20230630Final_Order_No_35838.pdf

ORDER NO. 35838 1
Office of the Secretary
Service Date
June 30, 2023
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR A
CERTIFICATE OF PUBLIC CONVENIENCE
AND NECESSITY FOR THE BOARDMAN
TO HEMINGWAY 500-KV TRANSMISSION
LINE
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CASE NO. IPC-E-23-01

ORDER NO. 35838

On January 9, 2023, Idaho Power Company (“Company” or “Idaho Power” or “IPC”) filed
an application (“Application”) with the Idaho Public Utilities Commission (“Commission”)
requesting an order granting a Certificate of Public Convenience and Necessity to construct a 300-
mile long, overhead 500-kV high voltage line. The transmission line would be between a proposed
substation near Boardman, Oregon, and the Hemingway Substation in southwest Idaho (“B2H”).
The Company asserted that B2H is crucial to meeting a 2026 capacity deficit. The Company hoped
to begin construction in the summer of 2023, and requested a final order be issued by June 30,
2023.
On February 1, 2023, the Commission issued a Notice of Application and Notice of
Intervention Deadline. Order No. 35674. The Idaho Irrigation Pumpers Association, Inc. (“IIPA”),
Idaho Industrial Customers of Idaho Power, City of Boise City (“Boise City”), Micron
Technology, Inc., and the Idaho Conservation League (“ICL”) intervened. Order Nos. 35685 and
35695.
On April 10, 2023, the Commission issued a Notice of Modified Procedure and Notice of
Public Workshop. The Commission also held Customer Hearings in Pocatello, Twin Falls, and
Boise from June 12-14, 2023.
Staff, Boise, ICL, IIPA, and one member of the public (“Commenting Parties”) filed
comments, and the Company responded. One member of the public testified at the Boise Customer
Hearing. No other comments were received.
APPLICATION
The Company stated that the transmission line would be between the proposed Longhorn
Substation (“Longhorn”) near Boardman, Oregon, and the Hemingway Substation in southwest
Idaho. Application at 1. The Company asserted that B2H would be crucial to meet the Company’s
capacity deficiency in 2026. Id. The Company asserted that it must begin construction of B2H in
ORDER NO. 35838 2
the summer of 2023 to meet its obligation to reliably serve customers and is necessary to provide
adequate service to its customers in 2026 and thereafter.
The Company stated that B2H has been identified as a cost-effective resource in the
Company’s Integrated Resource Plans (“IRP”) since 2009. Id. at 2. The Company further stated
that B2H is “the lowest-cost alternative to serve Idaho Power’s customers in Idaho and Oregon.”
Id. at 4.
The Company stated that the existing Boise to McNary line was insufficient to
accommodate the expanded transmission that the Company expects. Id. at 7. The Company stated
that B2H would add needed capacity to the Idaho/Northwest path. Specifically, the Company
stated that the transmission line would add “1,050 [(megawatts (“MW”)] of capacity in the west-
to-east direction” and “1,000 MW of capacity in the east-to-west” direction. Id. The Company
suggested that B2H would thus facilitate synergy between Bonneville Power Administration’s
(“BPA”) winter focused capacity needs and Idaho Power’s summer focused capacity needs. Id. at
12.
The Company asserted that it conducted various forms of community outreach to inform,
and seek feedback from, those who will be affected by the Company’s proposed project. Id. at 10.
The Company asserted that it collectively held dozens of various types of meetings, and that nearly
one thousand (1,000) people attended them. Id. The Company stated that this outreach helped
inform the proposed B2H route. Id.
The Company asserted that the Bureau of Land Management (“BLM”) granted a right-of-
way necessary to construct and maintain B2H partially on BLM land. Id. at 10-11.
The Company stated that its original ownership share was 21.21% of B2H; BPA’s original
ownership share was 24.24%; and PacifiCorp’s (“PAC”) original ownership share was 54.55%.
Id. at 12. Idaho Power represents that it and BPA have agreed that “Idaho Power will increase its
B2H project ownership from 21.21[%] to 45.45[%] by acquiring BPA’s B2H project capacity.”
Id. Idaho Power stated that in January of 2023 the parties “conclude[ed] negotiations on final
agreements that memorialize and effectuate the changes in ownership.” Id. Additionally, Idaho
Power has entered into an agreement with PacifiCorp that there will be undivided ownership of
certain assets associated with B2H. Id. at 13.
