20230110Ellsworth Direct_Redacted.pdf

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

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

JARED L. ELLSWORTH

ELLSWORTH, DI 1
Idaho Power Company
Q. Please state your name, business address, and 1
present position with Idaho Power Company (“Idaho Power” or 2
“Company”). 3
A. My name is Jared L. Ellsworth and my business 4
address is 1221 West Idaho Street, Boise, Idaho 83702. I 5
am employed by Idaho Power as the Transmission, 6
Distribution & Resource Planning Director for the Planning, 7
Engineering & Construction Department. 8
Q. Please describe your educational background. 9
A. I graduated in 2004 and 2010 from the 10
University of Idaho in Moscow, Idaho, receiving a Bachelor 11
of Science Degree and Master of Engineering Degree in 12
Electrical Engineering, respectively. I am a licensed 13
professional engineer in the State of Idaho. 14
Q. Please describe your work experience with 15
Idaho Power. 16
A. In 2004, I was hired as a Distribution 17
Planning engineer in the Company’s Delivery Planning 18
department. In 2007, I moved into the System Planning 19
department, where my principal responsibilities included 20
planning for bulk high-voltage transmission and substation 21
projects, generation interconnection projects, and North 22
American Electric Reliability Corporation’s (“NERC”) 23
reliability compliance standards. I transitioned into the 24
Transmission Policy & Development group with a similar 25

ELLSWORTH, DI 2
Idaho Power Company
role, and in 2013, I spent a year cross-training with the 1
Company’s Load Serving Operations group. In 2014, I was 2
promoted to Engineering Leader of the Transmission Policy & 3
Development department and assumed leadership of the System 4
Planning group in 2018. In early 2020, I was promoted into 5
my current role as the Transmission, Distribution and 6
Resource Planning Director. I am currently responsible for 7
the planning of the Company’s wires and resources to 8
continue to provide customers with cost-effective and 9
reliable electrical service. 10
Q. What is the purpose of your testimony in this 11
case? 12
A. The purpose of my testimony is to present the 13
need and justification for the Boardman to Hemingway 14
transmission line (“B2H”). The following is a summary of 15
the items I will discuss at length in my testimony: 16
• As the B2H project entered into the permitting 17
and pre-construction phase, project participants Idaho 18
Power, PacifiCorp, and Bonneville Power Administration 19
(“BPA”), executed a non-binding term sheet (“Term Sheet”) 20
that addresses B2H ownership, transmission service 21
considerations, and asset exchanges. The Term Sheet 22
provides that Idaho Power will acquire a 45.45 percent 23
ownership share of B2H – which reflect an increase of 24
24.24 percent over the ownership share previously 25

ELLSWORTH, DI 3
Idaho Power Company
anticipated in the Permit Funding Agreement. This 1
increase results from Idaho Power’s acquisition of BPA’s 2
24.24 percent ownership share initially reflected in the 3
Permit Funding Agreement. The Term Sheet reflects that, 4
instead of an ownership interest, BPA will commit to 5
acquiring B2H capacity from Idaho Power through 6
transmission service agreements. The agreements necessary 7
to facilitate Idaho Power’s increased ownership share in 8
the B2H project are completed and ready for execution. 9
The Company and PacifiCorp will execute a Construction 10
Funding Agreement that will cover all work necessary to 11
construct the B2H project. 12
• First identified in the 2006 Integrated 13
Resource Plan (“IRP”), the B2H project has proven to be a 14
cost-effective resource through successive IRPs. The B2H 15
project was identified as part of the preferred resource 16
portfolio in Idaho Power’s 2009, 2011, 2013, 2015, 2017, 17
2019 and most recently in the 2021 IRP. 18
• The results of the 2021 IRP preferred 19
portfolio indicate the Base with B2H portfolio minimizes 20
both cost and risk, and when compared to the lowest cost 21
non-B2H portfolio, the cost difference definitively shows 22
that the B2H project is a necessary component of the 23
Company’s preferred portfolio, assuming comparable risk 24
performance to other portfolios. 25

ELLSWORTH, DI 4
Idaho Power Company
• The transmission assumption used in the 1
modeling of the 2021 IRP includes B2H project costs 2
assuming Idaho Power’s 45.45 percent ownership share, 3
which are offset by transmission wheeling revenue benefits 4
associated with B2H. 5
• Aside from being the least-cost preferred 6
portfolio, the B2H project will provide: (1) improved 7
economic efficiency and renewable integration, (2) grid 8
reliability/resiliency, (3) resource reliability, (4) 9
contingency reserves and reduced electrical losses, and 10
(5) capacity to the Four Corners market hub. 11
• Idaho Power evaluated B2H project capacity 12
risk, cost risk, and in-service date risk extensively. 13
Q. Have you prepared any Exhibits? 14
A. Yes. Exhibit No. 1 is the Term Sheet between 15
Idaho Power, PacifiCorp, and BPA that addresses B2H 16
ownership, transmission service considerations, and asset 17
exchanges. Exhibit No. 2 details the construction, 18
ownership, operation, asset exchanges and service 19
agreements necessary for the Boardman to Hemingway Project. 20
Exhibit No. 3 is BPA’s Tech Forum notice dated January 5, 21
2023, announcing their completion of B2H project 22
negotiations. Exhibit No. 4 presents Idaho Power’s 23
transmission system. Exhibit No. 5 shows a map of the 24
region with the B2H project substation termination points. 25

ELLSWORTH, DI 5
Idaho Power Company
Exhibit No. 6 is the B2H Phase 2 Study Report – Western 1
Electricity Coordinating Council (“WECC”) Rating Process. 2
Exhibit No. 7 details the initial branching scenario 3
analysis performed as part of the 2021 IRP. 4
I. THE B2H PROJECT PARTICIPANTS 5
Q. What entities have participated in funding the 6
permitting of the B2H project? 7
A. Idaho Power, PacifiCorp, and BPA are parties 8
to the Permit Funding Agreement, initially executed January 9
12, 2012, and amended several times (“Permit Funding 10
Agreement”), to jointly support the regulatory processes 11
associated with obtaining necessary permits and other work 12
to develop the B2H project (“Parties”). Collectively, the 13
Parties represent a very large electric service footprint 14
in the western United States and have all recognized the 15
regional significance of the B2H project. 16
Q. What are the key provisions of the existing 17
Permit Funding Agreement? 18
A. The Permit Funding Agreement is intended to 19
align the Parties’ cost responsibility for funding with 20
their assigned B2H capacity allocations. Those allocations 21
include a seasonal capacity arrangement between Idaho Power 22
and BPA – which is a benefit for Idaho Power’s customers. 23
Specifically, the agreement provides that Idaho Power’s 24
west-to-east share of B2H capacity is 500 MW in the summer 25

ELLSWORTH, DI 6
Idaho Power Company
season (April-September), and 200 MW in the winter 1
(January-March and October-November) to serve its 2
customers, whereas BPA’s west-to-east share is 250 MW in 3
the summer and 550 MW in the winter. Idaho Power and BPA’s 4
share of the B2H project make up 750 MW of west-to-east 5
capacity. This seasonal capacity arrangement affords Idaho 6
Power 500 MW of summer season capacity at a cost equivalent 7
to 350 MW, a significant cost-reduction benefit that I will 8
discuss later in my testimony. The synergies between BPA’s 9
capacity needs (winter focused) and Idaho Power’s capacity 10
needs (summer focused) will lead to high utilization of the 11
B2H project’s increased capacity. Finally, the Permit 12
Funding Agreement includes a buyout option, stating that 13
once the B2H project received a Record-of-Decision from the 14
Bureau of Land Management, any party can trigger the 15
Construction Negotiation Phase, and move forward with 16
executing definitive construction funding agreements. If 17
one party chooses not to move forward, the other parties 18
that wish to move forward are required to buy that party 19
out, with the exiting party receiving full compensation for 20
its permitting costs. 21
Q. What was BPA’s interest in the B2H project at 22
the time the Permit Funding Agreement was initially 23
executed? 24

ELLSWORTH, DI 7
Idaho Power Company
A. BPA has a load service obligation for its 1
customers spread across southeast Idaho including Lost 2
River Electric, Fall River, Salmon River Electric 3
Cooperative, City of Idaho Falls, City of Soda Springs, and 4
Lower Valley Electric. Starting back in the 1970s, Idaho 5
Power worked with BPA to explore the construction of a 500-6
kV line from the Pacific Northwest to the Idaho Power area, 7
which would have provided BPA a connection across southern 8
Idaho for BPA to serve its customers (including its south 9
Idaho customers BPA currently serves via Idaho Power 10
transmission). This contemplated line was essentially what 11
B2H is today but was never constructed. Rather than build 12
the line, BPA and PacifiCorp executed a power exchange 13
agreement whereby BPA would deliver power to PacifiCorp 14
customers in the Oregon area, and in exchange, PacifiCorp 15
would deliver power to BPA customers in southeast Idaho. 16
PacifiCorp terminated this agreement, with five-years 17
notice, in 2011. Since 2016, BPA has served its southeast 18
load via combinations of firm transmission across 19
PacifiCorp, conditional firm transmission across Idaho 20
Power, and southern power market purchases. As a result of 21
these events, BPA desired a direct transmission connection, 22
with no transmission wheel, or a single transmission wheel, 23
between the Federal Columbia River Power System and its 24
customers. 25

ELLSWORTH, DI 8
Idaho Power Company
Q. What interest in B2H did the Permit Funding 1
Agreement originally anticipate for BPA? 2
A. Under the Permit Funding Agreement, BPA has a 3
24.24 percent ownership share. As discussed in more detail 4
later in my testimony, Idaho Power is now planning to 5
acquire BPA’s 24.24 percent ownership share of the permit 6
funding. 7
Q. What was PacifiCorp’s interest in the project 8
at the time the Permit Funding Agreement was initially 9
executed? 10
A. Around the time Idaho Power began permitting 11
the B2H project, the Company and PacifiCorp also began to 12
jointly permit the Gateway West project. Gateway West 13
extends between Hemingway, as the western terminus, and 14
east-central Wyoming, as the eastern terminus. To 15
complement Gateway West and connect its western Balancing 16
Area (PACW) and eastern Balancing Area (PACE) together, 17
PacifiCorp required an additional segment between the 18
Pacific Northwest and Hemingway. The B2H project would 19
provide strategic value to PacifiCorp connecting the two 20
regions, providing bidirectional capacity to increase 21
reliability and enable more efficient use of resources. 22
Under the Permit Funding Agreement, PacifiCorp has a 54.55 23
percent ownership share. 24

ELLSWORTH, DI 9
Idaho Power Company
Q. What other related negotiations did the 1
Parties pursue when executing the Permit Funding Agreement? 2
A. Coincident with the development of the Permit 3
Funding Agreement, the Parties also executed a Memorandum 4
of Understanding, which detailed high-level parameters of 5
different asset exchanges between Idaho Power, BPA, and 6
PacifiCorp. The asset exchanges, as they are envisioned 7
today, will be discussed later in my testimony. 8
Q. Have the Parties made progress on final 9
definitive agreements toward project ownership and 10
participation? 11
A. Yes. Via a revised Permit Funding Agreement, 12
the B2H project is currently in the permitting and pre-13
construction phase. In addition, on January 18, 2022, and 14
after significant discussions, study efforts, and 15
negotiations, the Parties executed the Term Sheet, included 16
as Exhibit No. 1, that addresses B2H ownership, 17
transmission service considerations, and asset exchanges. 18
The Parties entered into the Term Sheet after over two 19
years of discussions related to next steps associated with 20
the B2H project. 21
Q. Does the Term Sheet reflect any changes to the 22
ownership arrangements that had been contemplated in the 23
Permit Funding Agreement? 24

ELLSWORTH, DI 10
Idaho Power Company
A. Yes. A decade has passed since the Parties 1
signed the Permit Funding Agreement and the Parties’ 2
capacity needs, strategies, and goals associated with the 3
B2H project have evolved. As a result, the Parties 4
negotiated the Term Sheet as the framework for future 5
agreements required between and among the Parties as the 6
B2H project moved towards pre-construction. As envisioned 7
under the Term Sheet, BPA will transition out of its role 8
as a joint permit funding coparticipant and will instead 9
rely on the B2H project by taking transmission service from 10
Idaho Power to serve its customers. To accommodate this 11
change, Idaho Power will increase its B2H project ownership 12
share from 21.21 percent to 45.45 percent by acquiring 13
BPA’s B2H project capacity. 14
Idaho Power’s Increased B2H Ownership Share 15
Q. Does the approach agreed to in the Term Sheet 16
maintain the benefits to Idaho Power and its customers of 17
the initially contemplated ownership arrangements? 18
A. Yes. I will discuss the B2H project’s cost 19
effectiveness later in my testimony. In terms of the 20
arrangement with BPA, as previously discussed, BPA and 21
Idaho Power identified synergies associated with each 22
party’s B2H capacity needs. BPA needed more winter capacity 23
between the Pacific Northwest and Idaho, and Idaho Power 24
needed more summer capacity. BPA and Idaho Power negotiated 25

ELLSWORTH, DI 11
Idaho Power Company
the sum of their capacities to fit together like puzzle 1
pieces with total capacity equal to 750 MW. BPA’s capacity 2
included 400 aMW (250 MW summer / 550 MW winter) and Idaho 3
Power’s capacity included 350 aMW (500 MW summer / 200 MW 4
winter). The new arrangement, whereby BPA purchases 5
transmission service on B2H for the capacity that it had 6
formerly planned to acquire through ownership, maintains 7
the benefits of the B2H project for each party and their 8
customers. 9
Q. What is the resulting capacity interest 10
following execution of the Term Sheet? 11
A. Idaho Power’s B2H project capacity will 12
increase to 750 MW west-to-east, of which the Company plans 13
to utilize 500 MW in the summer months (April–September) 14
and 200 MW in the winter months (January–March and October–15
December) for Idaho Power retail customer service, and the 16
remainder will primarily be used to provide BPA network 17
transmission service under Idaho Power’s Open Access 18
Transmission Tariff (“OATT”) across B2H and southern Idaho. 19
PacifiCorp’s B2H ownership interest is not impacted by BPA 20
transitioning out of ownership of the project and their B2H 21
capacity will remain at 300 MW west-to-east and 600 MW 22
east-to-west. There remains 400 MW of unallocated B2H east-23
to-west capacity, of which 182 MW is expected to be 24

ELLSWORTH, DI 12
Idaho Power Company
allocated to Idaho Power and 218 MW allocated to 1
PacifiCorp, based on their respective ownership share. 2
Q. Have the agreements envisioned in the Term 3
Sheet with respect to the Company assumption of BPA’s 24.24 4
percent ownership share of the B2H project come to 5
fruition? 6
A. Yes. In January 2023, the Parties reached a 7
major project milestone, concluding negotiations on final 8
agreements that memorialize and effectuate the change in 9
ownership. There are five different agreements specific to 10
Idaho Power and necessary to reflect adjustments to the 11
funding and ownership percentages envisioned in the Term 12
Sheet, all of which are nearly finalized and will be ready 13
for execution. They consist of the: (1) Second Amended and 14
Restated B2H Transmission Project Joint Permit Funding 15
Agreement, (2) Network Integration Transmission Service 16
Agreement (“NITSA”) for Goshen Load, (3) NITSA for Idaho 17
Falls Load, (4) Purchase, Sale, and Security Agreement, and 18
(5) point-to-point (“PTP”) transmission service agreements. 19
These are summarized in Exhibit No. 2 to my testimony and 20
identified as Agreements 1, 2, 3, 4, and 11. 21
Q. When will the agreements be executed? 22
A. The parties will execute the agreements 23
following BPA’s public process, which is a standard 24
administrative decision-making process applicable to all 25

ELLSWORTH, DI 13
Idaho Power Company
federal agencies and typically concludes within three 1
months of BPA’s notice to the region. 2
Q. Has BPA begun the public process for their 3
proposed new role in the B2H project? 4
A. Yes. On January 5, 2023, BPA provided public 5
notice via their Tech Forum platform to customers and 6
stakeholders announcing their completion of B2H project 7
negotiations and releasing the customer engagement 8
schedule, identifying dates for the comment period, 9
customer workshop, and an expected final decision in March 10
2023. BPA released its Letter to the Region formally 11
opening the comment period on January 9, 2023, providing 12
their customers and stakeholders information about the 13
agreements and notified them of a BPA-hosted workshop on 14
January 23, 2023, to answer questions about the agreements. 15
In addition, BPA explained customers and stakeholders have 16
the opportunity to comment through February 10, 2023, prior 17
to BPA proceeding with execution of the binding contracts 18
for the B2H project. BPA’s public process is expected to 19
conclude in March 2023 with the issuance of a letter to the 20
region describing its reasoning behind its decision and 21
responding to comments. A copy of the Tech Forum notice is 22
included as Exhibit No. 3 to my testimony. 23

