 depicts the additional Simple Cycle
Combustion Turbine equivalent generation capacity required to maintain the Preferred
Portfolio (Base with B2H) and the Base without B2H PAC Bridger Alignment portfolio
(the least-cost portfolio that did not include B2H) within the desired reliability threshold.

B2H Benefits and Values
Page 44 2021 Integrated Resource Plan—Appendix D

Figure 4. Additional generation required to achieve 0.05 LOLE by portfolio
Figure 4 shows that the Preferred Portfolio (Base with B2H) is significantly more reliable than
the best portfolio that did not include B2H.
Contingency Reserves
During real-time operations, Idaho Power holds generation in reserve to meet its contingency
reserve obligation. As a requirement of NERC BAL-002-WECC-2a, Idaho Power has an obligation
to hold generation in reserve equaling at least 3% of network demand plus 3% of internal
generation. For market purchase imports, the 3% contingency requirement for the generation
is not borne by Idaho Power. The producer in the external balancing area is required to meet
the 3% reserve obligation associated with its resource. Compared to an internal resource
located within the Idaho Power area, imported market purchases reduce Idaho Power’s
reserve obligation.
Idaho Power plans to make additional market purchases with B2H. The selling entity will carry
the contingency reserve obligation. This reduction in reserve obligation will offset the
additional reserve obligations taken on by the company through the increased amount of BPA
customer network load and generation in the Idaho Power area. Table 11 details the increase in
transmission network customer reserve obligations being offset by reduced reserve obligations
B2H Benefits and Values
2021 Integrated Resource Plan—Appendix D Page 45
from market purchases. Idaho Power’s reserve obligation during summer peak is still reduced
with B2H compared to a replacement internal resource.
Table 11. Change in Idaho Power contingency reserve obligation with B2H
Change in Summer Peak
Network Demand
Change in Summer Peak
Network Resource
Change in Reserve
Obligation
New BPA Southeast Customer
Idaho Network Load and Gen
~325 MW ~145 MW 14.1 MW
Idaho Power Market Purchases
via B2H Instead of a New
Internal Resource
- (500 MW) (15 MW)
Total - - (0.9 MW)

Reduced Electrical Losses
During peak summer conditions, with heavy power transfers on the Pacific Northwest and
Idaho Power transmission systems, the addition of the B2H project is expected to reduce
electrical losses by nearly 100 MW across the Western Interconnection (factoring in more than
just Idaho Power’s system). This is a considerable savings for the region; 100 MW of
generation, that customers ultimately pay for, does not need produced to supply losses alone.
Electrical losses add to the demand level that needs to be supplied by the power system.
Losses on the power system are caused by electrical current flowing through energized
conductors, which in turn create heat. Losses are equal to the electrical current squared times
the resistance of the transmission line: 𝐸𝐸𝐸𝐸𝐸𝐸𝑐𝑐𝑡𝑡𝑡𝑡𝑡𝑡𝑐𝑐𝑡𝑡𝐸𝐸 𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐸𝐸𝐿𝐿=𝐶𝐶𝐶𝐶𝑡𝑡𝑡𝑡𝐸𝐸𝐶𝐶𝑡𝑡2 × 𝑅𝑅𝐸𝐸𝐿𝐿𝑡𝑡𝐿𝐿𝑡𝑡𝑡𝑡𝐶𝐶𝑐𝑐𝐸𝐸
From the electrical losses equation above, if the current doubles, the electrical losses will
increase by a factor of four. By constructing the B2H line, less efficient (i.e., lower voltage)
transmission lines with very large transfers are relieved, reducing the electrical current through
these lines and dramatically reducing the losses due to heat.
The electrical losses vary throughout the year depending on flow levels on the lines.
To determine an average electrical loss saving benefit for Idaho Power resulting from the B2H
project, various seasonal WECC power flow base cases were utilized to simulate flow conditions
with and without the addition of B2H. The Idaho Power area transmission losses from
simulated base case scenarios are shown in Table 12. In six of the seven cases the B2H project
resulted in a beneficial reduction of losses in the Idaho Power balancing area.
B2H Benefits and Values
Page 46 2021 Integrated Resource Plan—Appendix D
Table 12. Idaho Power area losses from powerflow cases pre- and post-B2H
Powerflow Case Idaho Power Losses
Pre-B2H Post-B2H Change (MW)
Peak Summer 207.2 MW 176.5 MW -30.7 MW
Peak Summer NW Import 185.6 MW 159.3 MW -26.3 MW
Peak Winter 97.8 MW 87.3 MW -10.5 MW
Off Peak Summer 82.9 MW 75.7 MW -7.2 MW
Off Peak Winter 61.1 MW 61.3 MW 0.2 MW
Off Peak Light NW Export 106.8 MW 106.0 MW -0.8 MW
Off Peak Heavy NW Export 189.4 MW 180.2 MW -9.2 MW