ORDER NO. 35838 3
The Company estimated that its most cost-effective resource portfolio without B2H is still
approximately $266 million more expensive than the Company’s preferred portfolio (which
includes B2H).
The Company asserted that it would pay for its share of B2H’s cost through a “combination
of available cash and operating cash flow, available facilities and borrowing and debt issuances,
and potential future equity issuances.” Id. at 16.
The Company requested that the Commission find that Idaho Power has met the
requirements of Idaho Code § 61-526 and issue an order granting a CPCN to construct B2H to
meet the identified capacity deficiency in 2026. The Company asserted it will make a future filing
to address the cost recovery associated with B2H.
STAFF COMMENTS
Staff reviewed the Company's Application and responses to discovery requests. Based on
its review, Staff believed that a significant capacity deficit exists and that unless action is taken,
the deficit could affect reliability in 2026. Staff believed that the Company’s proposed B2H project
is a least-cost, least-risk, solution that will resolve the 2026 capacity deficit. Staff recommended
that the Commission:
1. grant a CPCN for the Company to construct the B2H transmission line, but make recovery
contingent on approval of all agreements requiring Commission approval and the
Commission's determination of prudence of actual cost when the project is complete.
2. direct the Company to include evidence of its pursuit of alternative funding sources for the
project when the Company files for recovery.
3. establish a soft cap for the recoverable value of the project that includes non-B2H expenses
that may be incurred if B2H fails to stay on schedule and needs to mitigate any capacity
shortfalls.
Project Description
The Application describes B2H and several other infrastructure project agreements that the
Company represents are necessary to ensure the full benefits of B2H are realized for each party.
Below is an inclusive list of the various infrastructure projects categorized by agreement type.
1. The Boardman to Hemingway Transmission Line Project
The primary project seeks to acquire rights of way (“ROW”) and construct approximately
300 miles of 500-kV transmission lines between Boardman, Oregon, and Hemingway, Idaho. It
will also:
• Construct or improve access roads for the transmission line;
ORDER NO. 35838 4
• Construct communication regeneration sites along the transmission line;
• Rebuild or remove certain other transmission line segments;
o Remove 12 miles of 69-kV transmission line;
o Rebuild 1.1 miles of 138-kV transmission line;
o Rebuild 0.9 miles of 230-kV transmission line;
• Construct the Longhorn substation;
• Upgrade the Hemingway substation; and
• Construct the Midline Series Capacitor substation.
The B2H project will be constructed through a partnership between the Company and PAC, in
which the Company will eventually fund and own 45.45%, and PAC will fund and own 55.55%.
The Company will be responsible for managing the construction.
2. Buyout of BPA
The Company will assume BPA’s 24% ownership share of B2H and fund the additional
24% of the construction and operating expenses. The Company will reimburse BPA for its share
of the permitting expenses incurred over the last decade. This involves a complicated agreement
designed to minimize financial risk to the Company's ratepayers.
3. Asset Exchanges
The Company and PAC have agreed to a collection of future asset exchanges and
construction projects (“Asset Exchanges”), designed to be implemented if B2H is energized. The
proposed Asset Exchanges are:
• IPC will transfer to PAC transmission assets between Midpoint and Borah for 300
MW west-to-east capacity;
• IPC will transfer to PAC transmission assets between Borah and Hemingway for
600 MW east-to-west capacity;
• PAC will transfer to IPC transmission assets between Populus and Four Corners for
200 MW of bi-directional capacity;
• PAC will transfer to IPC transmission assets in the Goshen area;
• IPC will construct the Midpoint 500/345-kV transformer project; and
• IPC will construct the Kinport-Midpoint 345-kV series capacitor project.

ORDER NO. 35838 5
4. Miscellaneous Agreements
Miscellaneous other agreements between the three entities will go into effect in conjunction
with energizing B2H:
• The Company and BPA will establish a 500 MW point-to-point (“PTP”) TSA from
the Mid-Columbia ("Mid-C") market hub to the proposed Longhorn substation.
This will complete the Company's transmission corridor to the Mid-C market hub.
• BPA will transfer to PAC two 100 MW PTP TSAs it has with the Company.