ELLSWORTH, DI 14
Idaho Power Company
Q. What is required of Idaho Power contractually 1
once BPA’s ownership share is assumed? 2
A. As I described earlier, BPA’s transition out 3
of its role as a joint permit funding coparticipant will 4
require the Second Amended and Restated B2H Joint Permit 5
Funding Agreement, identified as Agreement 1 on Exhibit No. 6
2. As contemplated in the Term Sheet, funding and 7
ownership percentages will be adjusted such that the 8
Company will acquire BPA’s permitting interest and funding 9
of 45.45 percent of the B2H project costs while providing 10
transmission service across southern Idaho to BPA’s 11
customers through NITSA’s under Idaho Power’s OATT, 12
identified as Agreements 2 and 3 in Exhibit No. 2. In 13
addition, the Company will reimburse BPA over time for the 14
value of the permitting costs paid by BPA. 15
Q. Will payments received from BPA under the 16
NITSAs reimburse the Company for its increased share of the 17
B2H project? 18
A. Yes. Based on the yearly load estimates 19
provided by BPA and the resulting forecasted transmission 20
service payments to Idaho Power under the full term of the 21
NITSAs are projected to offset the Company’s costs 22
associated with its increased share of the B2H project to 23
support BPA’s usage, and, therefore, Idaho Power’s 24
customers will not be harmed by the changes to the 25

ELLSWORTH, DI 15
Idaho Power Company
arrangement. In addition, as an added protection for 1
customers, BPA has agreed to a security and risk backstop 2
payment in conjunction with the purchase and sale 3
provisions associated with the Company’s assumption of 4
BPA’s ownership share of the B2H project (“Purchase, Sale, 5
and Security Agreement”). The Purchase, Sale, and Security 6
Agreement is included as Agreement 4 to Exhibit No. 2. 7
Under the Purchase, Sale, and Security Agreement, 8
Idaho Power will hold, as a security payment, an amount 9
equivalent to BPA’s investment in the B2H project prior to 10
the transfer of permitting interest to Idaho Power, or the 11
approximately $25 million BPA has paid towards permitting 12
costs to date (“Transferred Permitting Interest”). BPA will 13
also pay Idaho Power an additional $10 million (“Seller’s 14
Security”), for a total security deposit of $35 million. 15
The Seller’s Security will provide assurances that Idaho 16
Power’s retail customers are insulated from risk associated 17
with the Company purchasing BPA’s share of the Transferred 18
Permitting Interest. 19
Upon energization of B2H, interest will accrue on 20
both the Transferred Permitting Interest and the Seller’s 21
Security at a rate of percent. Because the revenue 22
associated with BPA’s usage of B2H in the early years of 23
the agreement will be less than the associated annual 24
revenue requirement, the unreturned portion of the $35 25

ELLSWORTH, DI 16
Idaho Power Company
million should mitigate any potential default risk until 1
BPA has fully paid for its share of B2H costs over time. 2
Q. Please explain why BPA’s payments under the 3
NITSAs will not immediately offset the Company’s costs 4
associated with BPA’s usage of the B2H project. 5
A. The rate for which BPA will be charged under 6
the NITSAs is based on the network transmission service 7
rates under Attachment H of Idaho Power’s OATT. Rates for 8
transmission service are updated in October of each year, 9
based on the previous calendar year’s actual financial 10
data. Because of the regulatory lag that exists between 11
when transmission costs are incurred and when transmission 12
rates are updated, under recovery of revenue requirement 13
amounts associated with the network transmission service 14
provided to BPA will occur in the first few years the 15
NITSAs are in effect. Once all agreements with BPA have 16
been executed, and prior to energization of the B2H 17
project, the Company will request authorization from the 18
Commission for accounting treatment that will ensure the 19
Company’s retail customers are not harmed by the 20
arrangement and until such time as cumulative network 21
transmission service revenues received from BPA exceed 22
BPA’s cumulative share of the B2H revenue requirement. 23

ELLSWORTH, DI 17
Idaho Power Company
Q. Will the Company be responsible for repaying 1
the Transferred Permitting Interest and Seller’s Security 2
to BPA? 3
A. Yes. Repayment of the Seller’s Security and 4
all accrued interest related to the Seller’s Security will 5
occur within 60 days following energization of B2H. The 6
repayment of the Transferred Permitting Interest plus all 7
related accrued interest will occur starting year eleven 8
following energization of B2H if BPA’s total load under the 9
Goshen and Idaho Falls NITSA’s for any rolling twelve-month 10
basis averages 400 MW or more prior to the tenth 11
anniversary of energization (“Repayment Event”). Or, in the 12
alternative, if the total load for any rolling twelve-month 13
basis averages 400 MW or more after the tenth anniversary 14
of B2H energization, then the Repayment Event will commence 15
on the next anniversary date of B2H energization. 16
Q. Are there any additional terms agreed to 17
between Idaho Power and BPA? 18
A. Yes. The Term Sheet identified other related 19
transactions between the Company and BPA, two were 20
associated with necessary transmission service agreements 21
and one related to substation funding. With respect to the 22
transmission service agreements, first, Idaho Power will 23
secure 500 MW of PTP transmission service from BPA from the 24
Mid-Columbia (Mid-C) hub to the proposed Longhorn 25

ELLSWORTH, DI 18
Idaho Power Company
substation, which will provide the Company a direct 1
connection to the Mid-C market with flexible long-term BPA 2
wheeling rights. Second, as identified in the Term Sheet 3
and as a component of Agreement 11 in Exhibit No. 2, BPA 4
will redirect its two 100 MW PTP transmission service 5
agreements that it takes from the Company, assigning them 6
to PacifiCorp, a necessary redirect following termination 7
of BPA’s existing NITSA with PacifiCorp. 8
Q. Please describe the agreement required for 9
substation funding. 10
A. The Parties have also agreed to terms specific 11
to funding of the Longhorn substation, which BPA will own 12
and operate, and where the B2H project interconnects. The 13
Longhorn Substation Funding Agreement, identified as 14
Agreement 8 in Exhibit No. 2, was not required in advance 15
of BPA’s public process and has not yet been finalized. 16
However, provisions of the agreement were identified in the 17
Joint Purchase and Sale Agreement (“JPSA”) that I will 18
discuss later in my testimony. As a condition precedent to 19
closing of the JPSA, Idaho Power and PacifiCorp must have 20
finalized the agreement between the Parties for funding of 21
a portion of the assets at, and directly adjacent to, the 22
Longhorn substation where B2H will connect. The Longhorn 23
Substation Funding Agreement will also describe the use of 24
a facilities charge, or other similar charge, pursuant to 25

ELLSWORTH, DI 19
Idaho Power Company
BPA’s OATT, that will be paid by the Company and PacifiCorp 1
allowing for each party to transact across the Longhorn bus 2
in the future. It will detail the ownership, operation and 3
maintenance of the B2H equipment by Idaho Power and 4
PacifiCorp, including (1) a B2H project-related series 5
capacitor at the substation, (2) the B2H project shunt line 6
reactors, and (3) any ancillary equipment required to 7
support the B2H project series capacitor and shunt line 8
reactors. 9
Q. Are there any other agreements you have not 10
yet discussed necessary for facilitating Idaho Power’s 11
increased ownership arrangement with BPA? 12
A. No. 13
New Partnership Agreements Necessary for B2H 14
Q. As partners in B2H, what agreements are 15
necessary between Idaho Power and PacifiCorp? 16
A. In addition to the transactions directly 17
related to construction and operation of the B2H project, 18
under the Term Sheet the Company and PacifiCorp agreed to 19
the exchange of undivided ownership interests in certain 20
transmission assets to provide transmission capacity that 21
better aligns with the current configuration of the 22
parties’ respective future needs following the addition of 23
B2H. The JPSA, included as Agreement 5 in Exhibit No. 2, 24
facilitates these asset exchanges. 25

ELLSWORTH, DI 20
Idaho Power Company
Q. How will the asset exchanges between Idaho 1
Power and PacifiCorp facilitate the objectives of the 2
parties as envisioned in the Term Sheet? 3
A. The Company agreed to exchange with 4
PacifiCorp assets necessary to allow for (1) the transfer 5
to PacifiCorp by Idaho Power of transmission assets between 6
Midpoint and Borah to facilitate 300 MW of west-to-east 7
capacity, (2) the transfer to PacifiCorp by Idaho Power of 8
transmission assets between Borah and Hemingway to enable 9
an additional 600 MW of east-to-west capacity, increasing 10
from the current 1,090 MW to 1,690 MW, (3) the transfer to 11
Idaho Power by PacifiCorp of transmission assets between 12
Populus, Mona, and Four Corners to allow for 200 MW of bi-13
directional capacity, and (4) the transfer by PacifiCorp to 14
Idaho Power of an ownership interest in identified Goshen 15
area assets. 16
Four Corners/Populus Assets. The Company’s ownership 17
interest in the Four Corners/Populus assets will include 18
345-kV transmission lines between the Four Corners, Pinto, 19
Huntington, Camp Williams, Mona, Terminal, 90th South, Ben 20
Lomond, and Populus substations. Consistent with federal 21
processes, the Company and PacifiCorp will complete 22
required studies to determine whether recent system 23
upgrades result in a possible increase in existing 24

ELLSWORTH, DI 21
Idaho Power Company
transmission capacity between Borah and Populus to 1
facilitate Idaho Power’s incremental transfer needs 2
associated with this exchange. If determined necessary, the 3
parties will identify revisions to existing agreements, 4
upgrades, modifications, or other options to meet each 5
party’s commercial needs between Borah and Populus. 6
Goshen Area Assets. Under the Term Sheet, the 7
Parties agreed to make best efforts to plan for service to 8
BPA’s six preference customers in Southeast Idaho that 9
requires only one leg of network transmission from the BPA 10
transmission system. Idaho Power’s ownership interest in 11
the Goshen area assets will enable BPA to serve its loads 12
currently in PacifiCorp’s East transmission with one leg of 13
firm network transmission service from the Company. 14
Borah/Midpoint West Assets. The transfer by Idaho 15
Power to PacifiCorp of Borah/Midpoint West assets will 16
provide ownership to PacifiCorp on the Company’s existing 17
transmission system from Borah/Kinport to Hemingway (east-18
to-west) and from Midpoint 500 to Borah/Kinport (west-to-19
east), including 500-kV and 345-kV transmission lines 20
creating a path between the Borah, Kinport, Adelaide, 21
Midpoint and Hemingway substations. In addition, upgrades 22
will be required across the Borah West and Midpoint West 23
paths to facilitate this portion of the proposed asset 24

ELLSWORTH, DI 22
Idaho Power Company
exchange. 1
Q. Is Idaho Power requesting approval of these 2
asset exchanges as part of the request in this case? 3
A. No. The asset exchanges will not be effective 4
until energization of the B2H project which is expected to 5
occur in 2026. Exhibit A to the JPSA does however identify 6
the assets necessary for facilitating the capacity rights 7
agreed upon and acquired by Idaho Power or conveyed to 8
PacifiCorp. Both the Company and PacifiCorp will request 9
approval of the agreement pursuant to Idaho Code § 61-328, 10
detailing the benefits associated with the assets being 11
exchanged and demonstrating the transaction is consistent 12
with the public interest, in a future proceeding. 13
Q. Have Idaho Power and PacifiCorp contemplated 14
who will be responsible for operations and maintenance of 15
the exchanged assets? 16
A. Yes. PacifiCorp and the Company will expand 17
the existing Joint Ownership and Operating Agreement, as 18
amended and restated August 22, 2019, (“JOOA”) to include 19
operation and maintenance provisions associated with the 20
assets acquired by both parties under the JPSA. In 21
addition, the Second Amended and Restated JOOA, identified 22
as Agreement 6 on Exhibit No. 2, will include the 23
ownership, operation, and maintenance provisions associated 24
with the B2H project. 25

ELLSWORTH, DI 23
Idaho Power Company
Q. Are there any additional agreements between 1
the Company and PacifiCorp as envisioned under the Term 2
Sheet? 3
A. Yes. As described in the Term Sheet, the 4
Company and PacifiCorp will execute the B2H Project Joint 5
Construction Funding Agreement (“Construction Funding 6
Agreement“) that will cover all work necessary to construct 7
B2H. The Construction Funding Agreement, identified as 8
Agreement 7 on Exhibit No. 2, will provide definitive terms 9
and conditions by which the parties will jointly support 10
and contribute funds, for the procurement, construction, 11
and commissioning of the B2H project, allowing for 12
energization of the project by the earliest in-service date 13
needed by the parties. In addition, it appoints Idaho 14
Power as the construction project manager, providing for 15
full power and authority to do all things necessary or 16
proper to develop and construct the B2H project. Finally, 17
the Construction Funding Agreement will incorporate work 18
associated with the installation of the Midline Series 19
Capacitor substation, which was originally envisioned as a 20
separate funding agreement in the Term Sheet. The Midline 21
Series Capacitor substation is necessary to reduce 22
simultaneous interactions between the NW AC Intertie, 23
central and southern Oregon load service, and Path 14 24
(Idaho to Northwest). The Company expects to execute the 25

ELLSWORTH, DI 24
Idaho Power Company
Construction Funding Agreement with PacifiCorp in July 1
2023. 2
Q. Are there any other construction agreements 3
required for the B2H project? 4
A. Yes. Idaho Power and PacifiCorp will, in 5
conjunction with the JPSA, execute two additional 6
construction agreements, the Midpoint 500/345-kV 7
Transformer Project Construction Agreement (“Midpoint 8
Transformer Construction Agreement”) and the Kinport – 9
Midpoint 345-kV Series Capacitor Bank Project Construction 10
Agreement (“Kinport Capacitor Bank Construction 11
Agreement”). Under the Midpoint Transformer Construction 12
Agreement, the Company will make capital upgrades to the 13
Midpoint 500-kV and 345-kV transmission substations, 14
including a second 500/345-kV transformer bank and 345-kV 15
tie line. Capital upgrades will be made to the Midpoint 16
345-kV transmission line under the Kinport Capacitor Bank 17
Construction Agreement including installation of Kinport-18
Midpoint 345-kV series capacitor bank. The two construction 19
agreements, identified as Agreements 9 and 10 on Exhibit 20
No. 2, are expected to be executed in March 2023. 21
Q. Are any changes to transmission service 22
agreements between the Company and PacifiCorp necessary to 23
facilitate the proposed ownership structure of the B2H 24
project? 25

ELLSWORTH, DI 25
Idaho Power Company
A. No. While initially contemplated in the Term 1
Sheet, PacifiCorp has determined they will not terminate 2
their existing 510 MW of east-to-west transmission service 3
across southern Idaho as initially anticipated. Rather, as 4
shown on Exhibit No. 2 as Agreement 11, PacifiCorp is 5
expected to continue this existing 510 MW of PTP 6
transmission service from Idaho Power. PacifiCorp’s PTP 7
transmission service is term specific, and has roll over 8
rights, so PacifiCorp will continue to reserve its rights 9
to either terminate the service or roll it over. This 10
decision will be made by PacifiCorp every five years. Idaho 11
Power will continue to plan its system assuming PacifiCorp 12
retains their transmission service. 13
II. TRANSMISSION PLANNING AND THE IRP PROCESS 14
Q. What is the goal of the IRP? 15
A. The goal of the IRP is to ensure: (1) Idaho 16
Power’s system has sufficient resources to reliably serve 17
customer demand and flexible capacity needs over a 20-year 18
planning period, (2) the selected resource portfolio 19
balances cost, risk, and environmental concerns, (3) 20
balanced treatment is given to both supply-side resources 21
and demand-side measures, and (4) the public is involved in 22
the planning process in a meaningful way. For reliability 23
purposes, in the 2021 IRP the Company planned its resource 24
portfolio to have a Loss of Load Expectation (“LOLE”) of 25

ELLSWORTH, DI 26
Idaho Power Company
0.05 days per year or better (i.e. less than one resource 1
adequacy related outage event in 20 years). 2
Q. Please explain the Loss of Load Expectation. 3
A. The LOLE is a statistical measure of a 4
system’s resource adequacy, describing the expected number 5
of days per year that a system would be unable to meet 6
demand. Idaho Power plans to meet a reliability threshold 7
of 0.05 days per year, or better, which represents one 8
resource adequacy related outage event, or less, in 20 9
years. The Company utilizes test years, based on historical 10
data, to calculate its LOLE. Given Idaho Power’s dependence 11
on its hydro system, which fluctuates with water 12
conditions, and the increased frequency of extreme events, 13
the Company has aligned its resource adequacy methodology 14
with the Northwest Power Conservation Council. The 15
calculation of a system LOLE is complex, and not easily 16
input into modeling software, therefore, the Company 17
converts its LOLE methodology into a tabulated load and 18
resource balance for the purposes of long-term planning. 19
Q. Please explain the “load and resource 20
balance.” 21
A. The load and resource balance is the Company’s 22
tabulated plan that identifies resource deficiencies during 23
the 20-year IRP planning horizon. It helps ensure Idaho 24
Power has sufficient resources to meet projected customer 25