The above loss benefits in Table 12 are for seven specific powerflow hours. To develop an
average loss savings benefit for B2H that considers all flow hours, regression analysis was
performed to develop quadratic equation coefficients that relate path flows to predicted
energy loss savings. Next, historical transmission path flows from the previous five years were
captured and analyzed with developed loss savings coefficients. The result of the analysis was
an Idaho Power 6.4 MW average electrical loss savings with the addition of B2H. This 6.4 MW
average loss saving benefit was utilized as an input in the B2H scenarios for the 2021 IRP.
For IRP portfolios with B2H included, the Idaho Power load was reduced by 6.4 MW during all
hours to capture the value of this reduction in electrical losses.
Flexibility
Advances in technology are pushing some generation resources, such as coal plants,
toward economic obsolescence. Any supply-side resource alternative could face the same
economic obsolescence in the future. B2H is an alternative to constructing a new supply-side
resource and, therefore, reduces the risk of technological obsolescence. B2H will facilitate the
transfer of any generation technology, ensuring Idaho Power customers always have access to
the most economic resources, regardless of the resource type.
B2H capacity, when not used by B2H owners, will be available (for purchase) to other parties to
make economic interstate west-to-east and east-to-west power transfers for more efficient
regional economic dispatch. This provides a regional economic benefit to utilities around
Idaho Power that is not factored into the analysis. Specifically, the B2H project will make
additional capacity available for Pacific Northwest utilities to sell energy to southern and
eastern markets in the west, and for Pacific Northwest utilities to purchase energy from
southern and eastern markets to meet their winter peak load service needs (southern and
eastern WECC entities are mostly summer peaking). Idaho Power customers benefit from any
B2H Benefits and Values
2021 Integrated Resource Plan—Appendix D Page 47
third-party transmission purchases as the incremental transmission revenue acts to offset retail
customer costs.
The existing electric system is heavily used. Because the system is so heavily used,
new transmission line infrastructure, like B2H, creates additional operational flexibility. B2H will
increase the ability to take other system elements out of service to conduct maintenance and
will provide additional flexibility to move needed resources to load when outages occur
on equipment.
EIM
Idaho Power views the regional high-voltage transmission system as critical to the realization
of EIM benefits. The expansion of this transmission system, through the addition of B2H,
will facilitate further benefits by increasing transmission capacity between Idaho Power and
other EIM participants. As fluctuations in supply and demand occur for EIM participants,
the market system will automatically find the best resource(s) from across the large-footprint
EIM region to meet immediate power needs. Additional Northwest utilities are joining the EIM
increasing the value the transmission system provides. This activity optimizes the
interconnected high-voltage system as market systems automatically manage congestion,
helping maintain reliability while also supporting the integration of variable energy resources
and avoiding curtailing excess supply by sending it to where demand can use it.
Idaho Power notes that its participation in the EIM does not alter its obligations as a balancing
authority (BA) required to comply with all regional and national reliability standards.
Participation in the western EIM does not change NERC or WECC responsibilities for resource
adequacy, reserves, or other BA reliability-based functions for a utility.
Transmission capacity and connectivity is critical to evolution of markets in the west.
Market expansion efforts such as the California Independent System Operator’s (CAISO) Energy
Day-Ahead Market (EDAM) or the Southwest Power Pool’s (SPP) markets both look to optimize
transmission between entities to capture diversity of resources and loads. Greater transmission
transfer capacity between participants in a market reduces congestion costs and allows the
lowest cost energy to reach a wider load footprint. Transmission benefits customers in both the
EIM and expanded markets through increased competition and liquidity as customers gain
access to a wider set of generators through an optimized market dispatch.
B2H Complements All Resource Types
Utility-scale resource installations allow economies of scale to benefit customers in the form of
lower cost per watt. For instance, residential rooftop solar is growing in popularity, but the
B2H Benefits and Values
Page 48 2021 Integrated Resource Plan—Appendix D
economics of rooftop solar are outweighed by the economics of utility-scale solar installation.17
Large transmission lines allow the most economical resources to be sited in the most
economical locations. As an example, in the 2021 IRP, wind in Idaho is expected to have a
capacity factor of approximately 35% (where the capacity factor is the amount of time the
system generates relative to its nameplate rating over the course of a year).
Comparatively, wind in Wyoming has a capacity factor of 45%. If wind installation costs are
assumed to be equivalent in Idaho and Wyoming, a Wyoming installation would generate over
28% more energy over the course of the year. Transmission lines provide the ability to move
the most economical resources around the region.
Idaho Power views transmission lines like B2H as a complement to any resource type that
allows access to the least-cost and most efficient resource, as well as regional diversity,
to benefit all customers in the West.
B2H Benefits to Oregon
Economic and Tax Benefits
The B2H project will result in positive economic impacts for eastern Oregon communities in the
form of construction jobs, economic support associated with infrastructure development
(i.e., lodging and food), and increased annual tax benefits to each county for project-specific
property tax dollars. The annual tax benefit of the line is shown in Table 13 below. Idaho Power
anticipates the project will add about 500 construction jobs, which will provide a temporary
increase in spending at local businesses.
Table 13. Projected annual B2H tax expenditures by county*
Oregon County Property Tax
Morrow $318,040
Umatilla $421,048
Union $1,002,165
Baker $1,815,398
Malheur $2,241,157
Total Oregon Tax Benefit $5,797,808
*The property tax valuation process for utilities is determined differently than locally assessed commercial and residential property.
The Oregon Department of Revenue determines the property tax value for Idaho Power’s property (transmission, distribution, production,
etc.) as one lump sum value (i.e., not by individual assets). The Oregon Department of Revenue then apportions and remits Idaho Power’s lump sum assessed value to each county. It is from those values that the county generates property tax bills for the company. Idaho Power converts its Oregon property tax payment by county into an internal rate that can be applied to Idaho Power’s transmission,
distribution, and production book investment to estimate taxes. This internally calculated tax rate is what was applied to the B2H estimated
book investment (project cost) to estimate property taxes. The table above summarizes the tax value derivation. For estimation purposes, the estimated property taxes are assumed at Idaho Power tax rates. PAC property taxes may differ from Idaho Power’s property taxes.
17 The National Renewable Energy Laboratory (NREL) estimates the cost of residential rooftop solar (PV) is nearly
2.5 times the cost of utility-scale solar on a $/Watt basis (NREL, Annual Technology Baseline: Electricity: 2019).
B2H Benefits and Values
2021 Integrated Resource Plan—Appendix D Page 49
Local Area Electrical Benefits
The B2H project will add 1,050 MW of additional transmission connectivity between the BPA
and Idaho Power systems. Currently, the transmission connections between BPA and
Idaho Power are fully committed for existing customer commitments. Along the B2H line route,
Idaho Power currently serves customers in Idaho’s Owyhee County and in Oregon’s Malheur
County and portions of Baker County. PAC, through Pacific Power, serves portions of Umatilla
County. BPA provides transmission service to local cooperatives in the remainder of the project
area in Morrow, Umatilla, Union, and Baker counties. Below is a summary of how these areas
will benefit directly from B2H.
La Grande and Baker City are served by the Oregon Trails Electric Cooperative (OTEC).
Portions of Morrow County and Umatilla County are served by Umatilla Electric Cooperative
(UEC) and Columbia Basin Electric Cooperative (CBEC). OTEC, UEC, and CBEC pay BPA’s network
transmission rate to receive transmission service from the BPA system. BPA is kicking off a
public process related to B2H in 2022, and Idaho Power expects BPA’s business case will show
B2H is a cost-effective solution to meet BPA customer needs. Correspondingly, given the
sharing of BPA’s transmission costs, OTEC, UEC, and CBEC customers would also benefit from
this cost-effective solution.
The B2H project provides economic development opportunities. The cost of power is a major
factor in economic development and—as discussed previously—B2H, as a low-cost resource
alternative, will keep power costs low compared to more expensive alternatives.
Capacity must be available on the existing system for additional economic development to take
place. In Union and Umatilla counties, BPA’s McNary–Roundup–La Grande 230 kV line has
limited ability to serve additional demand in the Pendleton and La Grande areas but is currently
capable of meeting the 10-year load forecast. The B2H project will increase the transfer
capability through eastern Oregon by 1,050 MW. This capacity will provide a significant regional
benefit to the entire Northwest and specifically benefit load service to eastern Oregon and
southern Idaho. It is possible this added capacity resulting from the B2H project could be used
to serve additional demand in Union and Umatilla counties.
Portions of Baker County are served by Idaho Power, including the communities of Durkee and
Huntington. BPA currently provides energy to OTEC, which serves Baker City via transmission
connections between the Northwest and Idaho Power’s transmission system. The existing
transmission connections between the Northwest and Idaho Power are fully used for existing
load commitments, with very little ability to meet load growth requirements. The B2H project
associated increased transmission connectivity between the Northwest and Idaho Power will
allow BPA to serve additional demand in Baker City.
B2H Benefits and Values
Page 50 2021 Integrated Resource Plan—Appendix D
Finally, additional transmission capacity can create opportunities for new energy resources,
which can add to the county tax base and create new jobs.
Gateway West Project
2021 Integrated Resource Plan—Appendix D Page 51
GATEWAY WEST PROJECT
Project Background
The Gateway West transmission line project is a joint project between Idaho Power and PAC to
build and operate approximately 1,000 miles of new transmission lines from the planned
Windstar Substation near Glenrock, Wyoming, to the Hemingway Substation near Melba,
Idaho. PAC is currently the project manager for Gateway West, with Idaho Power providing a
supporting role.
Figure 5 shows a map of the entire project identifying the authorized routes in the federal
permitting process based on the BLM’s November 2013 ROD for segments 1 through 7 and 10.
Segments 8 and 9 were further considered through a Supplemental EIS by the BLM. The BLM
issued a ROD for segments 8 and 9 on January 19, 2017. In March 2017, this ROD was rescinded
by the BLM for further consideration. On May 5, 2017, the Morley Nelson Snake River Birds of
Prey National Conservation Area Boundary Modification Act of 2017 (H.R. 2104) was enacted.
H.R. 2104 authorized the Gateway West route through the Birds of Prey area that was
proposed by Idaho Power and PAC and supported by the Idaho Governor’s Office,
Owyhee County and certain other constituents. On April 18, 2018, the BLM released the
Decision Record granting approval of a ROW for Idaho Power’s proposed routes for segments 8
and 9.
In its 2017 IRP, PAC announced plans to construct a portion of the Gateway West Transmission
Line in Wyoming. PAC has subsequently constructed the 140-mile segment between the
planned Aeolus Substation near Medicine Bow, Wyoming, and the Jim Bridger power plant near
Point of Rocks, Wyoming. The Aeolus to Bridger/Anticline 500 kV line segment was energized
November 2020.
Gateway West will provide many benefits to Idaho Power customers, including the following:
• Relieve Idaho Power’s constrained transmission system between the Magic Valley
(Midpoint) and the Treasure Valley (Hemingway). Transmission connecting the Magic
Valley and Treasure Valley is part of Idaho Power’s core transmission system,
connecting two major Idaho Power load centers
• Provide the option to locate future generation resources east of the Treasure Valley
• Provide future load-service capacity to the Magic Valley from the Cedar Hill Substation
• Help meet the transmission needs of the future, including transmission needs
associated with VERs
• Reduce transmission losses
Gateway West Project
Page 52 2021 Integrated Resource Plan—Appendix D
• Improve transmission grid reliability
• Provide access to abundant renewable energy that will lead to a cleaner generating
portfolio across the West
Phase 1 of the entire Gateway West project is expected to provide up to 1,500 MW of
additional transfer capacity between Midpoint and Hemingway. The fully completed project
would provide a total of 3,000 MW of additional transfer capacity. Idaho Power has a one-third
interest in these capacity additions on certain segments of the overall project.
The Gateway West
and B2H projects are complementary and will provide upgraded transmission paths from the
Pacific Northwest across Idaho and into eastern Wyoming.
More information about the Gateway West project can be found at gatewaywestproject.com.