• BPA and PAC will revise multiple transmission agreements and upgrade
infrastructure in the Central Oregon region to establish more efficient delivery
corridors for PAC (“Central Oregon Agreements”).
CPCN Analysis
Staff agreed with the Company that B2H is the most cost-effective way to meet the
Company’s 2026 load requirements and recommended the Commission grant the Company a
CPCN for this project. However, Staff recommended that the Commission make it clear that the
requested CPCN would authorize only those items directly sought for the construction of B2H and
not cover every agreement for asset exchanges, construction, or other new or revised TSAs
between parties associated with B2H, regardless of whether the completion of certain agreements
are necessary to maximize B2H’s cost effectiveness. Staff also recommended that the Company
include evidence of the Company’s efforts to pursue additional sources of funding when it files
for recovery of actual cost.
Staff believed that the additional service to the community that B2H would supply is
directly tied with the public need, and that the Company will have the financial ability to fulfill
that need in good faith. Idaho Code §§ 61-526, 61-528. Staff does not believe that the project will
impair the Company’s ability to provide safe and reliable service.
After Staff reviewed the Company’s 2021 Load and Resource Balance (“L&RB”) and
other materials, Staff believed that the Company’s capacity deficit will grow and meeting the
Company’s obligations will necessitate additional capacity resources by 2026.
Staff noted that the effectiveness of B2H will depend on the construction of Longhorn,
reaching a TSA with BPA, and an adequate supply of available energy from the Mid-C Market.
Staff recommended making the Company’s recovery conditioned on the Commission’s approval
the various interrelated agreements necessary for B2H implementation.

ORDER NO. 35838 6
Risks and Soft Cap
Staff recommended that the Commission establish a soft cap on the amount of recovery for
B2H. Staff believed that the total cost of the project plus any additional cost necessary to meet
load if the project fails to stay on schedule should be part of the all-in total B2H costs that will be
compared to the established soft cap. The soft cap should be the threshold that will require the
Company to provide robust justification for construction costs over the cap to receive recovery.
Staff believed the Company faces significant risks throughout the entire project life cycle
that may ultimately impact customers. Table No. 1 summarizes the three types of project risk and
the key issues contributing to them.
Table No. 1: Project Risks
Capability Risks Schedule Risks Cost Risks
Longhorn Substation:
B2H will be unusable without
this interconnection.
Longhorn Substation:
The permitting process is in
progress and the construction
timeline is unknown.
Longhorn Substation:
The cost of an alternative is
unknown.
ROW Acquisitions:
B2H cannot be built without
the ROW(s).
ROW Acquisitions:
ROW delays might delay
construction, especially if legal
action becomes necessary.
ROW Acquisitions:
ROW negotiations have the
potential to increase costs.
Boardman-Ione (“B-I”)
Alternate Transmission Path:
B2H cannot be completed
without relocating this line.
B-I Alternate Transmission Path:
An alternate line is in the early
stages of permitting, followed by
construction of the line, then
demolition of the old line.
B-I Alternate Transmission
Path:
The alternate path and cost are
not certain, and environmental
mitigation may be required.
Supply Chain:
Substantial delays exist for key
project materials.
Inflation:
High inflation persists,
especially for key project
materials.
Outstanding Permits:
Various project permits are
outstanding, and delays are typical.

1. Project Capability Risk
Project capability risk is the risk that an essential part of the project cannot be completed,
thereby preventing completion of the overall project. Without proper interconnection, B2H will
not be usable. Staff identified three capability risk issues for B2H: (1) Construction of the
Longhorn substation; (2) Acquisition of the ROWs to construct B2H; and (3) Establishment of an
alternate transmission path for BPA’s B-I line.
ORDER NO. 35838 7
Although any of these issues, or other unforeseen issues, could prevent the successful
completion of B2H, Staff assumed that the Company would find a workaround to complete the
project and make it useful. Staff concluded that these capability risks may translate into increased
project costs and/or schedule growth. Therefore, Staff made no recommendation for capability
risk.
2. Project Schedule Risk
Project schedule risk is that risk that delays may manifest as cost risk to ratepayers. Staff
identified five risk issues that have potential to delay the overall project schedule: (1) Construction
of the Longhorn substation; (2) ROW acquisitions for B2H; (3) The B-I alternate transmission
path; (4) Supply chain delays; and (5) Outstanding permits.