ELLSWORTH, DI 27
Idaho Power Company
demand plus a margin to account for extreme conditions, 1
reserves, and resource outages, and is checked against the 2
LOLE. It is critical when comparing future resource 3
portfolios that each plan achieve at least a base 4
reliability threshold. 5
Q. How is the resulting resource sufficiency or 6
deficiency determined through the load and resource 7
balance? 8
A. At a high level, the load and resource balance 9
incorporates the expected availability of Idaho Power’s 10
existing resources, comparing the total output to the 11
Company’s forecasted load, and illustrates the resulting 12
surplus or deficit by month. This will identify the 13
Company’s first resource need date, or the point at which 14
Idaho Power’s reliability requirements may not be met. 15
Q. How is the expected availability of the 16
Company’s existing resources determined? 17
A. The availability of existing resources, 18
including Public Utility Regulatory Policies Act (PURPA) 19
projects, power purchase agreements, hydro, coal, gas, 20
demand response, and market purchases, is determined using 21
a number of factors such as expected stream flows, plant 22
run times, forced outages, historical performance, and 23
transmission import capability, among other considerations. 24

ELLSWORTH, DI 28
Idaho Power Company
Q. You indicated this is compared to Idaho 1
Power’s forecasted load. How is the load forecast 2
determined? 3
A. Each year, the Company prepares a forecast of 4
sales and demand for electricity based on a combination of 5
historical system data and trends in electricity usage 6
along with numerous external economic and demographic 7
factors. The anticipated average load and anticipated 8
peak-hour demand forecast represent Idaho Power’s most 9
probable outcome for load requirements during the planning 10
period. The difference between the expected availability 11
of the Company’s existing resources and the forecasted load 12
is the resulting surplus or deficit by month. 13
Q. How does the Company address a resource 14
deficiency identified through the load and resource balance 15
analysis? 16
A. Deficits identified through the formation of 17
the load and resource balance are then used to develop 18
resource portfolios through potential combinations of 19
supply-side resources, such as solar plus storage 20
generation facilities, demand-side resources like energy 21
efficiency measures, and transmission projects that 22
increase access to energy markets. The portfolios are then 23
analyzed and the portfolio that best minimizes cost and 24

ELLSWORTH, DI 29
Idaho Power Company
risk, and meets the LOLE, is selected in the plan as the 1
preferred portfolio. 2
Q. Please explain the importance of the Company’s 3
transmission system with regard to resource planning. 4
A. The Company’s transmission system is a 5
critical component of Idaho Power’s ability to provide 6
reliable and fair-priced energy services. Transmission 7
lines facilitate the delivery of economic resources and 8
allow resources to be sited where most cost effective. 9
Furthermore, geographic diversity of resources and robust 10
connections to neighboring systems facilitate system 11
resiliency and minimize impacts from localized weather or 12
events. For much of its history, Idaho Power has relied 13
upon resources outside of its major load pockets to 14
economically serve its customers. The existing transmission 15
lines between Idaho Power and the Pacific Northwest have 16
been particularly valuable. 17
Transmission lines are constructed and operated at 18
different operating voltages depending on purpose, location 19
and distance. Idaho Power operates transmission lines at 20
138-kV, 161-kV, 230-kV, 345-kV, and 500-kV. Idaho Power 21
also operates sub-transmission lines at 46-kV and 69-kV. 22
The higher the voltage, the greater the capacity of the 23
line and the lower the relative losses, but also greater 24
construction cost and physical size requirements. 25

ELLSWORTH, DI 30
Idaho Power Company
Therefore, depending on the capacity needs, economics, 1
distance, and intermediate substation requirements, either 2
230-kV, 345-kV, or 500-kV transmission lines may be chosen 3
as a resource to facilitate the delivery of economic 4
resources. Exhibit No. 4 shows an overview of the Company’s 5
high-voltage transmission system. 6
Q. Please describe the Company’s existing 7
transmission capacity between the Pacific Northwest and 8
Idaho Power. 9
A. Idaho Power owns 1,280 MW of transmission 10
capacity between the Pacific Northwest transmission system 11
and the Company’s service territory. Of this, 1,200 MW are 12
on the “Idaho to Northwest” path and 80 MW are on the 13
“Montana-Idaho” path (the Company has transmission rights 14
through Montana to the Pacific Northwest as part of the 15
Amps Agreement – a legacy agreement currently scheduled to 16
expire in 2025). Avista, BPA, and PacifiCorp share an 17
allocation of capacity on the western side of the Idaho to 18
Northwest path and Idaho Power owns 100 percent of the 19
capacity on the eastern side of the path. To use the 20
Company’s share of the Idaho to Northwest capacity to serve 21
customer load, Idaho Power must purchase transmission 22
service from Avista, BPA, or PacifiCorp. Similarly, in 23
order to connect resources in the Pacific Northwest to 24
Idaho Power’s transmission system via the Montana-Idaho 25

ELLSWORTH, DI 31
Idaho Power Company
path, the Company must purchase transmission service from 1
either Avista or BPA to transmit, or wheel, the power 2
across their system and deliver to Idaho Power’s 3
transmission system. The Company fully utilizes the 4
capacity of these lines. 5
Q. Does Idaho Power own any transmission capacity 6
to the south? 7
A. Yes. The Company owns or controls 8
transmission capacity between utilities in the south via 9
the Idaho – Nevada path with NV Energy, which is utilized 10
to import energy from the North Valmy Power Plant, and the 11
Idaho – Utah path (“Path C”) with PacifiCorp. There is no 12
firm transmission availability across Nevada to leverage 13
the Idaho – Nevada path’s import capacity to access Desert 14
Southwest markets. Regarding Path C, PacifiCorp is the 15
owner and operator of all Path C transmission lines. Idaho 16
Power has secured 50 MW of transmission capacity across 17
PacifiCorp between the months of June and October to access 18
the Desert Southwest markets. 19
Q. When did the Company begin analyzing 20
transmission adequacy and/or projects in the IRP? 21
A. Idaho Power began analyzing transmission 22
adequacy as part of the 2000 IRP. Prior to this time, 23
Idaho Power planned for temporary water-related generation 24
deficiencies through the use of short-term power purchases. 25

ELLSWORTH, DI 32
Idaho Power Company
As a summer-peaking utility, short-term power purchases 1
were successful because the majority of other utilities in 2
the Pacific Northwest region experienced peak loads during 3
the winter. Therefore, prior to 2000, Idaho Power’s IRPs 4
emphasized acquisition of energy rather than construction 5
of generating resources to satisfy load obligations as 6
transmission constraints were not a major impediment of the 7
Company’s purchasing power to meet its service obligations. 8
In addition, IRP planning periods were ten years at the 9
time and therefore significant resource deficiencies did 10
not exist in the ten-year planning period. However, 11
because the Company had started experiencing transmission 12
constraints, coupled with expected renewable resource 13
development in the region, transmission adequacy analyses 14
began being performed as part of the 2000 IRP planning 15
process. 16
Q. How did Idaho Power analyze transmission 17
adequacy? 18
A. To better assess the adequacy of the power 19
supply and the transmission system, the Company performed a 20
peak-hour transmission analysis which quantifies the 21
magnitude of off-system market purchases that may be 22
required to serve the load and determines if adequate 23
transmission capacity is available to deliver those 24
purchases. The results of the analysis performed as part 25

ELLSWORTH, DI 33
Idaho Power Company
of the 2000 IRP indicated transmission deficiencies under 1
low water conditions of approximately 150 MW in 2002, 2
growing to 500 MW by 2009. 3
Q. Did Idaho Power continue to include 4
transmission planning as part of the IRP preparation? 5
A. Yes. The results of the 2002 IRP transmission 6
adequacy analysis, under a 90th percentile water and 70th 7
percentile load condition, were July peak transmission 8
deficiencies of 141 MW and 225 MW in 2003 and 2004, 9
respectively, increasing by 75-90 MW per year beginning in 10
2006, with deficiencies beginning to appear in December and 11
January as well. The results of the 2004 IRP again showed 12
July peaks were expected to increase by approximately 90 MW 13
per year. By 2013, transmission deficiencies began 14
appearing in May through September and reached to nearly 15
800 MW. 16
Q. Were any changes made to the 2006 IRP with 17
respect to transmission adequacy? 18
A. Yes. Beginning with the 2006 IRP, Idaho Power 19
commenced analyzing transmission system constraints for a 20
20-year planning period. In addition, it was at this time 21
that the transmission analysis began factoring a 95th 22
percentile peak-hour load along with a 90th percentile 23
water and 70th percentile load condition for establishing a 24
capacity target for planning purposes. 25

ELLSWORTH, DI 34
Idaho Power Company
Q. How did these refinements impact transmission 1
deficiencies during the 20-year planning period? 2
A. Deficiencies continued to exist during the 3
summer months throughout the planning period growing from 4
450 MW in 2011 to as much as 1,800 MW in 2025. As a 5
result, the preferred portfolio selected through the 2006 6
IRP process, and accepted by the Commission with Order No. 7
30281, included two significant supply-side resource 8
additions, one of which was 225 MW of additional 9
transmission capacity to occur in 2012 via a connection to 10
the Pacific Northwest power markets, a project at the time 11
envisioned as a 230-kilovolt transmission line between the 12
McNary substation and Boise. 13
Q. Was this the first time Idaho Power had 14
considered transmission capacity as a supply-side resource 15
addition? 16
A. Yes, and soon after completion of the 2006 17
IRP, with Order No. 07-002, the Public Utility Commission 18
of Oregon adopted guidelines regarding integrated resource 19
planning including a guideline specific to transmission:1 20
Guideline 5: Transmission. Portfolio 21
analysis should include costs to the utility for 22
the fuel transportation and electric transmission 23
required for each resource being considered. In 24
addition, utilities should consider fuel 25

1 In the Matter of Public Utility Commission of Oregon
Investigation into Integrated Resource Planning, Docket No.
UM 1056, Order No. 07-002, pp. 13-14.

ELLSWORTH, DI 35
Idaho Power Company
transportation and electric transmission 1
facilities as resource options [emphasis added], 2
taking into account their value for making 3
additional purchases and sales, accessing less 4
costly resources in remote locations, acquiring 5
alternative fuel supplies, and improving 6
reliability. 7
8
Q. How are supply-side resources compared when 9
evaluating costs of resources during the IRP process? 10
A. When evaluating and comparing alternative 11
resources, two major cost considerations exist: the capital 12
cost of the project, or fixed costs, and the energy cost of 13
the project, or variable costs. Capital costs are derived 14
through cost estimates to install the various projects and 15
energy costs are calculated through a detailed modeling 16
analysis, using the AURORA software, for both transmission 17
capacity and supply-side resource additions. Energy prices 18
are based on forecasted gas prices, coal prices, nuclear 19
prices, hydro conditions, and variable operations and 20
maintenance expenses. Portfolios that include transmission 21
capacity as a resource addition include costs associated 22
with market purchases, as forecasted in the AURORA model. 23
Q. At what point did the plan for the 230-kV 24
transmission line change to a 500-kV transmission line? 25
A. Following inclusion of the 230-kV transmission 26
line between the McNary substation and Boise in the 27
preferred portfolio of the 2006 IRP, Idaho Power determined 28

ELLSWORTH, DI 36
Idaho Power Company
there was insufficient room at the existing McNary 1
substation for major transmission expansion options. In 2
addition, as part of the regional transmission planning 3
public review process conducted by the Northern Tier 4
Transmission Group (“NTTG”), it was determined a 230-kV 5
project would be unable to meet the Company’s overall 6
resource planning requirements and would underutilize a 7
substantial transmission corridor. A project operating at 8
a voltage of 500-kV was selected to match the existing 9
Pacific Northwest transmission grid. The resulting project 10
identified to meet this need, the B2H project, is an 11
approximately 300-mile long, overhead, 500-kV high voltage 12
transmission line between the proposed Longhorn Station 13
near Boardman, Oregon, to the existing Hemingway Substation 14
in southwest Idaho, which is designed to increase capacity 15
between the Pacific Northwest and Idaho Power’s service 16
area, adding 1,050 MW of capacity to the Idaho to Northwest 17
path in the west-to-east direction, and 1,000 MW of 18
capacity from east-to-west.2 Exhibit No. 5 shows a map of 19
the region with the B2H project substation termination 20
points. 21

2 Beyond the 1,000 MW of east-to-west capacity gained with B2H, the addition of
the Gateway West project will further increase the east-to-west capacity
between the Pacific Northwest and Idaho Power’s service area by approximately
800 - 1,000 MW by mitigating transmission limitations east of Hemingway.

ELLSWORTH, DI 37
Idaho Power Company
Q. Has the Company evaluated whether alternative 1
transmission arrangements might better serve Idaho Power’s 2
need for transmission capacity? 3
A. Yes. Idaho Power studied a number of 4
alternative transmission additions to determine the best 5
solution to the Company’s need. The Company’s analysis 6
assumed the 300-mile line between the Longhorn station and 7
the Hemingway station. The following is a summary of 8
relative capacities, anticipated ratings, and losses for 9
new transmission lines at different operating voltages:3 10
Table 1. Comparison of Transmission Line Capacity Scenarios 11
– New Lines from Longhorn to Hemingway 12
Scenario Line
Capacity1
Potential Path 14
W-E 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%

3 A number of factors impact the transfer capability of
transmission lines, including distance, technical design,
source/sink capabilities, relative location in the bulk
electric system, etc.

ELLSWORTH, DI 38
Idaho Power Company
1 Line Capacity is the thermal rating of the assumed conductors 1
and does not account for system limitations of voltage, stability, or 2
reliability requirements. 3
2 Potential Rating is based upon study results to date to meet 4
reliability design requirements for the WECC ratings processes, not 5
including simultaneous interaction studies. 6
3 Estimated Losses are percent losses for the new line at the 7
Potential Rating loading level. Annual energy losses are dependent on 8
total system loss reductions. All of the scenarios would likely yield a 9
total system loss reduction for the flow levels above. 10
11
In addition, the Company evaluated the possibility 12
of constructing a new line built in place of an existing 13
transmission line, known as a rebuild, for a portion of the 14
total line length and new line built in a new right-of-way 15
for the remaining portion of the total line length. Every 16
rebuild scenario required at least 136 miles of new 17
construction in a new right-of-way. 18
Table 2. Comparison of Transmission Line Capacity Scenarios 19
– Rebuild Existing Lines to the Northwest 20
Scenario Line
Capacity1
Potential
Path 14
Increase2
Losses on
New
Circuit(s)3
Length of
Line / New
ROW4
a. 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
b. Replace Oxbow - Lolo
230kV 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
c. 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
d. 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

e. Build double circuit
500 kV/230 kV line from
McNary to Quartz. Build
500 kV from Quartz to
Hemingway
3,214 MW 765 MW W-E
870 MW E-W
3.9% 298 Miles /
168 Miles

ELLSWORTH, DI 39
Idaho Power Company
1 Line Capacity is the thermal rating of the assumed conductors 1
and does not account for system limitations of voltage, stability, or 2
reliability requirements. 3
2 Potential Rating is based upon study results to date to meet 4
reliability design requirements for the WECC ratings processes, not 5
including simultaneous interaction studies. 6
3 Estimated Losses are percent losses for the new line at the 7
Potential Rating W-E loading level. Annual energy losses are dependent 8
on total system loss reductions. All of the scenarios would likely 9
yield a total system loss reduction for the flow levels above. 10
4 In addition to utilizing the existing 230-kV right-of-way, 11
each of the scenarios above will require a new ROW to be obtained. 12
13
The result of these analyses indicated the only scenarios 14
capable of providing 1,050 MW of west-to-east capacity are 15
new lines at an operating voltage of 500-kV or greater. 16
Q. Has the capacity of the B2H project received a 17
rating from any other entity? 18
A. Yes. Early in the B2H project development, the 19
Company coordinated with other utilities in the Western 20
Interconnection via a peer-review process known as the WECC 21
Path Rating Process. Through the WECC Path Rating Process, 22
Idaho Power worked with other western utilities to 23
determine the maximum rating (power flow limit) across the 24
transmission line under various stresses, and system flow 25
conditions on the bulk power system. Based on industry 26
standards to test reliability and resilience, Idaho Power 27
simulated various outages, including the outage of B2H, 28
while modeling these various stresses to ensure the power 29
grid was capable of reliably operating with increased power 30
flow. Through this process, the Company also ensured the 31
B2H project did not negatively impact the ratings of other 32