Figure 5. Gateway West map
Idaho Power Segments
Idaho Power has a one-third interest in the segments between Midpoint and Hemingway
(segment 8), Cedar Hill and Hemingway (segment 9), and Cedar Hill and Midpoint (segment 10).
Further, Idaho Power has interest in the segment between Borah and Midpoint (segment 6),
which is an existing transmission line operated at 345 kV but constructed at 500 kV.
Gateway West Project
2021 Integrated Resource Plan—Appendix D Page 53
The Gateway West transmission capacity between the Magic Valley and the Treasure Valley
areas can relieve two primary transmission constraints: 1) transmission capacity between the
Magic Valley and Treasure Valley (Midpoint West), and 2) transmission capacity between the
Mountain Home area, and the Treasure Valley (Boise East). These transmission constraints limit
the amount of new generation resources that can be sited on the Idaho Power system east of
the Treasure Valley area. Planned coal exits from Jim Bridger and North Valmy open up some
capacity on the paths that can also be used for new resources, but additional transmission
capacity may be required depending on the resource portfolio.
The Midpoint to Hemingway 500 kV line (segment 8) between the Magic Valley and the
Treasure Valley was modeled to relieve transmission congestion allowing new IRP resources to
be added to the system. The Midpoint to Hemingway segment was modeled as being phased in
as two distinct projects described below.
Figure 6. Gateway West map–Magic Valley to Treasure Valley segments (8 and 9)
2021 IRP Gateway West—Phase 1 (Partial Segment 8)
For the 2021 IRP, the company modeled a partial build phase of a Gateway West segment,
the Midpoint to Hemingway #2 500 kV line (segment 8) as a possibility. The partial build phase
would be a subset of segment 8 constructed between Hemingway and Mountain Home with
the line constructed at 500 kV but operated at 230 kV. This Phase 1 partial segment increases
the capacity of the Idaho Power transmission system, by approximately 700 MW, between
Mountain Home and Boise required to support incremental resources sited to the east.
2021 IRP Gateway West—Phase 2 (Complete Segment 8)
Phase 2 would be to complete the second half of the Gateway West segment 8 project between
Midpoint and Mountain Home. The line would be operated at 500 kV from Midpoint to
Gateway West Project
Page 54 2021 Integrated Resource Plan—Appendix D
Hemingway after this phase is constructed. The total capacity provided by the complete
segment 8 would increase the transmission capacity into the Treasure Valley by approximately
1,500 MW, which represents an additional 800 MW increase from Phase 1.
Depending on transmission capacity needs, the complete segment 8 could also be built in a
single phase.
2021 IRP Gateway West Transmission Assumptions
The siting of new resources, such as wind and solar, on the Idaho Power system are limited by
internal transmission constraints on the Idaho Power system between the Magic Valley and the
Treasure Valley, in particular the Midpoint West and Boise East internal transmission paths.
The 2021 IRP analysis determined the incremental resource additions that would trigger the
need for Gateway West to transport energy from new resources to the Treasure Valley load
center. Historical resource and load data and transmission service obligations were analyzed to
determine the existing transmission commitments and available transmission capacity that
could be utilized by new resources. For this determination the company assumed 75th
percentile resource levels and 25th percentile system loads in the Magic Valley and Eastern
Idaho. Planned unit exits from Valmy and Bridger power plants in the IRP portfolios open up
capacity that can be utilized by new resources and are also part of the analysis.
Base with B2H Portfolio Gateway West Transmission Assumptions
As described in the B2H Benefits and Values section of this appendix, the transmission capacity
on the Idaho Power operated Borah West and Midpoint West transmission paths will be
upgraded to support additional east-to-west schedules and to enable PAC’s usage of its B2H
capacity. PAC will acquire 600 MW of east-to-west transmission assets across Borah West,
Midpoint West, and Boise East for an ownership path to their B2H capacity, and PAC will
terminate its existing 510 MW east-to-west transmission service across Idaho Power.
Idaho Power can re-purpose the transmission previously reserved for PAC’s transmission
service for the integration of new resources. Table 14 below details the east-to-west Borah
West and Midpoint West ownership, transmission service obligations, and Idaho Power net
capacity for use before and after the B2H project.
Gateway West Project
2021 Integrated Resource Plan—Appendix D Page 55
Table 14. Idaho Power internal path capacity and ownership
Path Rating
E to W
Idaho Power Ownership
E to W
PAC Ownership
E to W
PAC Transmission
Service E to W
Idaho Power
Net Capacity
E to W
Without B2H
Boise East ~3700* MW 2610 MW 1090 MW 510 MW 2100 MW
Midpoint West 2800 MW 1710 MW 1090 MW 510 MW 1200 MW
Borah West 2557 MW 1467 MW 1090 MW 510 MW 957 MW
After B2H and Idaho Upgrades
Boise East ~4250 MW 2560 MW 1690 MW 0 MW 2560 MW
Midpoint West ~3350 MW 1660 MW 1690 MW 0 MW 1660 MW
Borah West ~3180 MW 1490 MW 1690 MW 0 MW 1490 MW
* Rating assumes planned near-term rebuild of an existing 230 kV line.
Per the 2022 Term Sheet, the addition of B2H will come with 200 MW of capacity from Four
Corners Substation in New Mexico to Populus Substation in eastern Idaho. Utilization of this
capacity will consume some of the east-to-west capacity listed above to move it across
southern Idaho to load. Offsetting some of the 200 MW Four Corners schedule will be the
addition of BPA southeast Idaho customer network load located east of the paths detailed in
Table 8. BPA southeast Idaho load increases the network load on the eastern side of the
Idaho Power system and therefore reduces the east-to-west congestion. The net impact of the
upgrades, PAC wheeling termination, Four Corners capacity, and BPA southeast Idaho network
load, compared to a scenario without B2H and the associated 2022 Term Sheet, results in
approximately 400 MW more available east-to-west transmission capacity in B2H portfolios
than portfolios without the addition of B2H.
The Base with B2H portfolio includes 700 MW of new wind resources and 1,405 MW of new
solar resources. These resources are assumed to be added on the Idaho Power transmission
system east of the Treasure Valley. The stand-alone battery resources are assumed to be sited
near the Treasure Valley load center, or co-located with the new wind and solar resources,
and therefore do not require network transmission across southern Idaho to the Treasure
Valley. The net approximate 400 MW of capacity gained by the internal east-to-west
upgrades associated with B2H coupled with the exits of Valmy and Bridger allow the
Preferred Portfolio (Base with B2H) resources to be integrated without requiring a Gateway
West segment.
Base without B2H PAC Bridger Alignment Portfolio Gateway West
Transmission Assumptions
The Base without B2H PAC Bridger Alignment portfolio includes 1,200 MW of new wind
resources and 1,905 MW of new solar resources. Similar to the Base with B2H portfolio,
Gateway West Project
Page 56 2021 Integrated Resource Plan—Appendix D
it is assumed these resources would be sited on the Idaho Power transmission system east of
the Treasure Valley and that stand-alone battery resources would be sited near the Treasure
Valley load center or co-located with the new wind and solar resources. For this portfolio the
upgrades detailed in the Borah West and Midpoint West Capacity Upgrades section, and the
Gateway West partial segment 8 (project 1) would be required in 2027 and the Gateway West
completed segmented 8 would be required in 2033. The additional amount of wind and solar
and the 400 MW net reduction in available transmission capacity compared to the Preferred
Portfolio (Base with B2H) necessitates the addition of the Gateway West projects to
the portfolio.
Southwest Intertie Transmission Project-North
2021 Integrated Resource Plan—Appendix D Page 57
SOUTHWEST INTERTIE TRANSMISSION PROJECT-NORTH
The Southwest Intertie Transmission Project-North
(SWIP-North) is a proposed 275-mile
500 kV transmission project being developed by Great
Basin Transmission, LLC which is an affiliate of LS
Power. The SWIP-North connects Idaho Power’s
Midpoint Substation near Twin Falls, Idaho, and the
Robinson Summit Substation near Ely, Nevada.
The project would provide a connection to the One
Nevada 500 kV Line (ON Line) which is an in-service
segment between Robinson Summit and the Harry
Allen Substation in the Las Vegas, Nevada, area.
The two projects together are the combined SWIP
project. The combined SWIP project is expected to
have a bi-directional WECC-approved path rating of
approximately 2,000 MW.
The addition of the SWIP-North segment would unlock
additional capacity on the existing ON Line that
connects northern and southern Nevada. Contractual
ownership of capacity on SWIP-North would provide
capacity rights to and from the Harry Allen Substation
in the Las Vegas area. The Harry Allen Substation is connected to CAISO via the newly
constructed DesertLink 500 kV line. The substation is also near the Desert Southwest market
hub, Mead. Idaho Power’s potential participation in the project could provide the company
transmission access—past transmission congestion on NV Energy’s system—from the Desert
Southwest market and CAISO directly to Idaho Power. Figure 7 shows the SWIP-North
Preliminary Route and the locations of the ON Line and DesertLink
500 kV lines to the south.
To determine a cost-estimate for SWIP-North, the company used publicly available cost data for
similar lines recently constructed in Nevada and assumed that Idaho Power would own a
200-MW share of the south-to-north capacity.
Total Cost Estimate (200 MW share): $133 million with a pre-summer 2025 in-service date.
Figure 7. SWIP-North preliminary route

Combined Major Transmission Projects in Idaho
Page 58 2021 Integrated Resource Plan—Appendix D
COMBINED MAJOR TRANSMISSION PROJECTS IN IDAHO
B2H, Gateway West, and SWIP North, when combined, can provide vast interregional
connectivity for both load and resource diversity. Figure 8 below depicts the opportunity
the combination of these projects can provide to Idaho Power, and the greater
Western Interconnection.