The Company’s current planned in-service date for B2H is June 1, 2026, which is necessary
to meet the 2026 capacity deficit established in the Company’s 2021 IRP. Staff believed that if
B2H is not online, the Company may opt to incur additional expenses to implement a workaround
for the capacity deficit. Staff recommended that if circumstances delay the project beyond June 1,
2026, the Commission should require the Company to track and report any expenses incurred
outside of B2H to cover the capacity deficit until B2H is online.
3. Project Cost Risk
Project cost overruns represent a direct risk to ratepayers, who will be asked to recover the
full cost. Staff identified four cost risk issues that have potential to drive the project cost beyond
the current estimate: (1) The Longhorn substation; (2) ROW acquisitions; (3) The B-I alternate
transmission path; and (4) Inflation.
The Company has retained experienced engineering firms to refine the project estimate and
has shown due diligence in responsibly estimating the project cost. However, to further protect
customers, Staff recommended that the Commission place a soft cap on the Project in accordance
with the Application estimate. If the final Project cost exceeds the soft cap, the Company should
provide convincing evidence of its efforts to remain within the cap, the reasons it had to exceed
the cap, and justify any overages at the time recovery is requested.
Staff examined multiple responses to discovery including the date of estimates, major
construction features, contingency markups, shared and unshared costs between partners,
financing costs, and taxes. Staff compiled that information into a summary of the B2H cost
ORDER NO. 35838 8
estimate and included that as Attachment A to its comments. Staff recommended that the
Commission use the final total included in the attachment as the soft cap for any future recovery.
4. Other Risk
Staff has also identified potential risks that could arise or continue even after B2H has been
completed including: (1) sufficient energy availability from the Mid-C Market; (2) the market
price from the Mid-C Market; (3) completion of Longhorn; (4) the Company’s expense associated
with the BPA buyout; and (5) the associated Asset Exchanges.
PUBLIC COMMENTS
One member of the public, Donald Kemper, commented in this case. Mr. Kemper stated:
The rapid expansion of high voltage transmission capacity in the West is
needed to fill in a critical and missing gap on our path toward a climate solution. A
truck has little value without a road to travel on. Air travel relies on runways and
airports in order to function. Renewables can’t solve our emissions problem without
a way to connect power production to power need. New and better lines are needed
and needed quickly. Find a way to do it both fairly and quickly. Idaho and the world
are counting on you.
Public Comment at 1. At the June 14, 2023, Public Customer Hearing in Boise. Mr. Kemper
provided additional testimony substantially similar to his written comment. Mr. Kemper also
commented on the cost of utilities, and the harmful effects of climate change that would make
utility prices more expensive. Mr. Kemper testified that increased transmission infrastructure
across the United States was crucial to the combatting the effects of climate change, and Mr.
Kemper believed that, in addition to other harms, the monetary costs related to climate change
should be considered when deciding whether to invest in transmission lines such as B2H.
BOISE CITY’S COMMENTS
Boise City supported the Commission granting a CPCN in this case “based on the
assumption that B2H will deliver on its promise to be a ‘Clean-Energy Superhighway.’” Boise
City’s Comments at 3. Boise City believed that the Company had completed its due diligence in
analyzing the cost savings and other benefits of B2H. Boise City noted that the Company’s 2021
IRP identifies more than $265 million in savings compared to the most cost-effective portfolio that
did not include B2H. Boise City believed that B2H will help facilitate a transition away from high-
ORDER NO. 35838 9
cost, volatile, fossil resources to low-cost, clean energy. Boise City recommended that the
Company be required to report on the resources that were transmitted via B2H.1
Boise City identified several risks and suggested certain associated mitigation measures.
Boise City noted concerns related to potential delays, unanticipated costs, and the Company’s
minority ownership of the line. Boise City also noted the unique risks of transmission resources
compared with generation resources. Specifically, Boise City was concerned that increased access
to other markets could expose the Company’s customers to risks and market volatility arising from
the Company becoming too reliant on market purchases as opposed to in-house or local generation.
Boise City contrasted those risks against the Company’s recent solar and battery projects.
To mitigate these concerns, Boise City suggested mandatory and transparent annual reports
on the resources delivered via B2H as a condition of the Company obtaining the requested CPCN.