ELLSWORTH, DI 40
Idaho Power Company
transmission projects in the Western Interconnection. Idaho 1
Power completed the WECC Path Rating Process in November 2
2012 and achieved a WECC Accepted Rating of 1,050 MW in the 3
west-to-east direction and 1,000 MW in the east-to-west 4
direction. It was determined that the B2H project would add 5
significant reliability, resilience, and flexibility to the 6
Northwest power grid. Exhibit No. 6 to my testimony is the 7
Project Review Group Phase II Rating Report resulting from 8
this study. 9
Q. Was the B2H project identified as part of the 10
preferred portfolio of subsequent IRPs? 11
A. Yes. The B2H project was identified as part 12
of the preferred resource portfolio in Idaho Power’s 2009, 13
2011, 2013, 2015, 2017, 2019 and most recently in the 2021 14
IRP. In addition, the B2H project has been identified as a 15
regionally significant project, producing a more efficient 16
or cost-effective plan in NTTG’s 2007, 2009, 2011, 2013, 17
2015, 2017, and 2019 biennial regional transmission plans, 18
and in the NorthernGrid, NTTG’s successor regional planning 19
organization, 2021 biennial regional transmission plan. 20
The B2H project has proven to be a regionally significant 21
project through the regional transmission planning process 22
as well as a cost-effective resource through successive 23
IRPs. 24
25

ELLSWORTH, DI 41
Idaho Power Company
III. THE B2H PROJECT AND THE 2021 IRP 1
Q. Please describe the process for analyzing 2
resources as part of Idaho Power’s most recent IRP, the 3
2021 IRP. 4
A. Historically, the Company manually developed 5
portfolios to eliminate resource deficiencies identified in 6
a 20-year load and resource balance. Under this process, 7
Idaho Power developed portfolios that were demonstrated to 8
eliminate the identified resource deficiencies. However, 9
beginning with the Second Amended 2019 IRP, and again with 10
the 2021 IRP, the Company began using AURORA’s long-term 11
capacity expansion (“LTCE”) modeling capability to develop 12
portfolios.4 13
The logic of the LTCE model optimizes resource 14
additions and exits of generating units based on the 15
performance of each zone defined within WECC and develops 16
resource portfolios under various future conditions, such 17
as sensitivities for natural gas prices, carbon costs, load 18
growth and electrification, transmission and clean energy 19
constraints and timelines. The LTCE model applies a 20
planning margin hurdle and regulation reserve requirements, 21
and then optimizes resource selections around those 22
constraints to determine a least-cost, least-risk 23
portfolio. Available future resources possess a wide range 24

4 Case No. IPC-E-21-43

ELLSWORTH, DI 42
Idaho Power Company
of operating, development, and environmental attributes. 1
Impacts to system reliability and portfolio costs of these 2
resources depend on future assumptions. Each portfolio 3
consists of a combination of resources derived from the 4
LTCE process to enable Idaho Power to supply cost-effective 5
electricity to customers over the 20-year planning period. 6
Q. Was any further analysis performed on the 7
portfolios that resulted from the LTCE modeling? 8
A. Yes. For the 2021 IRP, the Company developed 9
a branching scenario analysis strategy to ensure that the 10
resulting portfolios reasonably identified an optimal 11
solution specific to its customers. Exhibit No. 7 details 12
the initial branching evaluation where Idaho Power compared 13
AURORA-optimized portfolios for a base scenario (i.e., 14
planning conditions for all key inputs such as load growth, 15
natural gas price, carbon price, etc.) for six potential 16
future portfolios. Each of these portfolios was fully 17
optimized by the LTCE model: (1) Base with the B2H project, 18
(2) Base with the B2H project but without Gateway West, (3) 19
Base with the B2H project and PacifiCorp Bridger Alignment, 20
(4) Base without the B2H project, (5) Base without the B2H 21
project and without Gateway West, and (6) Base without the 22
B2H project but with PacifiCorp Bridger Alignment. Idaho 23
Power compared the base portfolios that included the B2H 24
project to determine an optimal B2H project-included 25

ELLSWORTH, DI 43
Idaho Power Company
portfolio (“Base with B2H”) and compared the base 1
portfolios that did not include the B2H project to 2
determine an optimal B2H-excluded portfolio (“Base without 3
B2H PAC Bridger Alignment”). 4
Q. What occurs once the LTCE modeling and 5
robustness testing is complete? 6
A. Once the portfolios are created using the LTCE 7
model, Idaho Power performs the portfolio cost analysis 8
using the AURORA electric market model, determining 9
operating costs for the 20-year planning horizon for each 10
of the six resource portfolios. The AURORA software applies 11
economic principles and dispatch simulations to model the 12
relationships between generation, transmission, and demand 13
to forecast market prices. Various mathematical algorithms 14
simulate the regional electrical system to determine how 15
utility generation and transmission resources operate to 16
serve load. Portfolio costs are calculated as the net 17
present value (“NPV”) of the 20-year stream of annualized 18
costs, fixed and variable, for each portfolio. 19
Q. What were the results of the AURORA electric 20
market modeling of the six different portfolios? 21
A. Each of the six different portfolios were 22
evaluated through three different hourly simulations, 23
including the planning case scenario as well as bookends 24
for natural gas and carbon adder price forecasts. The 25

ELLSWORTH, DI 44
Idaho Power Company
hourly simulations enable the Company to compare how the 1
portfolios will perform throughout the 20-year timeframe 2
and identify a potential option for a preferred portfolio. 3
The following table presents the results of the hourly 4
simulations: 5
Table 3. 2021 IRP portfolios, NPV years 2021–2040 ($ x 1,000) 6
7
8 1 The Company did not continue further evaluation of this portfolio beyond planning conditions due to the portfolio’s 9
inferior performance (high-cost, poor reliability, and poor emissions performance). 10
2 All portfolios were optimized with planning conditions. The “Base with B2H—High Gas High Carbon (HGHC) Test” 11
portfolio includes total renewables equivalent to the “Base without B2H” portfolio and was evaluated to test B2H as an 12
independent variable. The results indicate that B2H remains cost effective, independent of gas price and carbon price 13
and that a pivot to even more renewables in a future with a high gas and carbon price would be appropriate. 14
15
This comparison indicates the Base with B2H portfolio best 16
minimizes both cost and risk and is the appropriate choice 17
for the preferred portfolio. 18
Q. For the portfolios that include the B2H 19
project, do the modeled costs reflect Idaho Power’s 45.45 20
percent ownership share reflected in the Term Sheet and 21
subsequently the Purchase, Sale and Security Agreement? 22
A. Yes. The 2021 IRP modeled B2H costs based on 23
an Idaho Power ownership share of 45.45 percent. 24
Q. How did the cost of the Base with B2H 25
portfolio compare to the Base without B2H PAC Bridger 26
Portfolio
Planning Gas,
Planning
Carbon
Planning
Gas, Zero
Carbon
High Gas,
High Carbon
Base with B2H $7,942,428 $7,213,486 $9,858,726
Base B2H PAC Bridger Alignment $8,021,906 $7,175,514 $9,955,484
Base without B2H $8,219,281 $7,810,996 $9,501,435
Base without B2H without Gateway West1 $8,470,101 - -
Base without B2H PAC Bridger Alignment $8,207,893 $7,610,787 $9,675,450
Base with B2H—High Gas High Carbon
Test2 $8,024,064 - $9,451,660

ELLSWORTH, DI 45
Idaho Power Company
Alignment portfolio as determined through the LTCE 1
modeling? 2
A. Comparing the NPV cost of the Base with B2H 3
portfolio to the Base without B2H PAC Bridger Alignment 4
portfolio, results in a $266 million difference, or $266 5
million more costly than the preferred portfolio. This cost 6
difference definitively shows that the B2H project is a 7
necessary component of the Company’s preferred portfolio, 8
assuming comparable risk performance to other portfolios. 9
Q. Did Idaho Power perform any additional testing 10
of the branching scenario analysis? 11
A. Yes. To further validate transmission 12
planning results, the Company performed additional 13
robustness testing including various sensitivities and 14
scenarios on the portfolios that included the B2H project, 15
including one specific to the robustness of the B2H 16
project, and testing capacity sensitivities, cost risks and 17
timing, which I will describe in more detail later in my 18
testimony. The results of all the sensitivities and 19
scenarios performed validated and further verified that the 20
results of the LTCE modeling identified optimal solutions 21
for Idaho Power’s customers. 22
Q. You indicated the cost of a resource is based 23
on the capacity cost, or fixed costs, and the energy cost, 24
or variable costs of that resource. How did the capacity 25

ELLSWORTH, DI 46
Idaho Power Company
cost of the B2H project compare to alternative resources 1
when evaluated in the 2021 IRP? 2
A. The table below provides capital costs for 3
resource options found in the 2021 IRP to have the lowest 4
cost from a capacity perspective: 5
Table 4. Total capital dollars ($/kW) for select resources 6
considered in the 2021 IRP (2021$) 7
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. 8
2 Depreciable life assumed for the solar component is 30 years and is 15 years for the storage component. 9
10
The capital costs for the B2H project include local 11
interconnection costs and the project is still roughly 70 12
percent of the cost of the next lowest-cost resource. 13
Additionally, transmission lines, have a longer depreciable 14
life when compared to a gas plant or a solar plant. The low 15
up-front cost and longer depreciation period further 16
reduces the rate impact to Idaho Power’s customers. The 17
summation of these factors show the B2H project is the 18
lowest capital-cost resource by a substantial margin. 19
Q. Has the Company performed any modeling outside 20
of the IRP to test whether Idaho Power’s current 45.45 21
percent ownership share in the B2H project is the most cost 22

ELLSWORTH, DI 47
Idaho Power Company
effective and least risk option? 1
A. Yes. Although entirely hypothetical, Idaho 2
Power analyzed alternatives to the ownership structure to 3
evaluate the risk associated with, and cost-effectiveness 4
of, a 45.45 percent ownership share to gauge reasonableness 5
of the modeling results. First, bookends were created 6
using results from the 2021 IRP modeling. As shown in 7
Table 3, the least-cost portfolio without the B2H project, 8
Base without B2H PAC Bridger Alignment, is approximately 9
$8.208 billion and the least-cost portfolio with the B2H 10
project, Base with B2H, has a cost of $7.942 billion, 11
indicating a $266 million difference between the two 12
bookends. Next, the Company modeled an extremely 13
conservative scenario in which there is no value associated 14
with the additional capacity Idaho Power gains through 15
acquisition of BPA’s ownership share. That means that even 16
under the highly unlikely scenario where the Company 17
receives no transmission revenues associated with its 45.45 18
percent ownership share, the B2H portfolio remains the most 19
cost effective and least risk. 20
Q. What were the resulting portfolio costs? 21
A. Assuming the unlikely hypothetical scenario 22
results in a portfolio cost of $8.089 billion, indicating 23
that even absent value to the additional capacity Idaho 24
Power will receive with 45.45 percent ownership, the 25

ELLSWORTH, DI 48
Idaho Power Company
portfolio is still $119 million more cost effective than 1
the lowest cost “without B2H” portfolio. The results 2
indicate that acquisition of BPA’s ownership share of the 3
B2H project, with payment from BPA for network transmission 4
service, is the most cost-effective solution for the 5
Company’s customers. The B2H project as a resource has 6
repeatedly demonstrated to be the most cost-effective 7
method of serving projected customer demand, and as a 8
transmission line the B2H project also offers incremental 9
ancillary benefits, additional operational flexibility, and 10
access to abundant clean energy in the Pacific Northwest. 11
IV. THE B2H PROJECT COSTS INCLUDED 12
IN THE PREFERRED PORTFOLIO 13
14
Q. What were the B2H project costs included in 15
the 2021 IRP preferred portfolio? 16
A. The cost estimate included in the 2021 IRP 17
preferred portfolio included B2H project costs assuming 18
Idaho Power’s ownership share under the Term Sheet, or 19
45.45 percent. Prepared between 2020 and 2021, the cost 20
estimate was based on a 10 percent detailed 21
design/indicative design, the best available information at 22
the time. Ms. Barretto will discuss the detailed 23
design/indicative design milestones in more detail in her 24
testimony. The capital costs modeled, including Allowance 25
for Funds Used During Construction but excluding any 26

ELLSWORTH, DI 49
Idaho Power Company
contingency amounts, were $435.5 million. In addition, the 1
2021 IRP preferred portfolio included approximately $49.7 2
million in additional capital costs associated with the B2H 3
project transmission upgrades, for local 230-4
kV upgrades necessary to integrate the project into 5
Treasure Valley load center and an estimated 6
associated with the NPV of the buyout of BPA’s permitting 7
interest. 8
Q. How were the B2H project costs determined? 9
A. The Company contracted with HDR, Inc. (“HDR”) 10
to serve as the B2H project’s third-party owners’ engineer 11
and prepare the B2H transmission line cost estimate. HDR 12
has extensive industry experience, including experience 13
serving as an owner’s engineer for BPA for the last seven 14
years. HDR has prepared a preliminary transmission line 15
design that locates every tower and access road needed for 16
the project. HDR used utility industry experience and 17
current market values for materials, equipment, and labor 18
to arrive at the B2H estimate. Material quantities and 19
construction methods are well understood because the B2H 20
project is utilizing BPA’s standard tower and conductor 21
design for 500-kV lines. BPA has used the proposed towers 22
and conductor on hundreds of miles of lines currently in-23
service. 24

ELLSWORTH, DI 50
Idaho Power Company
Q. Were substation costs included in this 1
estimate? 2
A. Yes. Costs associated with three substations 3
are included in the B2H project cost estimate, the Longhorn 4
station, the Hemingway substation, and a Midline Series 5
Capacitor substation. The northern terminus for B2H 6
requires the new Longhorn station to tap into the existing 7
BPA 500-kV transmission network. BPA owns the land for the 8
Longhorn station and intends to construct the substation, 9
at the request of Umatilla Electric for load service 10
purposes, once all environmental compliance laws are met. 11
As agreed under the Term Sheet, BPA will own all equipment 12
and facilities in the Longhorn station, except B2H-specific 13
equipment and facilities that will be jointly owned by 14
Idaho Power and PacifiCorp. The Company’s ownership share 15
of the jointly owned equipment is included in the B2H 16
project costs modeled in the 2021 IRP. 17
The Idaho Power-owned existing Hemingway substation 18
is designed to accommodate the B2H line terminal but will 19
require the addition of new equipment, which was also 20
included in the total B2H project costs. The Midline 21
Series Capacitor station was added to the project scope 22
between the 2019 IRP and 2021 IRP to facilitate the 23
operational needs of the parties, and at this time consists 24
of only a fenced yard and series capacitor. Finally, the 25

ELLSWORTH, DI 51
Idaho Power Company
B2H project costs also include costs associated with 1
necessary local interconnection upgrades, upgrades 2
necessary to the southern Idaho transmission system and 3
BPA’s permitting buyout. 4
Q. How did the Company calibrate the total B2H 5
project costs for reasonableness? 6
A. The B2H project costs included in the modeling 7
of the 2021 IRP were reviewed and approved by BPA and 8
PacifiCorp, both of whom have recent 500-kV transmission 9
line construction projects to calibrate against. In 10
addition, Idaho Power worked collaboratively with NV Energy 11
and Southern California Edison to calibrate the B2H project 12
cost estimate using their experience on two recent 500-kV 13
projects. 14
Q. Transmission capacity can be sold to third 15
parties when not being utilized by the Company. How did 16
Idaho Power model the transmission wheeling revenue 17
benefits associated with B2H? 18
A. The B2H project is modeled in AURORA as 19
additional transmission capacity available for Idaho Power 20
energy purchases from the Pacific Northwest. In general, 21
for new supply-side resources modeled in the IRP process, 22
surplus sales of generation are included as a cost offset 23
in the AURORA portfolio modeling. Transmission wheeling 24
revenues, however, are not included in AURORA calculations. 25

ELLSWORTH, DI 52
Idaho Power Company
To account for this, in the 2021 IRP, Idaho Power modeled 1
incremental transmission wheeling revenue from non-native 2
load customers outside of AURORA as an annual revenue 3
credit. Therefore, the preferred portfolio which includes 4
the B2H project, includes a reduction in project costs 5
associated with incremental transmission revenues, 6
ultimately benefiting the Company’s retail customers. The 7
transmission revenue credit incorporates any changes in 8
point-to-point reservations with BPA and PacifiCorp as 9
agreed to under the Term Sheet, including expected revenues 10
from the NITSAs with BPA I discussed earlier in my 11
testimony. 12
Q. Are there any potential additional benefits in 13
transmission revenues Idaho Power did not include in its 14
quantification? 15
A. Yes. Due to significant increase in capacity 16
that the B2H project provides to the Idaho to Northwest 17
path, the Company believes firm, short-term firm, and non-18
firm usage of the Idaho Power transmission system by third 19
parties could increase, as supported by the over 1,000 MWs 20
of transmission requests that the Company has seen across 21
the Idaho to Northwest path over the past 24 months. 22
Additionally, Idaho Power’s acquisition of 200 MW of 23
bidirectional capacity to Four Corners, New Mexico will 24
only further enhance the value of the Company transmission 25