Figure 8. Map of B2H, Gateway West, and SWIP North
2021 IRP Portfolio Transmission Cost Assumptions
2021 Integrated Resource Plan—Appendix D Page 59
2021 IRP PORTFOLIO TRANSMISSION COST ASSUMPTIONS
The transmission assumptions from the 2021 IRP Preferred Portfolio (Base with B2H) are listed
in Table 15. The Base with B2H portfolio includes the 2026 addition of the B2H project including
the Midline Series Capacitor Station, the 230 kV Hemingway Integration Projects, and Borah
West and Midpoint West Upgrades to support increased east-to-west flows for PAC and
Idaho Power. The capital costs in the table include Idaho Power AFUDC and 0% contingency.
Table 15. Preferred Portfolio (Base with B2H) transmission upgrades and capital costs
Upgrade Year Capital Costs
B2H (45.45% IPC Share) 2026 $425.2M
B2H Midline Series Capacitor Station (45.45% IPC Share) 2026 $10.3M
230 kV Hemingway Integration Projects 2026 $35.3M
Borah West and Midpoint West Upgrades* 2026 $46.8M
*Upgrades to jointly owned Idaho Power and PAC assets.
The transmission assumptions for the Base without B2H PAC Bridger Alignment portfolio
(the least cost portfolio that did not include B2H) are listed in Table 16. This portfolio contains
Gateway West phases in 2027 and 2033 to enable higher amounts of solar and wind resource
additions to the system east of the Treasure Valley. The Gateway West projects deliver energy
to Hemingway necessitating a larger connection between Hemingway and the Treasure Valley
load area; consequently, the 230 kV Hemingway Integration Projects are also a required
upgrade in this portfolio. Further, the Borah West and Midpoint West Upgrades are included in
this portfolio as they are the initial lowest cost upgrades on the existing system. Absent any
future agreement, PAC is assumed to participate in the upgrades at the existing Borah West and
Midpoint West joint ownership percentages. This reduces the cost and capacity gained by
Idaho Power from the upgrades. Again, the capital costs in the table include Idaho Power
AFUDC and 0% contingency.
Table 16. Base without B2H PAC Bridger alignment transmission upgrades and capital costs
Upgrade Year Capital Cost
Gateway West Phase 1 (Partial Segment 8) 2027 $176.1M
230 kV Hemingway Integration Projects 2027 $35.3M
Borah West and Midpoint West Upgrades* 2027 $16.2M
Gateway West Phase 2 (Complete Segment 8) 2033 $176.1M
*Upgrades to jointly owned Idaho Power and PAC assets.
Transmission Line Estimates
Idaho Power has contracted with HDR to serve as the B2H project’s third-party owners’
engineer and prepare the B2H transmission line cost estimate. HDR has extensive industry
2021 IRP Portfolio Transmission Cost Assumptions
Page 60 2021 Integrated Resource Plan—Appendix D
experience, including experience serving as an owner’s engineer for BPA for the last seven
years. HDR has prepared a preliminary transmission line design that locates every tower and
access road needed for the project. HDR used utility industry experience and current market
values for materials, equipment, and labor to arrive at the B2H estimate. Material quantities
and construction methods are well understood because the B2H project is utilizing BPA’s
standard tower and conductor design for 500 kV lines. BPA has used the proposed towers and
conductor on hundreds of miles of lines currently in-service. HDR was the owner’s engineer on
recent BPA projects, so HDR is also familiar with the BPA towers and conductor the B2H project
is using.
Substation Estimates
The northern terminus for B2H requires a new substation near Boardman, Oregon, to tap into
the existing BPA 500 kV transmission network. BPA owns the land for the Longhorn Station and
must complete all NEPA reviews and other legal requirements before making a final decision to
construct Longhorn Station. BPA proposed the Longhorn Station to integrate certain wind
projects in the immediate area. BPA has prepared the Longhorn Station cost estimate, based on
its extensive experience designing and constructing substations.
The southern terminus for B2H is Idaho Power’s Hemingway Substation, near Murphy, Idaho.
The Hemingway Substation has an existing 500 kV connection between Idaho Power’s Midpoint
Substation (near Shoshone, Idaho) and PAC’s Summer Lake Substation in Lake County, Oregon.
Completed in 2013, the Hemingway Substation is designed to accommodate the B2H line
terminal in the future. New equipment must be ordered and installed, but no station expansion
will be required. Based on these expectations, Idaho Power prepared the Hemingway
Substation cost estimate.
Calibration of Cost Estimates
The B2H estimate was reviewed and approved by BPA and PAC. BPA and PAC both have recent
transmission line construction projects to calibrate against. The recent projects included
the following:
• BPA: Lower Monumental–Central Ferry 500 kV line (38 miles, in-service 2015)
• BPA: Big Eddy–Knight 500 kV line (39 miles, in-service 2016)
• PAC: Sigurd to Red Butte 345 kV line (160 miles, in-service 2015)
• PAC: Mona to Oquirrh 500 kV line (100 miles, in-service 2013)
Additionally, in early 2017 Idaho Power visited with NV Energy and Southern California Edison
to learn from each company’s recent experience constructing 500 kV transmission lines in the
2021 IRP Portfolio Transmission Cost Assumptions
2021 Integrated Resource Plan—Appendix D Page 61
West. As part of the discussions with each company, Idaho Power calibrated cost estimates and
resource requirements.
The two projects were as follows:
• NV Energy: ON Line project (235 miles, 500 kV, in-service 2014)
• Southern California Edison: Devers to Palo Verde (150 miles, 500 kV, in-service 2013)
Costs Incurred to Date
Approximately $125 million, including AFUDC, has been expended on the B2H project through
December 31, 2021. The $125 million incurred through December 31, 2021, is included in the
$1 to $1.2 billion total estimate. Idaho Power’s share of the costs incurred to-date is included in
B2H IRP portfolio modeling.
Additional Costs Applied to B2H
In addition to the base costs of the B2H project, the company also applied additional costs to
the B2H project in the 2021 IRP modeling. These costs have been previously discussed in this
appendix and are: 1) costs for local interconnection upgrades totaling approximately
$35 million, and 2) costs for Borah West and Midpoint West upgrades necessary to facilitate the
PAC asset exchange, detailed in the 2022 Term Sheet and B2H Project Partner Update section
of this appendix, totaling approximately $47 million.
Cost-Estimate Conclusions
The cost estimate for B2H has been thoroughly vetted. Idaho Power used third-party
contractors with industry experience, relied on PAC and BPA recent transmission line
construction experience, and benchmarked against multiple recent high-voltage
transmission line investments in the West to arrive at the B2H construction cost estimate.
Material quantities and construction methods are well understood because the B2H project is
using BPA’s standard tower and conductor design for 500 kV lines. The cost estimate for the
project will be further refined as the project design develops toward completion.
Transmission Revenue
The B2H transmission line project is modeled in AURORA as additional transmission capacity
available for Idaho Power energy purchases from the Pacific Northwest. In general, for new
supply-side resources modeled in the IRP process, surplus sales of generation are included as
a cost offset in the AURORA portfolio modeling. Transmission wheeling revenues,
however, are not included in AURORA calculations. To remedy this inconsistency, in the 2021
IRP, Idaho Power modeled incremental transmission wheeling revenue from non-native load
customers as an annual revenue credit for B2H portfolios, representing a reduction in project
costs and ultimately benefiting Idaho Power retail customers.
2021 IRP Portfolio Transmission Cost Assumptions
Page 62 2021 Integrated Resource Plan—Appendix D
Idaho Power’s transmission assets are funded by native load customers, network customers,
and point-to-point transmission wheeling customers based on a ratio of each party’s usage of
the transmission system. For the 2021 IRP, Idaho Power modeled B2H assuming the company
has a 45% ownership interest and is providing transmission service to BPA, with BPA
transmission wheeling payments acting as a cost-offset to the overall B2H project costs.
Idaho Power also modeled the change in PAC point-to-point usage. Portfolios involving B2H
result in a higher FERC transmission rate than portfolios without B2H. Although B2H provides
significant incremental capacity, and will likely result in increased transmission sales,
Idaho Power assumed flat short-term and non-firm transmission sales volume as a
conservative assumption.
Idaho Power’s FERC transmission rate is calculated as follows: 𝑇𝑇𝑡𝑡𝑡𝑡𝐶𝐶𝐿𝐿𝑇𝑇𝑡𝑡𝐿𝐿𝐿𝐿𝑡𝑡𝐿𝐿𝐶𝐶 𝑅𝑅𝑡𝑡𝑡𝑡𝐸𝐸=𝑇𝑇𝑡𝑡𝑡𝑡𝐶𝐶𝐿𝐿𝑇𝑇𝑡𝑡𝐿𝐿𝐿𝐿𝑡𝑡𝐿𝐿𝐶𝐶 𝐶𝐶𝐿𝐿𝐿𝐿𝑡𝑡𝐿𝐿 ($)𝑇𝑇𝑡𝑡𝑡𝑡𝐶𝐶𝐿𝐿𝑇𝑇𝑡𝑡𝐿𝐿𝐿𝐿𝑡𝑡𝐿𝐿𝐶𝐶 𝑈𝑈𝐿𝐿𝑡𝑡𝑠𝑠𝐸𝐸 (𝑀𝑀𝑀𝑀∗𝑦𝑦𝐸𝐸𝑡𝑡𝑡𝑡)
Per the formula above, transmission costs will increase following the installation of B2H,
and transmission usage will adjust with the company providing increased transmission service
associated with additional BPA network load, and reduced transmission service corresponding
to PAC’s net point-to-point usage declining. To calculate the B2H cost offset annual revenue
stream, the company calculated the difference between two scenarios:
1. The B2H third-party transmission revenues it would receive assuming the 2021 IRP
Preferred Portfolio; and
2. the third-party transmission revenues it would receive in a case without the addition of
B2H assuming PAC continues to utilize 510 MW of point-to-point service, and BPA finds
an alternative long-term plan for serving its customers in southeast Idaho (B2H is
currently the plan that they are pursuing).
The difference between these two scenarios represents the B2H cost offset annual revenue
stream that was applied as a reduction to B2H overall costs.
Due to significant increase in capacity that B2H provides to the Idaho to Northwest path,
Idaho Power believes firm, short-term firm, and non-firm usage of the Idaho Power
transmission system by third parties could increase. This belief is supported by the over
1,000 MWs of transmission requests that the company has seen across the Idaho to Northwest
path over the past 18 months. Additionally, Idaho Power’s acquisition of 200 MW of
bidirectional capacity to Four Corners, New Mexico will only further enhance the value of the
company transmission system to third parties. These potential revenues would further reduce
the cost of the project, however, to be conservative, Idaho Power assumed a constant
transmission usage by third parties (no increase or decrease) from an average of usage over
recent years.
Risk
2021 Integrated Resource Plan—Appendix D Page 63
RISK
Risk is inherent in any infrastructure development project. The sections below address various
risks associated with the B2H project. Combining the analysis below with the risk analysis
conducted in the 2021 IRP, B2H is the lowest-risk resource to meet Idaho Power’s
resource needs.
Capacity, Cost, and In-Service Date Risk
The company evaluated the following risks extensively in the 2021 IRP:
• Capacity Risk: As part of the 2021 IRP, 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.
• Cost Risk: Evaluating cost risks to ensure cost-effectiveness (i.e., a tipping point analysis)
is an important consideration when planning for a project.
• In-Service Date Risk: The current planned in-service date for B2H is prior to the summer
of 2026. The company evaluated the impacts of a 2027 in-service date.
A description of each of these risks can be found in the 2021 IRP Chapter 10—Modeling
Analysis and Results, starting on page 144 of the document.
Regarding cost risk, the 2021 IRP portfolio Net Present Value (NPV) cost for B2H is
approximately $160 million (this is the NPV cost incurred within the 20-year planning window)
assuming a 0% contingency amount. The difference between the Preferred Portfolio,
and the best alternative portfolio that did not include B2H was approximately a $266 million
NPV. Therefore, B2H costs could increase by nearly 165% and the project would remain
cost effective.
Liquidity and Market Sufficiency Risk
This risk was partially addressed by the capacity risk evaluation detailed starting on page 144 of
the 2021 IRP. As part of the 2021 IRP, 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. Of note, should market capacity ever become limited, this will not
reduce B2H’s capacity. The company would have the flexibility to acquire or develop another
resource in the Pacific Northwest, potentially in eastern Oregon, and repurpose B2H
transmission capacity to continue to meet its customers’ needs. As discussed in the Flexibility
section of this appendix, a transmission line like B2H will facilitate the transfer of any
generation technology, ensuring Idaho Power customers always have access to the most
economic resources, regardless of the resource type.
Risk
Page 64 2021 Integrated Resource Plan—Appendix D
Focusing on the market, the Pacific Northwest is a winter peaking region. Pacific Northwest
utilities continue to install and build generation capacity to meet winter peak regional needs.
Idaho Power operates a system with a summer peak. Idaho Power’s peak typically occurs in the
late June/early July timeframe. The Idaho Power summer peak aligns with the Mid-C hydro
runoff conditions when the Pacific Northwest is flush with surplus power capacity. The existing
transmission system between the Pacific Northwest and Idaho Power is constrained.
Constructing B2H will alleviate this constraint and add 1,050 MW of total transfer capability
between the Pacific Northwest and the Intermountain West region. The Pacific Northwest and
Idaho Power will significantly benefit from the addition of transmission capacity between the
regions. The Pacific Northwest has constructed power plants to meet winter needs and would
benefit from selling energy to Idaho Power in the summer. Idaho Power needs generation
capacity to serve summer peak load, and a transmission line to existing underutilized power
plants is much more cost-effective than building a new power plant.
See the Market Overview section of this appendix for more information about the Mid-C
market hub liquidity. Based on the risk assessment, Idaho Power believes sufficient market
liquidity exists.
The following data points will address the market sufficiency risk.
Data Point 1: Peak Load Analysis from Table 8
Referencing Table 8 from the B2H Benefits and Values section, British Columbia and other
utilities in the Pacific Northwest18 have forecast 2030 winter peaks that exceed their forecast
2030 summer peaks by a combined 8,200 MW. Given the difference in seasonal peaks,
coupled with Columbia runoff hydro conditions aligning with Idaho Power’s summer peak,
resource availability in the Pacific Northwest during Idaho Power’s summer peak is highly likely.
Data Point 2: 2019 Pacific Northwest Loads and
Resources Study—BPA
Idaho Power’s review of recent regional resource adequacy assessments also included the
Pacific Northwest Loads and Resources Study by the BPA (White Book). The most recent BPA
adequacy assessment report was released October 2020 and evaluates resource adequacy from
2021 through 2030.19 Idaho Power concludes from this analysis that: 1) summer capacity will be
available in the future, and 2) additional summer capacity will likely be added as the region