Additionally, while not expressly using the word “cap,” Boise City suggested the Commission
“should consider proactive measures to ensure customers are not ultimately responsible for a
project where costs unreasonably outweigh the direct, long-term benefits to the Company’s
system.” Boise City Comments at 4.
ICL’S COMMENTS
ICL offered qualified support for granting a CPCN in this case stating:
Though we maintain questions as to whether the size and configuration of
the line is best optimized to reduce customer costs and promote non-carbon
development relative to local, mid-sized and distributed generation, we reserve
those questions here in recognition that the transmission capacity afforded by the
B2H project benefits long-term grid stability and renewable integration.
ICL Comments at 2. ICL also stated that the Company had referenced the availability of clean
energy as justification for the Commission granting a CPCN in this case. Accordingly, ICL
believed that the Commission should grant the CPCN with conditions that the Company pursue
certain decarbonization aims and further develop clean energy sources. Alternatively, ICL
suggested the Company be required to report on the renewable resources that B2H facilitates.

1 In the Company Reply Comments, the Company summarized Boise City’s comments as requesting that the Company
be required to report on how much clean energy was transmitted via B2H. Boise City did not explicitly state that the
Company should report on how much clean energy B2H transmitted, only the resources transmitted, although that
may be a reasonable interpretation of the Company’s request. As noted below, ICL explicitly stated that a granted
CPCN should be conditioned upon the Company providing a report of the renewable resources that were delivered
via B2H.
ORDER NO. 35838 10
Finally, due to the risks that arise from the Company’s minority ownership, potential
delays, and potential cost-overruns, ICL suggested the Commission consider a cap or other
measures to mitigate the financial risks to the Company’s ratepayers. With these factors
considered, ICL recommended the Commission approve the Company’s requested CPCN in this
case.
IIPA’S COMMENTS
IIPA supported the construction of B2H. IIPA believed that B2H would allow for cheaper
power, a more manageable grid, and a preferable approach to demand response resources.
However, IIPA noted that its comments were only supplemental as it had not performed a
comprehensive analysis of the Project.
IIPA noted that Washington and Oregon have goals to be 100% carbon neutral between
2030 and 2040. IIPA believed that, as current generation resources in Oregon and Washington are
replaced by more local generation in those areas, B2H would allow the Company access to surplus
clean energy at wholesale prices. Furthermore, IIPA stated that the Company will have access to
“a large fleet of natural gas generators” in Oregon and Washington that local utilities will be unable
to use even during peak hours because of the carbon restrictions in those states. IIPA Comments
at 3. IIPA reiterated this argument in relation to other emitting resources. IIPA noted that the
Company could sell clean hydro capacity while purchasing low-cost emitting capacity and still
reduce its overall carbon footprint.
IIPA noted that the Company’s system faces difficulties due to heat domes, expiring coal
generation, and solar generation that is susceptible to problems arising from the generation being
geographically concentrated. IIPA believed that B2H will provide access to a greater variety of
generation resources thus increasing stability. IIPA also noted that the Pacific Northwest will
continue to peak in winter while IPC peaks in the summer, thus allowing both locations increased
flexibility in meeting their peak demands.
IIPA was also supportive of B2H because it believed that it would positively impact the
Company’s demand response programs:
IIPA expects that increased market access will reduce the need to regularly curtail
irrigation customers. Many current participants in the irrigation demand response
program face substantial crop damage if curtailment occurs too regularly. A
preferred outcome for IIPA is that the irrigation demand service only provides
emergency capacity service rather than regular capacity service.
ORDER NO. 35838 11
Id. at 6-7. For the reasons stated above, IIPA believed that B2H was in the public interest
and that the Commission should grant a CPCN to the Company in this case.
COMPANY REPLY COMMENTS
The Company address the suggestions made by the Commenting Parties topically.
1. Granting the CPCN
The Company quoted several Commenting Parties and noted that all Commenting Parties
expressed support for the Commission granting the Company’s requested CPCN in this case. The
Company also noted Staff’s concern that B2H relied heavily on the completion of numerous other
projects not directly related to the construction of B2H and often with additional permitting
requirements. The Company agreed with Staff’s recommendation that the proposed CPCN cover
specifically those issues relating directly to the construction of B2H. The Company noted that it
already planned on seeking independent Commission approval at the appropriate time for those
projects, which are not directly related to the construction of B2H yet remain important to its cost-
effectiveness. However, the Company suggested that “it would be appropriate for the Commission
to acknowledge in this case that the underlying partnership agreements that provide for the line to
be constructed are reasonable in their current states.” Company Reply at 5.