ELLSWORTH, DI 53
Idaho Power Company
system to third parties. These potential revenues would 1
further reduce the cost of the project, however, to be 2
conservative, Idaho Power assumed a constant transmission 3
usage by third parties (no increase or decrease) from an 4
average of usage over recent years. 5
Q. Did the B2H project costs modeled in the 2021 6
IRP include a contingency? 7
A. No. None of the modeled resources in the 2021 8
IRP included a contingency amount, including the B2H 9
project. Therefore, it would have skewed the IRP modeling 10
results to have included a contingency amount in the B2H 11
cost estimate. That said, the Company did perform a risk 12
analysis in the 2021 IRP for informational purposes in 13
which Idaho Power evaluated 10 percent, 20 percent and 30 14
percent cost contingencies for the B2H project. The 15
following table presents the B2H project costs, by cost 16
category, and cost contingency utilized in the risk 17
analysis: 18
Table 5. B2H Project Costs by Cost Contingency 19
Contingency % B2H Main
Project
Local 230
Upgrades
NPV BPA
Permitting
Buyout
Total Total
Portfolio
NPV Impact
B2H 0% $435.5M $485M $159.6M
B2H 10% $472.7M $526M $178.4M
B2H 20% $509.8M $566M $197.2M
B2H 30% $546.8M $607M $216.1M
20
The line labeled B2H 0% reflects the costs described 21
earlier and modeled in the 2021 IRP. For IRP purposes, the 22
Company reports Total Portfolio Net Present Value (“NPV”) 23

ELLSWORTH, DI 54
Idaho Power Company
Impact because this is the amount that must be added to the 1
Preferred Portfolio. The total costs of all resources are 2
levelized into an annual amount, and quantified over the 3
20-year IRP planning period, for fair comparison purposes. 4
The table below presents the results of the risk analysis 5
that evaluated the various cost contingencies: 6
Table 6. B2H Cost Sensitivities 7
8
   B2H Cost  
Idaho Power Share TOTAL  B2H Cost 
2021 IRP NPV  
B2H 0% Contingency  $485 million  $159.6 million 
B2H 10% Contingency  $526 million  $178.4 million 
B2H 20% Contingency  $566 million  $197.2 million 
B2H 30% Contingency  $607 million  $216.1 million 
9
The 2021 IRP portfolio NPV cost for B2H is $159.6 million 10
assuming a 0 percent contingency amount. B2H with a 30 11
percent contingency increases the cost of B2H by $122 12
million ($607 million less $485 million) but that increase 13
only results in increased B2H portfolio costs of $56.5 14
million NPV. As I mentioned earlier, the difference between 15
the Preferred Portfolio, and the best alternative portfolio 16
that did not include B2H was approximately a $266 million 17
NPV. Additionally, IRPs are based on comparing portfolios, 18
and the best alternative portfolio that did not include B2H 19
included the Gateway West project, another 500-kV 20
transmission project. An increase in B2H costs would likely 21
mean that there would be a comparable increase to Gateway 22
West costs. Therefore, B2H costs could increase 23

ELLSWORTH, DI 55
Idaho Power Company
significantly, and well beyond 30 percent, and the project 1
would remain cost effective. 2
Q. Has Idaho Power updated the B2H project cost 3
estimate since publishing the 2021 IRP? 4
A. Yes. As Ms. Barretto discusses in her 5
testimony, the Company’s constructability consultant 6
assisted the Company in updating its B2H project cost 7
estimate. Assuming Idaho Power’s 45.45 percent ownership 8
share, B2H project costs are estimated to be 9
, including a 20 percent contingency. The increase 10
from the 2021 IRP B2H project cost estimate of $485 million 11
can primarily be attributed to (1) increased material and 12
labor costs due to inflation and supply chain issues, and 13
(2) the inclusion of approximately in 14
contingency costs, at a total project level, which were not 15
included in the 2021 IRP B2H project costs. 16
Q. Please explain the increased material and 17
labor costs resulting from inflation and supply chain 18
issues. 19
A. Inflationary pressures and supply chain 20
disruptions are pushing up the cost of labor and materials 21
necessary to construct B2H. However, transmission expansion 22
is required independent of the portfolio selected to drive 23
least-cost. The least-cost non-B2H portfolio requires a 24
sub-segment of Gateway West in 2027, and another Gateway 25

ELLSWORTH, DI 56
Idaho Power Company
West segment in 2033. The cost estimate of these Gateway 1
West segments in the 2021 IRP was based on the estimated 2
cost of B2H, therefore, the cost of the optimal non-B2H 3
portfolio would also increase. In the case of the least-4
cost non-B2H portfolio, the cost increases associated with 5
Gateway West (assuming the same inflationary and supply 6
chain pressures) would be nearly offsetting when compared 7
to the Preferred Portfolio. Inflationary pressures and 8
supply chain disruptions are therefore immaterial, as the 9
Company must build something to meet its load service 10
requirement, and there is no economic way to avoid a major 11
500-kV transmission project. 12
Q. How does the increased B2H cost estimate 13
impact the economics of the project and the conclusions 14
drawn in the 2021 IRP? 15
A. The following table presents the December 2022 16
B2H project cost estimate and total portfolio NPV impact 17
together with the 2021 IRP B2H project costs by cost 18
category and cost contingency presented earlier in my 19
testimony in Table 5. 20
Table 7. B2H Project Costs by Cost Contingency Using Updated 21
Costs 22
Contingency % B2H Main
Project
Local 230
Upgrades
NPV BPA
Permitting
Buyout
TOTAL TOTAL
Portfolio
NPV Impact
B2H 0% $435.5M $485M $159.6M
B2H 10% $472.7M $526M $178.4M
B2H 20% $509.8M $566M $197.2M
B2H 30% $546.8M $607M $216.1M
2022 B2H Costs
23

ELLSWORTH, DI 57
Idaho Power Company
While the total B2H cost increases from $485 million (zero 1
percent contingency) to (20 percent 2
contingency), the Preferred Portfolio NPV cost impact is 3
only an increase from $159.6 million to , a 4
impact. By inspection, a 5
increase does not result in a change to the Preferred 6
Portfolio, as the best non-B2H portfolio is $266 million 7
more costly. And, as I explained earlier in my testimony, 8
the best non-B2H portfolio would see similar increases due 9
to increased Gateway West costs. 10
In addition, if Idaho Power were to update costs of 11
all capital projects based on current conditions, the B2H 12
project is not the only variable that would change. As I 13
noted above, a primary factor driving the increase in the 14
B2H cost estimate is increased material and labor costs due 15
to inflation and supply chain issues—which would impact the 16
cost of capital projects in all portfolios studied. B2H 17
replacement resources have also seen price increases due to 18
inflationary and supply chain pressures since the 2021 IRP 19
was published, therefore, the least-cost non-B2H portfolio 20
would experience cost increases as well. Even with the cost 21
increase, the Company has sufficient information to 22
ascertain that the B2H project remains the least-cost, 23
least-risk option using the December 2022 updated estimate 24
of . 25

ELLSWORTH, DI 58
Idaho Power Company
V. JUSTIFICATION FOR THE B2H PROJECT 1
Q. Aside from the B2H project being a component 2
of the least-cost preferred portfolio, what other benefits 3
does the line provide? 4
A. In a low-carbon future dominated by renewable 5
resources, geographical diversity of wind and solar, as 6
well as regional utility loads, is a vital component of 7
reliability and affordability, and transmission is the 8
enabler of geographical diversity. In-depth studies and 9
experts, such as the American Clean Power Association, cite 10
the need for an expanded and robust transmission system in 11
a decarbonized future.5 Indeed, the Americans for a Clean 12
Energy Grid highlighted B2H as one of 22 projects that were 13
needed to enable the interconnection of around 60,000 MW of 14
additional renewable capacity in the United States.6 In 15
addition, a variety of other benefits are expected: 16
capacity to the Four Corners market hub, improved economic 17
efficiency, renewable integration, grid 18
reliability/resiliency, resource reliability, contingency 19
reserves, reduced electrical losses, flexibility, Energy 20
Imbalance Market (“EIM”) value, and economic value along 21
the B2H project route. 22

7 Slide 20, https://eta-publications.lbl.gov/sites/default/files/lbnl-
empirical_transmission_value_study-august_2022.pdf
7 Slide 20, https://eta-publications.lbl.gov/sites/default/files/lbnl-
empirical_transmission_value_study-august_2022.pdf

ELLSWORTH, DI 59
Idaho Power Company
Improved Economic Efficiency and Renewable Integration 1
Q. How does the B2H project improve economic 2
efficiency and the integration of renewable resources? 3
A. Transmission congestion causes power prices on 4
opposite sides of the congestion to diverge as higher cost, 5
less efficient resources are dispatched to ensure the 6
transmission system is operating securely and reliably. 7
Congestion can have a significant cost. Historically, 8
during peak summer conditions, the Idaho to Northwest path 9
in the west-to-east direction often becomes fully 10
constrained with zero firm transmission available between 11
the regions and power prices in Idaho and to the east will 12
generally be higher than power prices in the Pacific 13
Northwest, a market inefficiency caused by inadequate 14
transmission capacity to economically move power between 15
regions. The B2H project will help alleviate this 16
constraint and enable generators in the Pacific Northwest 17
to gain further value from their existing resource, and 18
load-serving entities in the Mountain West region will be 19
able to meet load service needs at a lower cost. At other 20
times, such as the winter, the roles may reverse with the 21
Pacific Northwest benefiting from economical resources from 22
the Mountain West region with B2H’s additional east-to-west 23
capacity. 24

ELLSWORTH, DI 60
Idaho Power Company
Similarly, the lack of transmission capacity, at 1
times, prevents the energy from existing renewable 2
generation to move to load, which in turn requires 3
renewable resources to be curtailed. The B2H project is 4
necessary to integrate and balance variable energy 5
resources like wind and solar as it will facilitate the 6
transfer of geographically diverse renewable resources 7
across the western grid and help ensure the clean energy 8
grid of the future, both Idaho Power’s and surrounding 9
states’, is robust and reliable. Lawrence Berkley National 10
Laboratory recently published a study titled “Empirical 11
Estimates of Transmission Value using Locational Marginal 12
Prices.”7 In the study, the difference between the 13
EIM_BPAHub node and the EIM_UT node (the EIM Utah node is a 14
close surrogate for Idaho Power), has an approximately 15
$13.50 per MWh mean power spread between 2012 and 2022, 16
resulting in approximately $125 million per year in 17
potential energy arbitrage related value. This value, or a 18
subset, was not factored into the 2021 IRP but represents a 19
real benefit to Idaho Power’s customers, nevertheless. 20
Grid Reliability/Resiliency 21
Q. Please explain how the B2H project will 22
contribute to the reliability and resiliency of the grid. 23

7 Slide 20, https://eta-publications.lbl.gov/sites/default/files/lbnl-
empirical_transmission_value_study-august_2022.pdf

ELLSWORTH, DI 61
Idaho Power Company
A. The B2H project will increase the robustness 1
and reliability of the regional transmission system by 2
adding high-capacity bulk electric facilities designed with 3
the most up-to-date engineering standards. Major 500-kV 4
transmission lines, such as B2H, substantially increase the 5
grid’s ability to recover from unexpected disturbances. 6
Q. What are some examples of unexpected 7
disturbances whose impacts would be reduced with the 8
addition of the B2H project? 9
A. While unexpected disturbances are difficult to 10
predict, I can provide a few examples of disturbances whose 11
impacts would be reduced with the addition of B2H. First, 12
the loss of the Hemingway–Summer Lake 500-kV transmission 13
line, the only 500-kV connection between the Pacific 14
Northwest and Idaho Power, during peak summer load, is one 15
of the worst possible contingencies the Company’s 16
transmission system can experience. Once the Hemingway–17
Summer Lake 500-kV disconnects, the transfer capability of 18
the Idaho to Northwest path is reduced by over 700 MW in 19
the west-to-east direction. After the addition of the B2H 20
project, there will be two major 500-kV connections between 21
the Pacific Northwest and Idaho Power, reducing risk by 22
increasing redundancy. 23
Another potential Idaho Power disturbance could be 24
on the same Hemingway-Summer Lake 500-kV line but east-to-25

ELLSWORTH, DI 62
Idaho Power Company
west. In this disturbance, an existing remedial action 1
scheme (power system logic used to protect power system 2
equipment) will disconnect over 700 MW of generation at the 3
Jim Bridger Power Plant or Wyoming wind to reduce path 4
transfers and protect bulk transmission lines and 5
apparatus. Due to the magnitude of the generation loss, 6
recovery from this disturbance can be extremely difficult. 7
After the addition of the B2H project, this sizable amount 8
of generation shedding will no longer be required. With two 9
500-kV lines between Idaho and the Pacific Northwest, the 10
loss of one can be absorbed by the other. Keeping 700 MW of 11
generation on the system for major system outages is 12
important for grid stability. 13
Third, the loss of a single 230-kV transmission 14
tower in the Hells Canyon area could create another 15
transmission disturbance. Idaho Power owns two 230-kV 16
transmission lines, co-located on the same transmission 17
towers, that connect Idaho to the Pacific Northwest. 18
Because these lines are on a common tower, Idaho Power must 19
consider the simultaneous loss of these lines as a 20
realistic planning event. Historically, such an outage did 21
occur on these lines in 2004 during a day with high summer 22
loads. By losing these lines, Idaho Power’s import 23
capability was dramatically reduced, and the Company was 24
forced to rotate customer outages for several hours due to 25

ELLSWORTH, DI 63
Idaho Power Company
a lack of resource availability. With the addition of the 1
B2H project, the impact of this outage would be 2
substantially reduced. 3
Finally, a more general example is discussed in a 4
recent paper titled “Transmission Makes the Power System 5
Resilient to Extreme Weather” by Grid Strategies8 which 6
explored the benefits that transmission can provide to 7
regions experiencing extreme weather. During Winter Storm 8
Uri alone, the paper identifies seven different 9
transmission connections that could have provided over $80 10
million of benefits per 1,000 MW of transmission capacity 11
for that single event, with one specific connection that 12
would have provided nearly $1 billion in benefits per 1,000 13
MW. Extreme events, such as the 2021 Pacific Northwest heat 14
dome, are seemingly increasing in frequency, and 15
transmission lines provide a significant regional 16
diversity, reliability, and resilience benefit. 17
Resource Reliability 18
Q. How does the reliability of a transmission 19
line compare to that of a generation resource? 20
A. The forced outage rate of a resource is the 21
best measure of its reliability, and, in general, the 22
forced outage rate of transmission lines has historically 23

8 https://acore.org/wp-content/uploads/2021/07/GS_Resilient-
Transmission_proof.pdf

ELLSWORTH, DI 64
Idaho Power Company
been lower than traditional generation resources. NERC has 1
historically tracked the forced outage rate for 2
transmission availability through a Transmission 3
Availability Data System (“TADS”) and generation 4
availability through a Generation Availability Data System 5
(“GADS”). 6
Q. What are the comparable NERC forced-outage 7
rates of the various resources? 8
A. The NERC forced-outage rates used in modeling 9
of the 2021 IRP were approximately 6 to 9 percent for coal 10
generation, 3.6 percent for hydro generation, approximately 11
4.4 percent to 7.3 percent for simple cycle gas generation, 12
2 percent for combined cycle gas generation and one-quarter 13
of one percent for transmission resources. A transmission 14
line with a forced outage rate of less than 1 percent is 15
significantly more reliable than a power plant - the B2H 16
project is expected to have 99.75 percent availability when 17
needed. 18
Of course, a transmission line requires generating 19
resources to provide energy to the line to serve load. 20
However, energy sold as “firm” must be backed up and 21
delivered even if a source generator fails. Therefore, firm 22
energy purchases would have an equivalent forced outage 23
rate demand – or EFORd - consistent with the transmission 24
line, which is more reliable than traditional supply-side 25

ELLSWORTH, DI 65
Idaho Power Company
generation. In the management of cost and risk, B2H will 1
provide Idaho Power’s operators additional flexibility when 2
managing the Idaho Power resource portfolio. In addition to 3
lower costs, the 2021 IRP preferred portfolio is 4
significantly more reliable than the best portfolio that 5
did not include B2H. 6
Contingency Reserves and Electrical Losses 7
Q. How will the B2H project support the Company’s 8
contingency reserve obligations? 9
A. During real-time operations, Idaho Power holds 10
generation in reserve to meet its NERC contingency reserve 11
obligation, or generation in reserve equaling at least 12
three percent of network demand plus three percent of 13
internal generation. For market purchase imports, the three 14
percent contingency requirement for the generation is not 15
borne by the Company but rather the producer in the 16
external balancing area is required to meet the reserve 17
obligation associated with its resource, reducing Idaho 18
Power’s reserve obligation. 19
The Company plans to make additional market 20
purchases with B2H and therefore the selling entity will 21
carry the contingency reserve obligation. This reduction in 22
reserve obligation will offset the additional reserve 23
obligations taken on by the Company through the increased 24
amount of BPA customer network load and generation in the 25