18 Load serving entities from Table 8 included in stated figure are Avista, BPA, British Columbia, Chelan, Douglas,
Grant, PAC–West, Portland General, Puget Sound, Seattle City, and Tacoma.
19 BPA. 2019 Pacific Northwest loads and resources study (2019 white book). Technical Appendix, Volume 2:
Capacity Analysis. bpa.gov/p/Generation/White-Book/wb/2019-WBK-Technical-Appendix-Volume-2-Capacity-
Analysis.pdf . Accessed November 24, 2021.
Risk
2021 Integrated Resource Plan—Appendix D Page 65
adds resources to meet winter peak demand. BPA considers regional load diversity
(i.e., winter- or summer-peaking utilities) and expected monthly production from the Pacific
Northwest hydroelectric system under the critical case water year for the region (1937).
Canadian resources are excluded from the BPA assessment. New regional generating projects
are included when those resources begin operating or are under construction and have a
scheduled on-line date. Similarly, retiring resources are removed on the date of the announced
retirement. Resource forecasts for the region assume the retirement of the following coal
projects over the study period:
Table 17. Coal retirement forecast
Resource Retirement Date
Centralia 1 December 1, 2020
Boardman January 1, 2021
Valmy 1 January 1, 2022
Colstrip 1 June 30, 2022
Colstrip 2 June 30, 2022
Centralia 2 December 1, 2025
Valmy 2 January 1, 2026

Figure 9. BPA white book PNW surplus/deficit one-hour capacity (1937 critical water year)

(3,000.00)
(2,000.00)
(1,000.00)
0.00
1,000.00
2,000.00
3,000.00
4,000.00
5,000.00
6,000.00
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
MW
January July
Risk
Page 66 2021 Integrated Resource Plan—Appendix D
Data Point 3: FERC Form 714 Load Data
For illustrative purposes, Idaho Power downloaded peak load data reported through FERC Form
714 for the major Pacific Northwest entities in Washington and Oregon: Avista, BPA,
Chelan County PUD, Douglas County PUD, Eugene Water and Electric Board, Grant County PUD,
PGE, Puget Sound Energy, Seattle City Light, and Tacoma (PAC West data was unavailable).
The coincident sum of these entities’ total load is shown in Figure 10.

Figure 10. Peak coincident load data for most major Washington and Oregon utilities
Figure 10 illustrates a wide difference between historical winter and summer peaks for the
Washington and Oregon area in the region. Other considerations, not depicted,
include Canada’s similar winter- to summer-peak load ratio (winter peaking), and the increased
ability of the Pacific Northwest hydro system in late June through early July compared to the
hydro system’s capability in the winter (more water in early summer compared to winter).
Data Point 4: Northwest and California Renewable Portfolio Standards
The adoption of more aggressive Renewable Portfolio Standard (RPS) goals by states such as
California, Oregon, and Washington will drive policy-driven resource additions. The RPS goals
will also likely result in more solar generation throughout the region and additional
dispatchable flexible ramping resources, such as battery storage. Solar and solar plus storage
align very well with summer peak needs, but their value can be limited in the winter months.
Meeting winter needs will require the Pacific Northwest region to overbuild these resources
15,000
17,000
19,000
21,000
23,000
25,000
27,000
29,000
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
MW
Winter Summer
Risk
2021 Integrated Resource Plan—Appendix D Page 67
above the level to meet a similar a summer demand, which will continue to align well with
Idaho Power looking to access summer energy from the market.
Data Point 5: Potential Resources from Northwest Utility IRPs
The 2021 PNUCC
Northwest Regional
Forecast includes a list of
potential new resources
reported by northwest
utilities in their integrated
resource plans to meet
their own needs.
The forecasted new
resource list from the
report is shown in Table
18. The list of resources
includes 6,389 MW of
planned new resources
through 2031. As
expected, the NW utilities
are continuing to plan for
growing winter peak
demands by adding
capacity resources.
Many of these resource
additions, such as solar
and storage installations,
will have a much higher
Effective Load Carrying
Capability (ELCC) for the
summer season, furthering
the depth of the market
for the summer season.
Table 18. Potential New Resources Identified by Regional Utilities (PNUCC)*