2. Soft Cap
The Company agreed with Staff’s assessment of project risks but did not believe that a soft
cap was the best way to address those risks. The Company argued that the CPCN should be granted
because it has met the requirements of Idaho Code § 61-526. The Company stated that it has not
yet even selected contactors for the construction and that the Company would address recovery in
a future filing where the Company would justify all costs associated with B2H. If a soft cap was
implemented, the Company expressed confusion about the metrics for its determination. The
Company stated:
Staff suggests that the Commission should require the Company to track
and report any expenses incurred outside the B2H project expenditures and that
those expenditures be “subject to the same soft cap limit recommended” by Staff.
[Staff Comments at 12.] It is unclear if Staff is suggesting any incremental costs
incurred due to a delay in the B2H 2026 in-service date be either (1) additive to the
total B2H project costs, identified in Attachment A to Staff’s Comments, such that
the sum of the two must fall under the soft cap proposed by Staff, or (2) in total, the
incremental costs must be less than the soft cap proposed by Staff.
ORDER NO. 35838 12
Id. at 7. The Company also stated that if B2H is delayed it would make changes to its resource
acquisition plan. The Company argued that because those modifications would result in a different
mix of resources, those resources should not be subject to the proposed soft cap.
3. Requirement to Track Clean Energy on B2H
The Company noted that, despite its clean energy benefits, the primary purpose of B2H is
to be a least cost resource. The Company explained that much, but not all, of the power transmitted
by B2H will be clean energy. The Company also noted that tracking clean energy would be
impractical at this time. The Company stated that it already reports the generation source of its
resources, but not the type of generation, for the power that it transmits. The Company pointed out
that it had no ability to track the generation source of power that is transmitted by a third party
(e.g. BPA) via B2H. Accordingly, despite having sympathies for the underlying concerns, the
Company requested that the Commission reject Boise City and ICL’s request that the Company
track clean energy that is transmitted via B2H.
4. Pursuit of Outside Funding
The Company disagreed with Staff’s request that the Company submit evidence to the
Commission of the Company’s attempts to secure grants or other outside funding. The Company
noted that the Company had already hired consultants who specialize in securing outside funding.
The Company also noted several previous attempts to secure such funding, and the Company also
noted cases and instances where the Company had previously secured, or is still pursuing, outside
funding. The Company stated that it would continue to attempt to secure grant opportunities and
other options to lower costs for its customers and will keep the Commission apprised of those
attempts, including any successful efforts.
5. Conclusion
The Company stated that it agreed with the Commenting Parties’ recommendation that the
Company be granted a CPCN. The Company opposed the Commission establishing a soft cap, a
requirement that clean energy transmitted via B2H be tracked, and a condition that the Company
provide verification of its efforts to seek outside funding.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over the Company’s Application and the issues in this
case under Title 61 of the Idaho Code including Idaho Code §§ 61-301 through 303. The
Commission is empowered to investigate rates, charges, rules, regulations, practices, and contracts
ORDER NO. 35838 13
of all public utilities and to determine whether they are just, reasonable, preferential,
discriminatory, or in violation of any provisions of law, and to fix the same by order. Idaho Code
§§ 61-501 through 503.
1. Necessity of the CPCN
Public utilities shall “furnish, provide and maintain such service, instrumentalities,
equipment and facilities as shall promote the health, safety, comfort and convenience of its patrons,
employees and the public, and as shall be in all respects adequate, efficient, just and reasonable.”
Idaho Code § 61-302.
Before constructing “a line, plant, or system,” a public utility providing electrical service
must obtain a CPCN from the Commission establishing that the “public convenience and
necessity” requires it. Idaho Code § 61-526. Pursuant to Idaho Commission Rule of Procedure
112, existing utilities applying for the issuance a CPCN under Idaho Code § 61-526 must submit
any relevant data including: (1) a Statement and Explanation; (2) a Description of Construction or
Expansion; (3) a Map; (4) a Financial Statement and Construction Timelines; and (5) Cost
Estimates and Revenue Requirements.