ELLSWORTH, DI 66
Idaho Power Company
Idaho Power area. Idaho Power’s reserve obligation during 1
summer peak will be reduced with the B2H project as 2
compared to a replacement internal resource. 3
Q. Is the B2H project expected to reduce 4
electrical losses? 5
A. Yes. Losses on the power system are caused by 6
electrical current flowing through energized conductors, 7
which in turn create heat. By constructing the B2H 8
project, less efficient, lower voltage transmission lines 9
with very large transfers are relieved, reducing the 10
electrical current through these lines and reducing the 11
losses due to heat. 12
Q. How did Idaho Power estimate the reduction in 13
electrical losses that is expected to result from addition 14
of the B2H project? 15
A. The electrical losses vary throughout the year 16
depending on flow levels on the lines. To determine an 17
average electrical loss saving benefit for the Company 18
resulting from the B2H project, various seasonal WECC power 19
flow base cases were utilized to simulate flow conditions 20
with and without the addition of B2H. In six of the seven 21
cases the B2H project resulted in a beneficial reduction of 22
losses in the Idaho Power balancing area. 23
To develop an average loss savings benefit for the 24
B2H project that considers all flow hours, regression 25

ELLSWORTH, DI 67
Idaho Power Company
analysis was performed to develop quadratic equation 1
coefficients that relate path flows to predicted energy 2
loss savings. Next, historical transmission path flows from 3
the previous five years were captured and analyzed with 4
developed loss savings coefficients. The result of the 5
analysis was an Idaho Power 6.4 MW per hour average 6
electrical loss savings with the addition of the B2H 7
project. 8
Capacity to Four Corners Market Hub 9
Q. Please explain the value of the capacity 10
gained to the Four Corners Market Hub. 11
A. As explained earlier in my testimony, under 12
the Term Sheet, Idaho Power will acquire from PacifiCorp 13
transmission assets and their related capacity sufficient 14
to enable the Company to utilize 200 MW of bidirectional 15
transmission capacity between the Company’s system, at the 16
Populus substation, and the Four Corners substation, a 17
desert Southwest market hub. Eight entities with 18
transmission have connectivity to the Four Corners market 19
hub. Along the route between Populus and Four Corners, the 20
Company will also have a connection to Mona substation, in 21
central Utah, establishing a direct connection between 22
Idaho Power and the Los Angeles Department of Water and 23
Power. The 200 MW of bidirectional capacity will provide 24
the Company with long-term strategic value from a market 25

ELLSWORTH, DI 68
Idaho Power Company
that is diverse from the Pacific Northwest. Importantly, 1
the desert Southwest is rich with solar potential which is 2
expected to continue its significant growth in the future, 3
New Mexico has significant wind potential, and the number 4
of desert Southwest entities with a presence at this market 5
hub presents significant market diversity opportunities. 6
Idaho Power believes additional access to this market hub 7
during the winter months will prove to be extremely 8
valuable in a low carbon future. 9
Moreover, the transmission assets between Idaho and 10
Four Corners will provide a valuable firm transmission 11
connection to a market hub that is diverse from Mid-C, 12
enabling two diverse connections to two major western 13
market hubs. As a conservative planning approach, this 14
additional 200 MW of import capacity is set to zero in 15
planning margin calculations for the summer peaking months. 16
The diversity of capacity from multiple market hubs 17
solidifies and supports that the overall B2H project 18
capacity will achieve 500 MW of peak import capacity into 19
Idaho Power. 20
Q. When will the winter value of the Four Corners 21
market access materialize? 22
A. In the 2021 IRP, the Company expected to start 23
seeing this value in the mid-2030s with winter load 24
increasing, and dispatchable coal resources retiring. As 25

ELLSWORTH, DI 69
Idaho Power Company
the Company is currently developing its 2023 IRP, however, 1
Idaho Power is seeing the Four Corner’s capacity as likely 2
especially valuable in the mid to late-2020s. This change 3
is due to the sizeable increase in the load forecast, and 4
specifically the winter load forecast, due to increased 5
industrial loads. 6
Q. How has the value of the Four Corners capacity 7
been quantified? 8
A. In the 2021 IRP, the value of the Four 9
Corner’s capacity was not quantified due to its value 10
starting very late in the plan. Generally, the Company did 11
not see any winter reliability issues in its 20-year plan. 12
The Company expects the Four Corners capacity will provide 13
substantial value in its 2023 IRP when portfolios inclusive 14
of B2H and the Idaho Power and PacifiCorp asset exchange 15
are compared against portfolios not inclusive of B2H and 16
the asset exchange. Due to the latest load growth 17
forecasts, winter capacity needs will likely be a key 18
consideration in the development of the 2023 IRP. 19
Borah West and Midpoint West Capacity Upgrades 20
Q. What value do the Borah West and Midpoint West 21
upgrades provide? 22
A. The Borah West and Midpoint West upgrades 23
consist of the addition of a series capacitor to one of the 24
Borah West transmission lines (the 345-kV line between the 25

ELLSWORTH, DI 70
Idaho Power Company
Kinport substation and the Midpoint substation), and a new 1
high-voltage transformer added to the Midpoint 500-kV 2
substation. These upgrades are required to facilitate the 3
asset exchange with PacifiCorp, enabling PacifiCorp’s usage 4
of its share of B2H project capacity. 5
In the 2021 IRP, as a conservative estimate, the 6
Company assumed the full $46.8 million cost of these 7
upgrades would be Idaho Power’s responsibility. The 8
conservative estimate was chosen because these assets are 9
intended to be utilized to balance the Idaho Power and 10
PacifiCorp asset exchange transaction, and the total values 11
of the assets for each company were unknown. However, 12
subject to final negotiations, it is likely that a portion 13
of these assets will be paid for by PacifiCorp. 14
Q. Given the capacity being acquired by 15
PacifiCorp, will they continue to take 510 MW of point-to-16
point transmission service across the Company? 17
A. Under the Term Sheet, and the Company’s 2021 18
IRP analysis, the expectation was that PacifiCorp would 19
terminate 510 MW of transmission service. PacifiCorp has 20
since indicated their intent to continue to take this 21
service, as is their right as a long-term transmission 22
customer taking PTP service with roll-over rights. 23
Q. Does PacifiCorp’s continued usage of the 510 24
MW change the decision to move forward with B2H? 25

ELLSWORTH, DI 71
Idaho Power Company
A. No. In the 2021 IRP, PacifiCorp terminating 1
the 510 MW of PTP transmission service was evaluated as a 2
cost to B2H due to lost transmission revenue compared to a 3
base “do-nothing” alternative. PacifiCorp continuing to 4
take this PTP transmission service enhances the B2H 5
business case. 6
Q. What is the trade-off for the Company with 7
PacifiCorp continuing to take 510 MW of transmission 8
service? 9
A. In the 2021 IRP, the Company was planning to 10
repurpose the transmission that was being used by 11
PacifiCorp to interconnect new resources in Eastern Idaho 12
to be delivered to the growing Treasure Valley area. The 13
impact of the 510 MW transmission service obligation 14
remaining will be evaluated as part of the 2023 IRP. 15
Additional B2H Project Benefits and Value 16
Q. Please describe the additional expected 17
benefits and value of the B2H project you have not yet 18
discussed in your testimony. 19
A. The B2H project provides Idaho Power with 20
flexibility in the acquisition and transfer of generation 21
resources. As advances in technology are driving some 22
generation resources, such as coal plants, toward economic 23
obsolescence, the B2H project serves as an alternative to 24
constructing a new supply-side resource. In this way, B2H 25

ELLSWORTH, DI 72
Idaho Power Company
reduces the risk of technological obsolescence by ensuring 1
Idaho Power customers always have access to the most 2
economic resources, regardless of the resource type. In 3
addition, because the existing electrical system is so 4
heavily used, new transmission line infrastructure like the 5
B2H project will create additional operational flexibility. 6
The B2H project will increase the ability to take other 7
system elements out of service to conduct maintenance and 8
will provide additional flexibility to move needed 9
resources to load when outages occur on equipment. This 10
additional transmission capacity and operational and 11
resource flexibility also provides value in the EIM and 12
should a day ahead market structure be determined 13
economically beneficial to Idaho Power’s customers, the B2H 14
project will complement the Company’s market participation 15
and facilitate additional economic benefits. 16
Q. How will the B2H project provide additional 17
value in the energy imbalance market, or EIM? 18
A. The expansion of the transmission system, 19
through the addition of the B2H project, will facilitate 20
further benefits by increasing transmission capacity 21
between Idaho Power and other EIM participants. As 22
fluctuations in supply and demand occur for EIM 23
participants, the market system will automatically find the 24
best resources from across the large-footprint EIM region 25

ELLSWORTH, DI 73
Idaho Power Company
to meet immediate power needs. This activity optimizes the 1
interconnected high-voltage system as market systems 2
automatically manage congestion, helping maintain 3
reliability while also supporting the integration of 4
variable energy resources and avoiding curtailing excess 5
supply by sending it to where demand can use it. Greater 6
transmission transfer capacity between participants in a 7
market reduces congestion costs and allows the lowest cost 8
energy to reach a wider load footprint. Idaho Power views 9
the B2H project as a complement to any resource type. The 10
B2H project will enhance access to the least-cost and most 11
efficient resources and unlock additional regional 12
diversity to benefit the Company as well as all customers 13
in the West. 14
Q. Will the B2H project provide any economic 15
benefits to the region? 16
A. Yes. First, the B2H project will result in 17
positive economic impacts for eastern Oregon communities in 18
the form of construction jobs, economic support associated 19
with infrastructure development (i.e., lodging and food), 20
and an estimated increase of $5.8 million in annual tax 21
benefits in total to the counties for project-specific 22
property tax dollars. It will also provide economic 23
development opportunities because it will create available 24
capacity for additional economic development to take place. 25

ELLSWORTH, DI 74
Idaho Power Company
In Union and Umatilla counties, BPA’s McNary–Roundup–La 1
Grande 230-kV line has limited ability to serve additional 2
demand in the Pendleton and La Grande areas but is 3
currently capable of meeting the 10-year load forecast. The 4
B2H project will increase the transfer capability through 5
eastern Oregon by 1,050 MW. This capacity will provide a 6
regional benefit to the entire Northwest and specifically 7
benefit load service to eastern Oregon and southern Idaho. 8
It is possible this added capacity resulting from the B2H 9
project could be used to serve additional demand in Union 10
and Umatilla counties. 11
Portions of Baker County are served by Idaho Power, 12
including the communities of Durkee and Huntington. BPA 13
currently provides energy to Oregon Trails Electric 14
Cooperative (“OTEC”), which serves Baker City via 15
transmission connections between the Northwest and Idaho 16
Power’s transmission system. The existing transmission 17
connections between the Northwest and Idaho Power are fully 18
utilized for existing load commitments, with very little 19
ability to meet load growth requirements. The B2H project 20
associated increased transmission connectivity between the 21
Northwest and Idaho Power will allow BPA to serve 22
additional demand in Baker City. Finally, additional 23
transmission capacity can create opportunities for new 24

ELLSWORTH, DI 75
Idaho Power Company
energy resources, which can add to the county tax base and 1
create new jobs. 2
Q. Are there any additional benefits you have not 3
discussed? 4
A. The B2H project will also provide local area 5
electrical benefits. La Grande and Baker City are served by 6
OTEC. Portions of Morrow County and Umatilla County are 7
served by Umatilla Electric Cooperative (“UEC”) and 8
Columbia Basin Electric Cooperative (“CBEC”). OTEC, UEC, 9
and CBEC pay BPA’s network transmission rate to receive 10
transmission service from the BPA system. As I discussed 11
earlier in my testimony, BPA kicked off a public process 12
related to the B2H project on January 5, 2023, presenting 13
BPA’s business case that shows B2H is a cost-effective 14
solution to meet BPA customer needs. Correspondingly, given 15
the sharing of BPA’s transmission costs among all of BPA’s 16
transmission customers, OTEC, UEC, and CBEC customers would 17
also benefit from this long-term cost-effective solution. 18
VI. RISK ASSOCIATED WITH THE B2H PROJECT 19
Q. Are there any risks associated with the B2H 20
project? 21
A. Risk is inherent in any infrastructure 22
development project. As mentioned earlier in my testimony, 23
as part of the 2021 IRP, Idaho Power evaluated capacity 24
risk, cost risk, and in-service date risk extensively. The 25

ELLSWORTH, DI 76
Idaho Power Company
capacity risk analysis evaluated the impact on portfolio 1
costs in the event that the Company cannot access the fully 2
expected capacity of B2H. The cost risk was evaluated by 3
performing a tipping point analysis. And finally, the 4
Company evaluated the impacts of a 2027 in-service date, a 5
year later than expected. 6
Q. How was the capacity risk analysis performed? 7
A. The B2H project capacity evaluation looked at 8
portfolio costs assuming the Company can access 350 MW, 400 9
MW, 450 MW, 500 MW (equivalent to the preferred portfolio), 10
and 550 MW of capacity. The sensitivities performed with 11
capacity amounts less than 500 MW are set up to evaluate 12
risk related to reduced market access. The 550 MW capacity 13
amount sensitivity quantifies potential benefits associated 14
with leveraging additional market purchases to avoid the 15
need for a new resource. To evaluate the impact of 16
different B2H capacity levels, the Company added or 17
subtracted comparable capacity in the form of battery 18
storage (the least-cost alternative to providing sufficient 19
amounts of capacity) to maintain an adequate planning 20
margin, while maintaining the same cost of B2H to reflect 21
that B2H’s capacity contribution toward the planning margin 22
is reduced with no offsetting cost reduction. The results 23
indicated that even with a substantially reduced planning 24
margin contribution, B2H portfolios remain cost-effective. 25

ELLSWORTH, DI 77
Idaho Power Company
Additionally, if Idaho Power is able to access an 1
additional 50 MW from the Mid-C hub, that may present a 2
cost-saving opportunity for customers.9 3
Q. What did the cost risk evaluation conclude? 4
A. A transmission line such as B2H requires 5
significant planning, organization, labor, and material 6
over a multi-year process to complete and place in-service. 7
Therefore, it is important to evaluate cost risks when 8
planning for such a project. Idaho Power evaluated the cost 9
of the B2H project assuming no contingency, a 10 percent 10
contingency, a 20 percent contingency, and a 30 percent 11
contingency. The results indicated the B2H project would 12
have to increase significantly beyond a 30 percent 13
contingency before the project would no longer be cost-14
effective, i.e., the tipping point is well beyond a 15
reasonable 30 percent contingency bookend. As I discussed 16
earlier, if the actual costs were to reach these levels, it 17
is likely that other comparable resources, and alternative 18
transmission facilities such as Gateway West, would have 19
their own increases in costs as well. 20
Q. Please explain the in-service date risk 21
evaluation. 22
A. The current planned in-service date for B2H is 23

9 The B2H project risk analysis can be found in the 2021 IRP Appendix D,
pp 63-69.

ELLSWORTH, DI 78
Idaho Power Company
prior to the summer of 2026, which is necessary to meet the 1
peak demand growth needs. Should the B2H in-service date 2
slip to 2027, other new resources will be required in 2026. 3
Slippage in the schedule from 2026 to 2027 is a possibility 4
and would require new resources, however, as the 2021 IRP 5
preferred portfolio demonstrates, the B2H project remains 6
the most cost-effective long-term resource. 7
Q. Were there any additional risk analyses 8
performed with respect to the B2H project? 9
A. Yes. Idaho Power also performed a liquidity 10
and market sufficiency risk analysis. As explained earlier 11
in my testimony, the Pacific Northwest is a winter peaking 12
region and Idaho Power operates a system with a summer peak 13
which aligns with the Mid-C hydro runoff conditions when 14
the Pacific Northwest is flush with surplus power capacity. 15
However, the existing transmission system between the 16
Pacific Northwest and the Company is constrained. 17
Constructing the B2H project will alleviate this constraint 18
and add 1,050 MW of total transfer capability between the 19
Pacific Northwest and the Intermountain West region. To 20
evaluate the market sufficiency, Idaho Power assessed five 21
different data points. The first data point was a peak 22
load analysis. British Columbia and other utilities in the 23

ELLSWORTH, DI 79
Idaho Power Company
Pacific Northwest10 have forecast 2030 winter peaks that 1
exceed their forecast 2030 summer peaks by a combined 8,200 2
MW. Given the difference in seasonal peaks, coupled with 3
Columbia River runoff hydro conditions aligning with the 4
Company’s summer peak, resource availability in the Pacific 5
Northwest during Idaho Power’s summer peak is highly 6
likely. 7
For the second data point, the Company reviewed a 8
recent resource adequacy assessment performed by BPA that 9
evaluated resource adequacy from 2021 through 2030.11 Idaho 10
Power concluded from this analysis that: (1) summer 11
capacity will be available in the future, and (2) 12
additional summer capacity will likely be added as the 13
region adds resources to meet winter peak demand. Next, 14
Idaho Power gathered peak load data for the major Pacific 15
Northwest entities in Washington and Oregon to compute the 16
peak coincident load. The results illustrated a wide 17
difference between historical winter and summer peaks. 18
The fourth data point evaluated the Renewable 19
Portfolio Standard (RPS) goals by states such as 20
California, Oregon and Washington which will drive policy-21

10 Load serving entities from included are Avista, BPA, British
Columbia, Chelan, Douglas, Grant, PAC–West, Portland General, Puget
Sound, Seattle City, and Tacoma.
11 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.