*PNUCC-2021-Northwest-Regional-Forecast-Final.pdf
Risk
Page 68 2021 Integrated Resource Plan—Appendix D
Market Sufficiency and Liquidity Conclusions
The analysis summarized above and in the Markets section of this report provide strong
evidence that there will be sufficient resources in the future to utilize the B2H transmission line.
Siting Risk
Any new infrastructure projects, from generation projects to transmission lines, comes with
siting risk. The BLM ROD, which was released on November 17, 2017, was a significant
milestone in the B2H project development and greatly minimized siting risk by authorizing the
project on 85.6 miles of BLM-administered land. The United States Forest Service also issued a
ROD authorizing the project on 8.6 miles of National Forest land in 2018, and the United States
Navy issued a ROD in 2019 authorizing the project on 7.1 miles of Navy land. The BLM and
Forest Service RODs were upheld by the United States District Court for the District of
Oregon.20
The issuance of a site certificate by the Oregon EFSC is the next major step in the siting process.
In 2020, ODOE issued its Proposed Order recommending approval of the project. That Proposed
Order, however, is being challenged by third-parties in an ongoing Contested Case proceeding
and will ultimately be subject to review and approval by EFSC, and the EFSC’s decision will be
subject to appeal before the Oregon Supreme Court. Until EFSC makes its final decision on the
Site Certificate, which Idaho Power expects by the end of 2022, and any appeal is resolved,
there remains some siting risk.
Schedule Risk
As of the date of this appendix, Idaho Power’s scheduled B2H in-service date is 2026 or
later. At a high level, remaining activities prior to energization are: permitting, preliminary
construction, material procurement, and construction.
As noted above, the permitting phase of the project is ongoing. For federal permitting, the B2H
project achieved the biggest schedule milestone to date with the release of BLM’s ROD on
November 17, 2017, and subsequent ROW grant in January 2018 authorizing the project on
BLM-administered lands. The United States Forest Service ROD was issued in November 2018
and a right-of-way easement was issued in May 2019. A Navy ROD was issued in September
2019 and a Navy easement was issued in May 2020. The project is on track to receive the
federal notice to proceed in 2023.
For the State of Oregon permitting process, the B2H project also achieved a considerable
milestone in summer 2017 with the submittal of the Amended Application for Site Certificate to

20 Stop B2H Coalition v. Bureau of Land Management, No. 2:19-cv-1822-SI, Order and Opinion (D. Or.
August 4, 2021).
Risk
2021 Integrated Resource Plan—Appendix D Page 69
the ODOE and an application completeness determination from ODOE in fall 2018. ODOE issued
a Proposed Order in July 2020, and EFSC is expected to issue its decision on the Site Certificate
in 2022. The EFSC permitting process is a critical path schedule activity. Schedule risk exists for
the EFSC permitting process if the EFSC does not issue a Site Certificate in 2022.
With the receipt of the BLM ROD and ROW easement, and a Proposed Order from ODOE,
sufficient route certainty exists to continue with preliminary construction tasks. At the time of
writing, Idaho Power is actively working on the following activities: detailed design, ROW option
acquisition, legal surveys, and geotechnical investigation. Construction activities are expected
to commence in 2023 with the expected project in-service date in 2026.
Catastrophic Event Risk
As detailed in B2H Design section of this appendix, the B2H transmission line is designed to
withstand a variety of extreme weather conditions and catastrophic events. Like most
infrastructure, the B2H project is susceptible to direct physical attack. However, unlike some
other supply-side resources, B2H adds to the resiliency of the electrical grid by providing
additional capacity and an additional path to transfer energy throughout the region should a
physical attack or other catastrophic event occur elsewhere on the system.
Additionally, Idaho Power also keeps a supply of emergency transmission towers that can be
quickly deployed to replace a damaged tower, allowing the transmission line to be quickly
returned to service.

Project Activities
Page 70 2021 Integrated Resource Plan—Appendix D
PROJECT ACTIVITIES
Schedule Update
Permitting
The B2H projected achieved a major milestone with the release of the BLM ROD on
November 17, 2017, and the ROW grant on January 9, 2018. These actions formalized the
conclusion of the siting process and federally required NEPA process. The BLM ROD and ROW
grant provides the B2H project the ability to site the project on BLM-administered land.
The BLM-led NEPA process took nearly 10 years to complete and involved extensive
stakeholder input. Refer to the Project History and Route History sections of this report for
more information on project history and public involvement. With the issuance of the United
States Forest Service ROD and easement, and the issuance of the United States Navy ROD,
all major federal decision records have been achieved.
For the State of Oregon permitting process, Idaho Power submitted the Amended Application
for Site Certificate to the ODOE in summer 2017 and ODOE issued a Proposed Order in July
2020. A decision on the Site Certificate from the EFSC is expected in 2022.
The NEPA and EFSC processes are separate and distinct permitting processes and not
necessarily designed to work simultaneously. At a high level, the NEPA EIS process evaluates
reasonable alternatives to determine the best alternative (the Agency Preferred Alternative)
at the end of the process. Comparative analysis is conducted at a “desktop” level. Information is
brought into the process on a phased approach. Detailed analysis must be conducted on the
final route prior to construction, generally once final design is complete.
The Oregon EFSC process is a standards-based process based on a fixed site boundary. For a
linear facility, like a transmission line, the process requires the transmission line boundary to be
established (a route selected) and fully evaluated to determine if the project meets established
standards. The practical effect of the EFSC standards-based process required the NEPA process
be far enough along to conduct field studies and other technical analyses to comply with
standards. Idaho Power conducted field surveys and prepared the EFSC application in parallel
with the NEPA process. The EFSC application is lengthy, coming in at over 20,000 pages.
Post-Permitting
To achieve an in-service date in 2026, preliminary construction activities have commenced
parallel to EFSC permitting activities. Preliminary construction activities include, but are not
limited to, the following:
• Geotechnical explorations
• Detailed ground surveys
Project Activities
2021 Integrated Resource Plan—Appendix D Page 71
• LiDAR aerial mapping
• Sectional surveys
• ROW option acquisition activities
• Detailed design
• Construction bid package development and construction contractor selection
After the Oregon permitting process and preliminary construction activities conclude,
construction activities can commence. Construction activities include, but are not limited to,
long-lead material acquisition, transmission line construction, and substation construction.
The preliminary construction activities must commence several years prior to construction.
The material acquisition and construction activities are expected to take approximately 3 years.
The specific timing of each of the preliminary construction and construction activities will be
coordinated with the project coparticipants.
Conclusion
Page 72 2021 Integrated Resource Plan—Appendix D
CONCLUSION
As the B2H project nears its construction phase, the 2021 IRP shows that the B2H project
remains a key component of the company’s Preferred Portfolio of future resources.
Additionally, project certainty continues to grow with Idaho Power, PAC, and BPA executing a
2022 Term Sheet related to the B2H project on January 18, 2022. The parties entered this 2022
Term Sheet after jointly funding the permitting of the B2H project over the past decade and
over two years of discussions related to next steps associated with the B2H project.
As part of the 2022 Term Sheet, BPA will transition out of its role as a joint B2H permitting
coparticipant and will instead take transmission service from Idaho Power to serve its southeast
Idaho customers. Idaho Power will increase its B2H ownership to 45.45% by acquiring BPA’s
B2H capacity. Idaho Power’s B2H capacity will increase from an average of 350 MW west-to-
east to 750 MW west-to-east, and Idaho Power will utilize a portion of its increased B2H
capacity to provide BPA transmission service across southern Idaho.
As part of the larger transaction, Idaho Power and PAC also plan to complete an asset exchange
to align transmission ownership with each party’s long-term strategy. Idaho Power will acquire
PAC transmission assets and their related capacity sufficient to enable Idaho Power to utilize
200 MW of bidirectional transmission capacity between the Idaho Power system (Populus)
and Four Corners Substation in New Mexico. Idaho Power will also acquire PAC assets around
the Goshen area necessary to provide transmission service to BPA to serve their southeast
Idaho customers. Idaho Power will be relieved of its 510 MW of transmission service obligations
to PAC across southern Idaho, freeing up capacity the company plans to utilize to integrate
additional southern Idaho renewable resources.
This B2H 2021 IRP appendix provides context and details that support evaluating the B2H
transmission line project as a supply-side resource, explores many of the ancillary benefits
offered by the transmission line, and considers the risks and benefits of owning a transmission
line connected to a market hub in contrast to direct ownership of a traditional
generation resource.
As discussed in this report, once operational, B2H will provide Idaho Power increased access to
reliable, clean, low-cost market energy purchases from the Pacific Northwest. B2H (including
early identification of need that ultimately became the project) has been a cost-effective
resource identified in each of Idaho Power’s IRPs since 2006 and continues to be a cornerstone
of Idaho Power’s 2021 IRP Preferred Portfolio.
The B2H project brings additional benefits beyond cost-effectiveness. The B2H project will
increase the efficiency, reliability, and resiliency of the electric system by creating an additional
pathway for energy to move between major load centers in the West. The B2H project also
provides the flexibility to integrate renewable energy and move existing resources during times
Conclusion
2021 Integrated Resource Plan—Appendix D Page 73
of congestion, benefiting customers throughout the region. Idaho Power believes B2H provides
value to the system beyond any individual resource because it enhances the flexibility of the
existing system and facilitates the delivery of cost-effective resources not only to Idaho Power
customers, but also to customers throughout the Pacific Northwest and Mountain
West regions.
The company must demonstrate a need for the project before EFSC will issue a Site Certificate
authorizing the construction of a transmission line. Pursuant to EFSC’s least-cost plan rule,
the need demonstration can be met through a commission acknowledgement of the resource
in the company’s IRP.21 The OPUC has already acknowledged the construction of B2H in
Idaho Power’s 2017 and 2019 IRPs. Idaho Power asks the OPUC to confirm its
acknowledgement of B2H in the company’s 2021 IRP.