Having reviewed the Application, the record, the comments of the parties, and all submitted
materials, the Commission finds that the Company has satisfied the requirements for a CPCN and
finds that the present and future public interest is served by and requires construction of the
Boardman-to-Hemingway 500-kV transmission line project in the manner, time frame, and at the
location proposed. Idaho Code § 61-526; Rule 112. The Commission makes no findings as to
reasonableness or prudence with respect to any other agreements or transfers contained,
referenced, or described in the Application, and any such other agreement shall be subject to future
Commission review as applicable.
2. Soft Cap, Future Recovery, and Energy Tracking
Staff recommends that the Commission establish a soft cap for the recoverable cost of
constructing the project, and Staff believes that the actual cost of the project, plus any additional
cost necessary to meet load if the project fails to stay on schedule, should be the total B2H costs
compared to the established soft cap when the Company seeks recovery. The Company does not
believe that a soft cap is necessary as it expects to demonstrate the prudence and cost-effectiveness
of the entirety of its actual investment in B2H.
ORDER NO. 35838 14
Based upon the risks the Company faces throughout the project life cycle, the impact those
risks may have on customers, and the requirement of future Commission approval for any other
relevant agreements that may be necessary for the Company and customers to obtain the full
benefits of B2H, the Commission finds it fair, just, and reasonable to establish a soft cap on the
recovery of costs in the amount of the Company’s estimated costs as calculated in the Company’s
Application and testimony, and updated in Attachment A to Staff’s comments.
While the Commission appreciates that the Company indicated it is prepared to seek the
appropriate prudence review and Commission approval as necessary for B2H and its associated
agreements, transfers, and exchanges; in the future the Company should be prepared to provide
detailed support and justification for any costs over the established soft cap when seeking recovery.
This information should include comparisons between the actual project cost and soft cap amount,
any associated incremental costs for construction, costs incurred due to delay in the Project, and
any mitigation efforts and associated costs incurred by the Company in connection with B2H or
the projects failure to provide full benefits. In the event of schedule delays requiring mitigation to
meet capacity requirements, the Company should expect to provide comparisons between the cost
of B2H with and without schedule delays from a total cost perspective.
Similarly, the Company has indicated that it is continuously seeking options to lower costs
to customers and that the Company keeps the Commission apprised of those attempts. The
Commission appreciates the Company’s commitment to providing such information in all cases,
but especially in cases such as this where there are significant expenditures being made and
customers face equally significant risks of impact. As such, when the Company does seek recovery
of costs for B2H, the Company shall provide evidence of the Company’s investigations; analyses;
applications for grants; and/or any attempts the Company made to secure alternative funding from
federal, state, or local agencies.
The Commission appreciates the Intervenor’s concerns and recommendations regarding
B2H. Notably, Boise City indicated the potential for increased risks due to market volatility if the
Company experiences an increase in its reliance on market purchases as opposed to local
generation, and Boise City recommends mandatory and transparent annual reports on the resources
delivered via B2H as a condition of the Company obtaining the requested CPCN. While the
Commission does not believe such a condition for approval of the CPCN is necessary, the
ORDER NO. 35838 15
Commission expects the Company to be diligent in its collection and analysis of all relevant
information concerning the construction and operation of B2H.
ORDER
IT IS HEREBY ORDERED that the Company’s Application for a Certificate of
Convenience and Necessity authorizing construction of the Boardman-to-Hemmingway 500-kV
Transmission Line is granted.
IT IS FURTHER ORDERED that the Commission establishes a soft cap for the
recoverable cost of constructing B2H as specified above.
IT IS FURTHER ORDERED that upon seeking recovery, the Company shall provide
evidence of its pursuit of alternative funding sources for B2H.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date upon this Order regarding any
matter decided in this Order. Within seven (7) days after any person has petitioned for
reconsideration, any other person may cross-petition for reconsideration. Idaho Code § 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho, this 30th day of
June 2023.

ERIC ANDERSON, PRESIDENT

JOHN R. HAMMOND JR., COMMISSIONER

EDWARD LODGE, COMMISSIONER
ATTEST:

Jan Noriyuki
Commission Secretary

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