ELLSWORTH, DI 80
Idaho Power Company
driven resource additions, and likely result in more solar 1
generation and additional dispatchable flexible ramping 2
resources, such as battery storage. Solar and solar plus 3
storage align very well with summer peak needs, but their 4
value can be limited in the winter months. Meeting winter 5
needs will require the Pacific Northwest region to 6
overbuild these resources above the level to meet a similar 7
summer demand, likely aligning well with the Company 8
looking to access summer energy needs from the market. 9
Finally, the fifth data point evaluated the 10
potential new resources reported by northwest utilities in 11
their IRPs. The list of resources includes 6,389 MW of 12
planned new resources through 2031. As expected, the 13
Northwest utilities are continuing to plan for growing 14
winter peak demands by adding capacity resources, 15
furthering the depth of the market for the summer season. 16
All data points demonstrate that there will be sufficient 17
market resources in the future to utilize the B2H 18
transmission line. 19
VII. CONCLUSION 20
Q. Please summarize your testimony. 21
A. B2H has been a cost-effective resource 22
identified in each of Idaho Power’s IRPs since 2009 and 23
continues to be a cornerstone of Idaho Power’s 2021 IRP 24
preferred portfolio. In the 2021 IRP, as has been the case 25

ELLSWORTH, DI 81
Idaho Power Company
in prior IRPs, the B2H project is not simply evaluated as a 1
transmission line, but rather as a resource that will be 2
used to serve Idaho Power load. That is, the B2H project, 3
and the market purchases it will facilitate, is evaluated 4
in the same manner as a new gas power plant, or a new 5
utility-scale solar plus storage project. 6
As a resource, the B2H project is demonstrated to be 7
the most cost-effective method of serving projected 8
customer demand and meeting clean energy goals. As can be 9
seen in the 2021 IRP, the lowest-cost resource portfolio 10
includes B2H, and the best non-B2H portfolio has a 11
significant cost premium. As a resource alone, the B2H 12
project is the lowest-cost alternative to serve the 13
Company’s customers in Oregon and Idaho. As a transmission 14
line, B2H also offers incremental ancillary benefits and 15
additional operational flexibility. 16
The B2H project is nearing its construction phase 17
and project certainty continues to grow. Idaho Power, 18
PacifiCorp, and BPA executed a Term Sheet in early 2022 and 19
have drafted definitive agreements, ready or near ready for 20
signature, associated with the provisions of the Term 21
Sheet. The agreements address the Parties’ capacity needs, 22
strategies, and goals associated with the B2H project. The 23
Company has extensively evaluated the B2H project as a 24
supply-side resource, explored many of the ancillary 25

ELLSWORTH, DI 82
Idaho Power Company
benefits offered by the transmission line, and considered 1
the risks and benefits of owning a transmission line 2
connected to a market hub in contrast to direct ownership 3
of a traditional generation resource. Once operational, 4
the B2H project will provide Idaho Power increased access 5
to reliable, clean, low-cost market energy purchases from 6
the Pacific Northwest. In addition, the B2H project will 7
increase the efficiency, reliability, and resiliency of the 8
electric system by creating an additional pathway for 9
energy to move between major load centers in the West. The 10
benefits in aggregate reflect the B2H project’s importance 11
to the Company’s commitment to reliability and 12
affordability. 13
Q. Does this complete your testimony? 14
A. Yes, it does. 15
// 16
// 17
// 18
// 19
// 20
// 21
// 22
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// 24
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ELLSWORTH, DI 83
Idaho Power Company
DECLARATION OF JARED L. ELLSWORTH 1
I, Jared L. Ellsworth, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Jared L. Ellsworth. I am 4
employed by Idaho Power Company as the Transmission, 5
Distribution & Resource Planning Director for the Planning, 6
Engineering & Construction Department. 7
2. On behalf of Idaho Power, I present this 8
pre-filed direct testimony and Exhibit Nos. 1 through 7 in 9
this matter. 10
3. To the best of my knowledge, my pre-filed 11
direct testimony and exhibits are true and accurate. 12
I hereby declare that the above statement is true to 13
the best of my knowledge and belief, and that I understand 14
it is made for use as evidence before the Idaho Public 15
Utilities Commission and is subject to penalty for perjury. 16
SIGNED this 9th day of January 2023, at Boise, Idaho. 17
18
Signed: 19
20