21 OAR 345-023-0020(2).
Appendix D-1
Page 74 2021 Integrated Resource Plan—Appendix D
Appendix D-1. Transmission line alternatives to the proposed B2H 500 kV transmission line
Table D-1
Comparison of Transmission Line Capacity Scenarios—New Lines from Longhorn to Hemingway
Scenario
Line
Capacity1
Potential Path 14
West-East Increase2
Losses on New
Circuit(s)3
a. Longhorn to Hemingway 230 kV single circuit 956 MW 525 MW 10.8%
b. Longhorn to Hemingway 230 kV double circuit 1,912 MW 915 MW 9.5%
c. Longhorn to Hemingway 345 kV single circuit 1,434 MW 730 MW 6.6%
d. Longhorn to Hemingway 500 kV single circuit 3,214 MW 1,050 MW 4.2%
e. Longhorn to Hemingway 500 kV—two separate lines 6,428 MW 2,215 MW 3.7%
f. Longhorn to Hemingway 500 kV double circuit 6,428 MW 1,235 MW 2.9%
g. Longhorn to Hemingway 765 kV single circuit 4,770 MW 1,200 MW 2.4%
1 Line Capacity is the thermal rating of the assumed conductors and does not account for system limitations of voltage, stability, or reliability requirements.
2 Potential Rating is based upon study results to date to meet reliability design requirements for the WECC ratings processes, not including
simultaneous interaction studies.
3 Estimated Losses are percent losses for the new line at the Potential Rating loading level. Annual energy losses are dependent on total system loss reductions. All of the scenarios would likely yield a total system loss reduction for the flow levels above.
Table D-2
Comparison of Transmission Line Capacity Scenarios—Rebuild Existing Lines to the Northwest
Scenario Line Capacity1 Potential Path 14 Increase2 Losses on New Circuit(s)3 Length of Line/ New ROW4
h. Replace Oxbow-Lolo 230 kV with
Hatwai–Hemingway 500 kV
3,214 MW 430 MW W-E
675 MW E-W
3.8% 255 Miles/136 Miles
i. Replace Oxbow-Lolo 230 kV with
Hatwai–Hemingway 500 kV—No double
circuiting with existing lines
3,214 MW 710 MW W-E
745 MW E-W
4.1% 255 Miles/167 Miles
j. Replace Walla Walla to Brownlee
230 kV with Sacajawea Tap–Hemingway
500 kV
3,214 MW 400 MW W-E
675 MW E-W
3.5% 288 Miles/150 Miles
k. Replace Walla Walla to Pallette
230 kV with Sacajawea Tap–Hemingway
500 kV—No double circuiting with
existing lines
3,214 MW 720 MW W-E
730 MW E-W
3.8% 288 Miles/181 Miles
l. Build double circuit 500 kV/230 kV
line from McNary to Quartz. Build
500kV from Quartz to Hemingway.
3,214 MW 765 MW W-E
870 MW E-W
3.9% 298 Miles/168 Miles
1 Line Capacity is the thermal rating of the assumed conductors and does not account for system limitations of voltage, stability,
or reliability requirements.
2 Potential Rating is based upon study results to date to meet reliability design requirements for the WECC ratings processes, not including
simultaneous interaction studies.
3 Estimated Losses are percent losses for the new line at the Potential Rating west-east loading level. Annual energy losses are dependent on
total system loss reductions. All of the scenarios would likely yield a total system loss reduction for the flow levels above.
4 In addition to utilizing existing 230 kV right-of-way (“ROW”), each of the scenarios above will require new ROW to be obtained.
Appendix D-2
2021 Integrated Resource Plan—Appendix D Page 75
Appendix D-2. B2H project history, public participation, project activities, route history, and a detailed list of
notable project milestones
B2H Project History
The B2H project originated from Idaho Power’s 2006 IRP. The 2006 IRP specified 285 MW of
additional transmission capacity, increasing Idaho Power’s connection to the Pacific Northwest
power markets, as a resource in the preferred resource portfolio. A project had not been fully
vetted at that time but was described as a 230 kV transmission line between McNary Substation
and Boise. After the initial identification in the 2006 IRP, Idaho Power evaluated numerous
capacity upgrade alternatives. Considering distance, cost, capacity, losses, and substation
termination operating voltages, Idaho Power determined a new 500 kV transmission line
between the Boardman, Oregon, area, and the proposed Hemingway 500 kV Substation would
be the most cost-effective method of increasing capacity. Refer to Appendix D-1 for more
information on the upgrade options considered.
Transmission capacity, especially at 500 kV, can be described as “lumpy” because capacity
increments are relatively large between the different transmission operating voltages. In the
2009 IRP, Idaho Power assumed 425 MW of capacity, which was 50% of the assumed total
rating. Idaho Power’s long-standing preference was to find a partner or partners to construct
B2H with to take advantage of economies of scale. In the 2011 IRP, Idaho Power assumed
450 MW of capacity. In 2012, Idaho Power achieved two major milestones: 1) PAC and BPA
officially joined the B2H project as permitting coparticipants, and 2) Idaho Power received a
formal capacity rating for the B2H project via the WECC Path Rating Process (more on this
process later in the Capacity Rating–WECC Rating Process section). In the 2013 IRP,
Idaho Power began to use the negotiated capacity from the permitting agreement: 500 MW in
the summer and 200 MW in the winter, a yearly average of 350 MW, for a cost allocation of
21% of the total project. Idaho Power used the same 21% interest in the 2015, 2017,
and 2019 IRPs.
At the beginning of 2022, Idaho Power, PAC, and BPA executed a Non-Binding Term Sheet
(2022 Term Sheet) that addresses B2H ownership, transmission service considerations, and
asset exchanges. As part of the 2022 Term Sheet, BPA will transition out of its role as a joint
B2H permitting partner and will instead take transmission service from Idaho Power to serve its
customers. Idaho Power will increase its B2H ownership to 45.45% by acquiring BPA’s B2H
capacity and will utilize a portion of this increased capacity to provide BPA transmission service
across southern Idaho.
In the 2021 IRP, Idaho Power modeled B2H assuming the 2022 Term Sheet specified 45.45%
project ownership share.
Appendix D-2
Page 76 2021 Integrated Resource Plan—Appendix D
B2H Public Participation
The B2H project development has involved considerable stakeholder interaction since its
inception. Idaho Power has hosted and participated in almost 300 public and stakeholder
meetings with an estimated 4,500+ participants. After approximately a year of public scoping in
2008, Idaho Power paused the federal and state review process and initiated a year-long
comprehensive public process to gather more input. This community advisory process (CAP)
took place in 2009 and 2010. The four objectives and steps of the CAP were as follows:
1. Identify community issues and concerns.
2. Develop a range of possible routes that address community issues and concerns.
3. Recommend proposed and alternate routes.
4. Follow through with communities during the federal and state review processes.
Through the CAP, Idaho Power hosted 27 Project Advisory Team meetings, 15 public meetings,
and 7 special topic meetings. In all, nearly 1,000 people were involved in the CAP,
either through Project Advisory Team activities or public meetings.
Ultimately, the route recommendation from the CAP was the route Idaho Power brought into
the NEPA process as the proponent-recommended route. The NEPA process included additional
opportunities for public comment at major milestones, and Idaho Power worked with
landowners and communities along the way. Ultimately, the route selected through the NEPA
process was based on the BLM’s analysis and public input. For more information, please visit
the B2H website.
Throughout the BLM’s NEPA process, including development of the Draft Environmental Impact
Statement (EIS), issued December 19, 2014, and prior to the Final EIS, issued November 22,
2016, Idaho Power worked with landowners, stakeholders, and jurisdictional leaders on route
refinements and to balance environmental impacts with impacts to farmers and ranchers.
For example, Idaho Power met with the original “Stop Idaho Power” group in Malheur County
to help the group effectively comment and seek change from the BLM when the Draft EIS
indicated a preference for a route across Stop Idaho Power stakeholder lands. BLM’s decision
was modified, and the route moved away from an area of highly valued agricultural lands in the
Final EIS almost two years later.
Idaho Power worked with landowners in the Baker Valley, near the National Historic Oregon
Trail Interpretive Center (NHOTIC), to move an alternative route along fence lines to minimize
impacts to irrigated farmland, where practicable. This change was submitted by the landowners
and included in the BLM’s Final EIS and ROD (issued November 17, 2017). Another change in
Baker County was in the Burnt River Canyon and Durkee area, where Idaho Power worked with
the BLM and affected landowners to find a more suitable route than what was initially
Appendix D-2
2021 Integrated Resource Plan—Appendix D Page 77
preferred in the Draft EIS. Idaho Power is still working with landowners and local jurisdictional
leaders to microsite in these areas to minimize impacts.
Unfortunately, the route preferences of Idaho Power and the local communities aren’t always
reflected in the BLM’s Agency Preferred route. For example, Idaho Power had worked in the
Baker County area to propose a route on the backside of the NHOTIC (to the east) to minimize
visual impacts, and in the Brogan area, to avoid landowner impacts. However, both route
variations went through priority sage grouse habitat and were not adopted in BLM’s Agency
Preferred route.
However, Idaho Power worked with Umatilla County, local jurisdictional leaders,
and landowners to identify a new route through the entire county, essentially moving the
line further south and away from residences, ranches, and certain agriculture. This southern
route variation through Umatilla County was included the BLM’s Agency Preferred route.
At the urging of local landowners along Bombing Range Road in Morrow County, Idaho Power
has been working with local jurisdictional leaders, delegate representatives,
farmers, ranchers, and other interested parties to gain the Navy’s consideration of an
easement along the eastern edge of the Boardman Bombing Range. This cooperative effort
with the local area has benefited the project, providing an approach that meets the interests
and common good for all the noted parties in the local area. A major milestone was achieved
when the United States Navy issued a Record of Decision for the proposed route in
September 2019.
Finally, in Union County Idaho Power worked with local jurisdictional leaders, stakeholder
groups, such as the Glass Hill Coalition and some members of StopB2H (prior to that group’s
formation) to identify new route opportunities. The Union County B2H Advisory Commission
agreed to submit a route proposal to the BLM that followed existing high-voltage transmission
lines, which was later identified as the Mill Creek Alternative. At the same time, Idaho Power
met with a large landowner to adjust the Morgan Lake Alternative route to minimize impacts.
Idaho Power understood that both the Mill Creek and Morgan Lake route variations were
favored over BLM’s Agency Preferred Alternative (referred to as the Glass Hill Alternative)
by local landowners, the Glass Hill Coalition, several stakeholders, and the Confederated Tribe
of the Umatilla Indian Reservation due to concerns of impacts on areas that had no prior
development.
Idaho Power continued support of the community-favored routes in its Application for Site
Certificate filed with ODOE in September 2018. Idaho Power will work with Union County and
local stakeholders to determine the route preference between the Morgan Lake and Mill Creek
alternatives. As of the date of the filing of the 2021 IRP, Idaho Power understands that the
Appendix D-2
Page 78 2021 Integrated Resource Plan—Appendix D
Morgan Lake route alternative, on balance, appears to be preferred by the majority of the
groups previously identified.
Project Activities
Below is a summary of notable activities by year since project inception.
2006
Idaho Power files its IRP with a transmission line to the Pacific Northwest identified in the
preferred resource portfolio.
2007
Idaho Power analyzes the capacity and cost of different transmission line operating voltages
and determines a new 500 kV transmission line to be the most cost-effective option to increase
capacity and meet customer needs. Idaho Power files a Preliminary Draft Application for
Transportation and Utility Systems and Facilities on Federal Lands. Idaho Power scopes routes.
2008
Idaho Power submits application materials to the BLM. Idaho Power submits a Notice of Intent
to the EFSC. The BLM issues a Notice of Intent to prepare an EIS; officially initiating the BLM-led
federal NEPA process. Idaho Power embarks on a more extensive public outreach program to
determine the transmission line route.
2009
Idaho Power pauses NEPA and EFSC activities to work with community members throughout
the route as part of the CAP to identify a proposed route that would be acceptable to both
Idaho Power and the public. Forty-nine routes and/or route segments were considered
through CAP.
2010
The CAP concludes. Idaho Power resubmits a proposed route to the BLM based on input from
the CAP. The BLM re-initiates the NEPA scoping process and solicits public comments.
Idaho Power publishes its B2H Siting Study. Idaho Power files a Notice of Intent with EFSC.
2011
Additional public outreach resulted in additional route alternatives submitted to the BLM.
The Obama Administration recognizes B2H as one of seven national priority projects.22

22 obamawhitehouse.archives.gov/administration/eop/ceq/initiatives/interagency-rapid-response-team-for-
transmission
Appendix D-2
2021 Integrated Resource Plan—Appendix D Page 79
2012
The ODOE conducts informational meetings and solicits comments. The ODOE issues a Project
Order outlining the issues and regulations Idaho Power must address in its Application for Site
Certificate. Additional public outreach and analysis resulted in route modifications and
refinements submitted to the BLM. Idaho Power issues a Siting Study Supplement. Idaho Power
conducts field surveys for the EFSC application. WECC adopts a new Adjacent Transmission
Circuits definition with a separation distance of 250 feet, which would later modify routes in
the EIS process. Idaho Power receives a formal capacity rating from WECC.
2013
Public meetings are held. Idaho Power submits its Preliminary Application for Site Certificate to
the ODOE. The BLM releases preliminary preferred route alternatives and works on a Draft EIS.
2014
The BLM issues a Draft EIS identifying an Agency Preferred Alternative. The 90-day comment
period opens. Idaho Power conducts field surveys for EFSC application.
2015
The BLM hosts open houses for the public to learn about the Draft EIS, route alternatives,
environmental analysis. The BLM reviews public comments. Idaho Power notifies the BLM of a
preferred termination location, Longhorn Substation. Idaho Power submits an application to
the Navy for an easement on the Naval Weapons System Training Facility in Boardman.
Idaho Power conducts field surveys for the EFSC application.
2016
Idaho Power submits a Draft Amended Application for Site Certificate to the ODOE for review.
The BLM issues a Final EIS identifying an environmentally preferred route alternative and an
Agency Preferred route alternative. Idaho Power incorporates the Agency Preferred route
alternative into the EFSC application material. Idaho Power collaborates with local area
stakeholders to find a routing solution on Navy-owned land. Idaho Power submits a revised
application to the Navy. Idaho Power conducts field surveys for the EFSC application.
2017
Idaho Power submits an Amended Application for Site Certificate to the ODOE. The BLM issues
a Record of Decision.
2018
ODOE and Idaho Power conduct public meetings after ODOE determined the Application for
Site Certificate was complete. The Oregon PUC issues Order No. 18-176 in Docket No. LC 68
Appendix D-2
Page 80 2021 Integrated Resource Plan—Appendix D
specifically acknowledging Idaho Power’s 2017 IRP and action items related to B2H. The United
States Forest Service issues its ROD. Idaho Power prepares and submits a Geotechnical Plan of
Development to the BLM for approval.
2019
The United States Forest Service issues right-of-way (ROW) easement. ODOE issues a Draft
Proposed Order (DPO). The United States Navy issues its ROD. BPA issues a ROD for moving the
existing 69 kV line from Navy property to accommodate B2H. Idaho Power coordinates with
BLM on Geotechnical Plan of Development.
2020
The United States Navy issues an easement for the B2H project. Based on the DPO, ODOE issues
a Proposed Order and notice for Contested Case. Preparations begin for several
pre-construction activities, which include completing LiDAR (aerial mapping) for the entire B2H
project route and preparations for initiating detailed design.
2021
Idaho Power and reviewing agencies continue to meet with interested groups,
affected landowners, community leaders, and elected officials. Idaho Power continues to
conduct fieldwork to inform the state and federal review processes. The BLM continued NHPA
Section 106 consultation. The ODOE continued with its contested case proceeding. A federal
court ruled against a lawsuit brought against the BLM and United States Forest Service (USFS)
regarding their ROD for B2H. Detailed design, geotechnical investigation, right-of-way option
acquisition, and survey work begins.
B2H Route History
As stated previously, the need for the B2H project was first identified in the 2006 IRP. At that
time, the transmission line was contemplated as a line between Boise and McNary. The project
evolved into a 500 kV line between the Boardman area and the Hemingway Transmission
Station. During scoping and the CAP process, a considerable number of routes through western,
central, and eastern Oregon, and southern Washington were considered to connect
Hemingway and the Boardman area. Figure D-1 is a snapshot the routes considered during
this timeframe.
Appendix D-2
2021 Integrated Resource Plan—Appendix D Page 81

Figure D-1. Routes developed by the Community Advisory Process teams (2009 timeframe)
Appendix D-2
Page 82 2021 Integrated Resource Plan—Appendix D
The CAP process resulted in Idaho Power submitting the route shown in Figure D-2 as the
company’s proposed route in the BLM-led NEPA process.

Figure D-2. B2H proposed route resulting from the Community Advisory Process (2010 timeframe)
Appendix D-2
2021 Integrated Resource Plan—Appendix D Page 83
The BLM considered Idaho Power’s proposed route, along with a few other reasonable
alternative routes, in the NEPA process. Figure D-3 shows the route alternatives and variations
considered in the BLM’s November 2016 Final EIS.

Figure D-3. BLM final EIS routes

Appendix D-2
Page 84 2021 Integrated Resource Plan—Appendix D
The conclusion of the BLM-led NEPA process, the BLM’s ROD, resulted in a singular route—
the BLM’s Agency Preferred route. The 293.4-mile approved route will run across 100.3 miles of
federal land (managed by the BLM, the USFS, the Bureau of Reclamation, and the United States
Department of Defense), 190.2 miles of private land, and 2.9 miles of state lands. Figure D-4
shows the BLM’s Agency Preferred route.

Figure D-4. BLM Agency Preferred route from the 2017 BLM ROD
As discussed previously, the BLM-led NEPA process and the EFSC process are separate and
distinct processes. Idaho Power submitted its Amended Application for Site Certificate to the
ODOE in summer 2017. The route Idaho Power submitted to the ODOE as part of the
Application for Site Certificate is very similar to the BLM’s Agency Preferred route, except for a
small sections across private property in the La Grande area. The BLM’s Agency Preferred route
in this area was a surprise to Idaho Power and seemingly all stakeholders and landowners in
the area.
At the time of EFSC application finalization (which was prior to the Final EIS release),
Idaho Power did not feel as if there was a stakeholder consensus preference between the
county’s preferred route and the modified route west of the City of La Grande.
Therefore, Idaho Power brought both alternatives into the EFSC application. Since that time,
Idaho Power understands that the Morgan Lake route alternative, on balance, appears to be
preferred by the majority of the groups previously identified.
Appendix D-2
2021 Integrated Resource Plan—Appendix D Page 85
Figure D-5 shows the route Idaho Power submitted in its 2017 EFSC Application for
Site Certificate.

Figure D-5. B2H route submitted in 2017 EFSC Application for Site Certificate