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-01

IDAHO POWER COMPANY

ELLSWORTH
TESTIMONY

EXHIBIT NO. 1
Contract No. 22TX-17207
TERM SHEET
THIS TERM SHEET IS INTENDED SOLELY TO FACILITATE DISCUSSIONS
AMONG IDAHO POWER COMPANY (“IDAHO POWER” or “IPC”), PACIFICORP
(“PACIFICORP” or “PAC”), AND THE BONNEVILLE POWER ADMINISTRATION
(“BPA”) (EACH REFERRED TO HEREIN AS A “PARTY” AND COLLECTIVELY
REFERRED TO HEREIN AS THE “PARTIES”) RELATED TO THE
CONSTRUCTION, OWNERSHIP, OPERATION, ASSET EXCHANGES, AND
SERVICE AGREEMENTS REGARDING THE BOARDMAN TO HEMINGWAY
TRANSMISSION LINE PROJECT (“B2H PROJECT” OR “PROJECT”) AND OTHER
TRANSMISSION FACILITIES. EXCEPT FOR SECTION 5 OF THIS TERM SHEET
WHICH SHALL BE LEGALLY BINDING UPON THE PARTIES UPON THE
EXECUTION AND DELIVERY OF THIS TERM SHEET BY ALL OF THE PARTIES
(THE “EFFECTIVE DATE”), (I) THIS TERM SHEET IS NOT INTENDED TO
CREATE, NOR SHALL IT BE DEEMED TO CREATE, A LEGALLY BINDING OR
ENFORCEABLE AGREEMENT OR OFFER, AND (II) NO PARTY SHALL HAVE
ANY LEGAL OBLIGATION WHATSOEVER PURSUANT TO THIS TERM SHEET.
1. BPA Requirements. The Parties acknowledge and agree that in order to
negotiate the Agreements (as defined below) and before BPA can make a
definitive final decision regarding whether to enter into the Agreements, BPA
must (1) engage in customer and stakeholder outreach, share information about
this Term Sheet during the outreach, and solicit feedback; (2) fulfill all
requirements under the National Environmental Policy Act (NEPA), the
National Historic Preservation Act (NHPA) and other applicable environmental
laws, and (3) make a definitive decision in an Administrator’s final record of
decision. Nothing in this Term Sheet shall be construed as indicating that BPA
has engaged in customer and stakeholder outreach; completed its NEPA and
other environmental review processes or made a decision regarding how to
proceed.
2. Term.This Term Sheet shall terminate the earlier of (a) energization of the
B2H Project, or (b) execution of all agreements identified in the Term Sheet, or
(c) mutual written agreement of all Parties. This Term Sheet may be extended
by mutual written agreement of all Parties.
3. Agreements. Upon execution of this Term Sheet, the Parties intend to
negotiate in good faith toward the execution of the definitive, binding
agreements and amendments between or among the Parties described below
consistent with the terms and conditions described below (“Agreements”).
Each of the Parties intends to prepare and deliver to the other Parties initial
drafts of the Agreements it is designated as responsible for below by no later
than the date identified for each agreement. The Parties further intend, subject
Contract No. 22TX-17207 B2H Term Sheet
Page 2 of 32
to the BPA requirements in Section 1, that they will endeavor to complete
negotiation of and execute the Agreements by no later than the date identified
for each agreement;provided, however, that the effectiveness of any such
Agreement may be subject to one or more conditions precedent, including state
or federal regulatory approvals.
a) Asset Exchanges, Transmission Service Agreements, and Amended and
Restated Existing and Future Agreements: The table below defines the transactions
contingent on completion of the B2H Project including, without limitation, regulatory
approval associated with IPC’s acquisition of BPA’s interest in the Amended and Restated
Boardman to Hemingway Transmission Project Joint Permit Funding Agreement (“Joint
Permitting Agreement”), asset exchanges, transmission service agreements, and amended
and restated existing and future agreements. Each of the Parties will prepare an initial draft
of the Agreements and Amendments below for which it is designated as the Primary
Drafter, consistent with the following terms:
Parties / Agreement /
Action / Primary Drafter
General Terms / Details
1. PAC, BPA
Agreement on Principles
and Timelines
Prepare First Draft –
BPA: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
PAC and BPA are parties to the Amended and
Restated Midpoint-Meridian Agreement, originally
executed June 1, 1994 (the “Midpoint-Meridian
Agreement”), which provides PAC with 340 MW of
bidirectional scheduling rights over the Buckley-
Summer Lake 500kV line (the “Buckley-
Summer Lake Line”). In connection with the Goshen
Area Asset Exchange (as referenced in Section
3(a)(7) of this table) and the B2H Midline Series
Capacitor Project (as referenced in Section 3(a)(12)
of this table), PAC and BPA are discussing options to
allow PAC the ability to schedule 340 MW from the
Buckley substation to the 500kV side of the
Ponderosa Transformer Bank 500/230 kV #1
(“Ponderosa 500”) and to concurrently schedule 340
MW from the Summer Lake substation to Ponderosa
500 upon energization of the B2H line and the B2H
Midline Series Capacitor Project.
I. Contingent upon the conditions set forth
below, PAC and BPA desire for the
concurrent bidirectional scheduling rights
over the Buckley-Summer Lake line to be
provided as firm point-to-point transmission
service (“PTP service”) pursuant to the terms
and conditions in BPA’s Tariff and rate
schedules upon energization of the B2H line
Contract No. 22TX-17207 B2H Term Sheet
Page 3 of 32
and the B2H Midline Series Capacitor
Project. As of the Effective Date, the PAC
and BPA understand that such PTP service
remains subject to further BPA evaluation.
a. BPA’s offer of PTP service may include
conditions if such conditions are
identified during BPA’s evaluation.
Conditions for PTP service are at BPA’s
sole discretion and, if required, will be
developed consistent with the principles
set forth in Section 3(a)(1)(II)(b) so that
flows associated with the PTP service
over the Buckley-Summer Lake line do
not exceed 340 MW in the north-to-south
direction and concurrently does not
exceed 340 MW in the south-to-north
direction during all lines in service.
b. As part of the PTP service evaluation,
PAC and BPA will also explore options to
combine an offer of PTP service with the
modification to points of receipt and
points of delivery in PAC’s existing PTP
service tables (“redirect”) within the Long
Term Firm Point-to-Point Service
Agreement (No. 04TX-11722) between
PAC and BPA, subject to BPA’s Tariff
and related business practices including
available transfer capability (“ATC”),
with a goal to optimize PAC’s
transmission service over the Federal
transmission system to serve its central
Oregon loads (e.g., using a single wheel
from a network point of receipt to PAC’s
load at Ponderosa 230 or Pilot Butte 230).
BPA will apply its long-standing practice
to evaluate the ATC impacts of the new
PTP service against the ATC impacts of
existing service, to include the
bidirectional scheduling rights and
redirected service.
c. BPA may request additional information
from PAC. PAC will make good faith
efforts to provide such information within
30 days of BPA’s request.
d. PAC will submit applicable transmission
service request(s) (“TSR”) within 30 days
Contract No. 22TX-17207 B2H Term Sheet
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of BPA’s notice to PAC that such requests
should be submitted.
e. If BPA determines, in its sole discretion,
that BPA can convert the bidirectional
scheduling rights to PTP service, BPA
agrees to offer PTP service pursuant to
BPA’s Tariff and rate schedules.
i. The PTP service will be contingent
upon and will not be effective before
(A) the energization of the B2H line
and the installation of the B2H
Midline Series Capacitor Project; (B)
approval by the Federal Energy
Regulatory Commission (“FERC”) of
the proposed amendments to the
Midpoint-Meridian Agreement
discussed in this Section 3(a)(1), per
subpart (iii below; and (C) the Goshen
Area Asset Exchange set forth in
Section 3(a)(7) of this table is
completed and all associated
agreements are in effect.
ii. PAC and BPA will adhere to the
applicable requirements set forth in
BPA’s Tariff and related business
practices, including timelines for
execution or amendment of a service
agreement.
iii. Concurrent with the execution of the
PTP service agreements contemplated
in this Section 3(a)(1)(I), PAC and
BPA will amend Section 4(a) of the
Midpoint-Meridian Agreement to
remove and otherwise terminate
PAC’s bidirectional scheduling rights
over the Buckley-Summer Lake Line.
f. If BPA offers PTP service that satisfies
PAC’s objectives as expressed in this
Term Sheet, PAC intends to accept such
service subject to the condition regarding
FERC approval described below. If
following FERC acceptance without
material conditions of the arrangements
negotiated between BPA and PAC in this
Section 3(a)(1)(I), PAC nonetheless fails
to submit applicable TSRs or otherwise
Contract No. 22TX-17207 B2H Term Sheet
Page 5 of 32
declines to accept the PTP service or
execute a PTP service agreement, then
BPA will have no further obligations to
provide PAC with the PTP service
described in this Section 3(a)(1)(I) or the
scheduling rights described in Section
3(a)(1)(II) below.
g. PAC and BPA will negotiate in good faith
to complete and enter into agreements
needed to complete the other conditions
set forth in Sections 3(a)(2) through (14)
and 3(c) of this Term Sheet, as such
conditions are applicable to either Party.
h. PAC will seek FERC guidance as
necessary and file the proposed
amendment to the Midpoint-Meridian
Agreement with FERC for acceptance.
BPA will reasonably coordinate with PAC
to prepare for FERC meetings and
submissions. FERC’s unconditioned
acceptance shall be a condition to PAC’s
obligations as contemplated under this
Term Sheet.
II. Following either (1) BPA’s determination that
it is unable to provide the PTP service to PAC
consistent with Section 3(a)(1)(I) above, or
(2) FERC’s failure to accept without material
conditions the arrangements negotiated
between PAC and BPA under Section
3(a)(1)(I) above, BPA will, effective upon
energization of the B2H line and the B2H
Midline Series Capacitor Project provided
that all conditions described below are met,
provide PAC with bidirectional scheduling
rights over the Buckley-Summer Lake line
which give PAC the ability to (A) schedule
340 MW from the Buckley substation to
Ponderosa 500 (“North to South schedules”)
and (B) concurrently schedule 340 MW from
the Summer Lake substation to Ponderosa
500 (“South to North schedules”)
(collectively referred to as “scheduling
limits”). The concurrent, bidirectional
scheduling rights described in the
immediately preceding sentence will be
Contract No. 22TX-17207 B2H Term Sheet
Page 6 of 32
provided pursuant to an amendment to the
Midpoint-Meridian Agreement and one or
more separately negotiated agreements, that
will be effective upon acceptance by FERC
and after all conditions set forth in this
Section 3(a)(1)(II) are met and will remain in
effect until BPA offers PTP service as set
forth in Section 3(a)(1)(I). PAC and BPA
will work in good faith to satisfy all such
conditions consistent with the principles
articulated in Section 3(a)(1)(II)(b) below by
energization of the B2H line.
a. Transmission service to move from the
Ponderosa 500 substation. The utilization
of the concurrent bidirectional scheduling
rights at the Ponderosa substation
described in this Section 3(a)(1)(II) is
limited to Ponderosa 500. PAC must
reserve PTP service from BPA pursuant to
BPA’s Open Access Transmission Tariff
(“OATT”), business practices, and rate
schedules in effect at the time of such
reservation to move from Ponderosa 500
to the 230 kV side of Ponderosa
transformer bank #1 for delivery to PAC
load in central Oregon.
b. Principles to guide satisfaction of
conditions.
i. North to South schedules, South to
North schedules, and the associated
directional power flows may not
exceed the scheduling limits (e.g., 340
MW North to South and, concurrently,
340 MW South to North, under all
lines in service). A Power Transfer
Distribution Factor (“PTDF”) based
methodology (“PTDF algorithm”) and
calculator will be used to determine
directional power flow. The PTDF
algorithm will sum positive flows in
the North to South and South to North
directions (i.e., schedules and flows
are not netted).
ii. If, at any time, North to South
schedules, South to North schedules,
or the associated directional power
Contract No. 22TX-17207 B2H Term Sheet
Page 7 of 32
flows exceed the scheduling limits,
PAC shall reduce the schedules so that
the schedules and directional power
flows are within the scheduling limits.
BPA can, at BPA’s sole discretion,
curtail the schedules in whole or in
part to maintain the scheduling limits
and to mitigate congestion, such as
during outages.
iii. Schedules (E-Tags) must contain a
single granular source and sink.
Sources and sinks (1) cannot be
consolidated on a single E-Tag; and
(2) must be granular enough to
determine the PTDF impact. Sources
and sinks that are scheduling points,
hubs, or nodes are not sufficiently
granular to determine the PTDF
impact.
iv. PAC may not schedule from sources
and sinks for which the PTDF impact
has not been determined. PAC will
provide BPA with advance notice of
sources and sinks with sufficient time
for BPA to determine the PTDF
impact and, if necessary, to
accommodate modifications to tools,
systems, and contracts.
v. The terms, tools, and protocols
associated with the concurrent
bidirectional scheduling rights will be
structured to minimize to the
maximum extent possible any impacts
exceeding the scheduling limits (e.g.,
340 MW North to South and,
concurrently, 340 MW South to North,
under all lines in service) that the
physical flows associated with the
concurrent bidirectional scheduling
rights have on the Pacific Northwest
AC Intertie (as such transmission
facilities are defined in the various
PNW AC Intertie-related agreements
among PAC, BPA and the other PNW
AC Intertie owners, the “NW AC
Intertie”)or the Federal transmission
Contract No. 22TX-17207 B2H Term Sheet
Page 8 of 32
system, as reasonably determined by
BPA.
c. Conditions to Effectiveness of 3(a)(1)(II)
Scheduling Rights
i. PTDF calculator. BPA will develop a
PTDF algorithm to calculate the
directional power flow associated with
each source and sink that PAC intends
to schedule. PAC and BPA will
coordinate to develop, at PAC’s
expense, a PTDF calculator that uses
the PTDF algorithm and related
communication equipment.
ii. Agreement on operational terms.
After the PTDF calculator is
developed, PAC and BPA will work in
good faith to develop operational
terms, to include the protocols and
requirements for monitoring, dispatch,
curtailment, reduction of scheduling
limits due to outages, and future
modifications to stay current with
reliability standards, automation, and
technological abilities. The
operational terms will remain in effect
for the duration of the concurrent
bidirectional scheduling rights
described in this Section 3(a)(1)(II)
and will be incorporated into the
proposed amendments to the
Midpoint-Meridian Agreement or such
other agreement as mutually agreed by
PAC and BPA.
iii. Energization of the B2H Project,
including the B2H Midline Series
Capacitor Project.
iv. The agreements set forth in Section
3(a)(1)(III) below are, to the extent
required, accepted for filing at FERC
without material conditions.
v. The Goshen Area Asset Exchange set
forth in Section 3(a)(7) of this table is
completed and all associated
agreements are in effect.
III.Agreements.
Contract No. 22TX-17207 B2H Term Sheet
Page 9 of 32
a. Agreement on Principles and Timelines.
Following execution of the Term Sheet,
PAC and BPA will negotiate and execute
an agreement to reflect the objectives,
commitments, principles, conditions, and
timelines, including negotiation of
applicable follow-on agreements for the
PTP service described in Section
3(a)(1)(I), and the concurrent,
bidirectional scheduling rights described
in Section 3(a)(1)(II). With regard to the
concurrent, bidirectional scheduling rights
described in Section 3(a)(1)(II), the
Agreement on Principles and Timelines
would include the principles and
conditions set forth in Section 3(a)(1)(II)
above, and the timelines for development
of the PTDF calculator and negotiation of
operational terms and protocols.
b. Follow-on Agreements. Before
energization of B2H and subject to the
conditions described above in this Section
3(a)(1) being met, PAC and BPA will
negotiate and execute (1) the agreements
and amendments referenced in Section
3(a)(1)(I) above, or (2) if BPA is not yet
providing PTP service upon B2H
energization consistent with Section
3(a)(1)(I) above, then an amendment to
the Midpoint-Meridian Agreement to
reflect the addition of the concurrent
bidirectional scheduling rights, including
term, scheduling and directional power
flow requirements, usage of the PTDF
calculator, and operational terms, all as
consistent with Section 3(a)(1)(II) above.
PAC and BPA understand that PAC may
be required to file amendments to the
Midpoint-Meridian Agreement with
FERC for acceptance and that the
effective date for the agreements
referenced above will be upon FERC
acceptance without material conditions.
IV. Consistent with the “Phase II Joint Study
Report (2020-2021), Boardman to
Contract No. 22TX-17207 B2H Term Sheet
Page 10 of 32
Hemingway (B2H) and Incremental Central
Oregon Load” completed on March 23, 2021,
upon notice from BPA, PAC will upgrade the
existing Meridian Series Capacitor on the 500
kilovolt bus or install an electrically
equivalent series capacitor on the PAC
section of the Dixonville-Meridian-Klamath
Falls-Captain Jack lines in southern Oregon
within a reasonable time after receiving the
notice. PAC shall be responsible for all costs
associated with the upgrade.
V. PAC and BPA agree that the proposed
modifications to the Midpoint-Meridian
Agreement described above are limited in
scope to PAC’s bidirectional scheduling
rights over the Buckley-Summer Lake line
under Section 4 of the Midpoint-Meridian
Agreement and do not include BPA’s
bidirectional scheduling rights over the
Summer-Lake Malin line under Section 4 of
the Midpoint-Meridian Agreement. PAC and
BPA do not intend to modify, change, alter,
or terminate BPA’s bidirectional scheduling
rights over the Summer Lake-Malin line set
forth in Section 4 of the Midpoint-Meridian
Agreement or the General Transfer
Agreement between PAC and BPA, originally
executed May 4, 1982, as amended.
2. IPC & PAC & BPA
New operational
agreement between IPC,
PAC & BPA
Prepare First Draft –
BPA: Quarter 3 of
Calendar Year 2022
Target Execution Date:
Quarter 4 of Calendar
Year 2022
IPC, PAC and BPA agree to negotiate in good faith
and draft a tri-party operational agreement that will:
a. Consider Midpoint-Meridian Agreement
Section 5(f); and
b. Define the curtailment procedures
between NW AC Intertie, Western
Electricity Coordinating Council (WECC)
Path 14 (Idaho to Northwest), and WECC
Path 75 (Hemingway – Summer Lake);
and
c. Identify conditions for revising the tri-
party operational agreement including, but
not limited to:
i. Engagement with NW AC Intertie
partners;
Contract No. 22TX-17207 B2H Term Sheet
Page 11 of 32
ii. In the event the B2H Project and the
B2H Midline Series Capacitor Project
are not complete and energized by
2027.
The Parties will make best efforts to negotiate and
target execution of the tri-party operational
agreement within one year of the Effective Date of
this Term Sheet, with an effective date for the tri-
party operational agreement a reasonable time
thereafter.
3. PAC & BPA
Termination of Existing
NITSAs:
PAC Trans – BPA
Merchant NITSAs (SA
Nos. 746, 747)
Incorporate into
Agreement on Principles
and Timelines under
3(a)(1)
BPA Network Integration Transmission Service
Agreements (“NITSAs”) (PacifiCorp Service
Agreement No. 746 and No. 747): BPA and PAC
agree to terminate the aforementioned NITSAs upon
(1) the completion of the asset purchase and sale
between IPC and PAC as detailed in Section 3(a)(5)
through Section 3(a)(7) of this table – the Goshen
Area Asset Exchange, and (2) the commencement of
network service as described in Section 3(b)(1).
4. IPC & BPA & PAC
New Agreement:
Longhorn Substation
Agreements
Prepare First Draft –
BPA: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
IPC and PAC will fund a portion of the proposed
Longhorn substation near Boardman, Oregon, if B2H
interconnects at Longhorn. This funding will occur as
specified in one or more negotiated Longhorn
Substation Agreements between the Parties that is
consistent with BPA’s Line and Load
Interconnection Business practices and allows for
recovery of the network portion of these funds
through incremental transmission wheeling revenue.
The agreement will:
a. include provisions for IPC and PAC to
pay a use of facilities charge or other
charge pursuant to BPA’s OATT and
applicable rate schedules to transact across
the Longhorn bus in the future;
b. include provisions for IPC and PAC to
potentially own, operate and maintain
B2H equipment, which shall include:the
Contract No. 22TX-17207 B2H Term Sheet
Page 12 of 32
B2H series capacitor at Longhorn, the
B2H shunt line reactors at Longhorn, any
ancillary equipment required to support
those devices, such as switches, bypass
breakers (series cap), and insertion
breakers (shunt reactor); and
c. be contingent upon BPA completing its
obligations and responsibilities under
NEPA, NHPA, and other requisite
environmental compliance laws and
making a decision regarding how to
proceed (including provisions for IPC and
PAC funding upfront at a prorated amount
based on cost allocation of Longhorn,
BPA’s NEPA, NHPA, and environmental
compliance costs).
Non-binding cost estimates identified for the
potential Longhorn aspects of the B2H Project as of
the Effective Date of this Term Sheet are as follows,
which all Parties acknowledge and agree are
preliminary and may be modified and revised prior to
and upon B2H energization:
These are estimated costs, charges to be trued up
with actual costs.
a. Longhorn (base substation) network costs
~$59M. Costs subject to transmission
credit.
i. IPC 21% ~ $12M (BPA to cover up to
$14M of IPC cost)
ii. PAC 55% ~ $33M
iii. BPA 24% ~ $14M (plus IPC ~ $12M,
for total ~ $26M)
b. B2H connection to Longhorn Network
Bay~$11M.
Constructed/Owned/Maintained by BPA.
Develop bay 3 with (2) 500kV circuit
breakers & (5) 500kV disconnects. Costs
subject to transmission credits.
i. IPC & PAC 100%
c. Customer built (not subject to
transmission credits). Including civil work
with the reactor and cap costs.
Contract No. 22TX-17207 B2H Term Sheet
Page 13 of 32
5. IPC & PAC
New Agreement:
Purchase and Sale
Agreement for Asset
Exchange -potentially
utilize the previously
developed Joint
Purchase and Sale
Agreement
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 4 of Calendar
Year 2022
PAC and IPC would purchase and sell to each other
various assets to achieve the objectives identified in
Section 3(a)(6) and Section 3(a)(7) of this table. PAC
and IPC will seek to first balance the purchase and
sale of the transferred assets through the depreciated
net book value of such assets and allocation of
upgrade costs and, finally, if necessary, will be
balanced between IPC and PAC through cash
considerations.
Details related to Populus – Four Corners assets:
These assets will provide IPC ownership on the
existing PAC transmission system from Four Corners
substation in New Mexico to Populus substation in
Idaho. This will include 345 kV transmission lines
between the following substations and assets to
create a path through each substation:
Four Corners, Pinto, Huntington, Camp Williams,
Mona, Terminal, 90th South, Ben Lomond and
Populus.
Consistent with federal processes, IPC and PAC will
complete required studies to determine if recent
system upgrades result in a possible increase in
existing transmission capacity between Borah and
Populus to facilitate IPC’s incremental transfer needs
associated with this exchange. If determined
necessary, IPC and PAC will identify revisions to the
JOOA (as defined in Section 3(a)(6) of this table),
upgrades, modifications, or other options to meet
each party’s commercial needs between Borah and
Populus.
Details related to Borah/Kinport to Hemingway and
Midpoint to Borah/Kinport assets:
These assets will provide PAC ownership on the
existing IPC transmission system from
Borah/Kinport to Hemingway and from Midpoint
500 to Borah/Kinport. This will include 500 kV and
345 kV transmission lines between the following
substations and assets to create a path through each
substation:
Borah, Kinport, Adelaide, Midpoint and Hemingway.
Upgrades are required across the Borah West and
Midpoint West paths to facilitate this portion of the
Contract No. 22TX-17207 B2H Term Sheet
Page 14 of 32
proposed asset exchange transaction. The cost of
these upgrades will be determined in the course of
negotiating the proposed asset exchange transaction
described in this Section 3(a)(5).
Details related to Goshen Area assets:
As described in more detail in Section 3(a)(7) of this
table, PAC will transfer to IPC certain to-be-
determined Goshen areas transmission assets that
would allow IPC to provide transmission service to
all BPA customers in southeast Idaho currently
served by PAC. These assets are being transferred to
IPC, from PAC, as part of the negotiations between
PAC and BPA as described in Section 3(a)(1) of this
table, with the consideration for these assets being
the transmission service provided by BPA to PAC as
detailed in Section 3(a)(1) of this table. IPC and PAC
intend for these Goshen assets to be incorporated into
the broader purchase and sale agreement described in
this Section 3(a)(5) with a goal of minimizing
changes to each company’s transmission rate base.
This goal is intended to be facilitated through the
allocation of the costs associated with the Borah
West and Midpoint West upgrades.
6. IPC & PAC
Amendment to Existing
Agreement:
IPC – PAC Joint
Ownership and
Operating Agreement
(“JOOA”)
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 4 of Calendar
Year 2022
As part of a transaction transferring assets described
in Section 3(a)(5) of this table, IPC and PAC may
expand their existing Joint Ownership and Operating
Agreement, as amended and restated August 22,
2019 (“JOOA”), to include the following:
I. PAC owning 300 MW of west-to-east
transmission assets between Midpoint 500 and
Borah (transferred from IPC); and
II. PAC owning an additional 600 MW of east-to-
west transmission assets between Borah and
Hemingway (transferred from IPC) - total
increases from the current 1,090 MW to 1,690
MW; and
III. IPC owning 200 MW of bi-directional
transmission assets between Populus, Mona and
Four Corners (transferred from PAC); and
IV. Other revisions as necessary to facilitate other
asset exchanges (e.g., for Goshen area, as
Contract No. 22TX-17207 B2H Term Sheet
Page 15 of 32
described in Section 3(a)(5) and Section 3(a)(7)
of this table).
7. IPC & PAC
Goshen Area Asset
Exchange
Part of 3(a)(5)
As referenced in Section 3(a)(5) and Section 3(a)(6)
of this table, IPC and PAC would negotiate an asset
exchange to be effective no later than (i) energization
of the B2H line and (ii) commencement of the
NITSA between BPA and IPC, as referenced in
Section 3(b)(1), that enables BPA to to serve its
loads currently in PAC’s East transmission system
(Lower Valley Elec., Idaho Falls, Fall River Rural
Elec., Lost River Electric, Salmon River Electric,
Soda Springs,) (“Southeast Idaho Load Service
(SILS) Customers”) with one leg of firm IPC
network transmission service.
As referenced in Section 3(a)(6) of this table, the
Goshen area asset exchange may be wrapped into the
existing JOOA framework.
IPC, PAC, and BPA agree to make best efforts to
plan for service to Idaho Falls that requires only one
leg of network transmission from the BPA
transmission system, provided such best efforts
among the Parties must (1) respect and retain the
existing services arranged for Idaho Falls load
service between BPA and Utah Associated Municipal
Power Systems (UAMPS); and (2) be in line with
FERC orders in similar circumstances and accepted
by FERC.
8. IPC & BPA
New Agreement:
Point to Point TSA
Prepare First Draft –
BPA: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
IPC will acquire up to 500 MW of PTP transmission
service from Mid-C to Longhorn subject to the terms
of BPA’s OATT, business practices and applicable
rate schedules. The duration of the new service must
be for an initial service duration of at least 5 years,
and sufficient to compensate BPA for BPA’s revenue
requirement associated with BPA capital investments
to facilitate the transmission service, with the right to
rollover service in accordance with the BPA’s OATT
and business practices in effect at the conclusion of
the initial term.
Contract No. 22TX-17207 B2H Term Sheet
Page 16 of 32
9. IPC & PAC Upon energization of the B2H Project, PAC would
not renew its current 510 MW of east-to-west rights
on the IPC system (which rights are found in IPC 1st
Revised Service Agreement (SA) Nos. SAs 344-346
and 383-384).
Consistent with and pursuant to IPC’s OATT, PAC
and IPC will coordinate to extend any remaining IPC
SAs, enter into new SAs, or take other action as
necessary to bridge any SA expiration dates until
such time as the B2H project is in-service.
10. IPC & PAC
B2H Construction
Funding Agreement-
related Commitments
The B2H Construction Funding Agreement, between
IPC and PAC as referenced in Section 3(d) below,
and any additional agreements as the Parties
determine necessary, will include terms necessary to
implement the Agreement to Reimburse BPA’s
Removal and Replacement Related Transaction
Costs, among IPC, PAC and BPA, dated March 18,
2020 (BPA Contract No. 20TX-16835).
IPC, on behalf of the B2H Project, will assure that it
coordinates construction of the B2H Project with
BPA in a manner consistent with the terms of BPA’s
Use Agreement, as amended by Amendment Two (2)
to NF(R)-9617, including Exhibits A, B and C,
between the United States of America, Dept. of the
Navy and the United States of America, Bonneville
Power Administration Ptn Secs 13, 23 and 24-T2N-
R25E, W.M.
IPC and PAC acknowledge that the Removal and
Replacement Related Transactions described in
Contract No. 20TX-16835 are contingent upon (1)
BPA obtaining acceptable service from Umatilla
Electric so that BPA may continue to serve Columbia
Basin Electric’s load; (2) BPA completing its
obligations and responsibilities under NEPA, NHPA,
or other requisite environmental compliance laws and
making a decision regarding how to proceed; and (3)
IPC and PAC moving forward with construction of
the B2H Project.
11. IPC & PAC & BPA In conjunction with the termination of the NITSAs
identified in Section 3(a)(3)of this table (i.e., PAC
Contract No. 22TX-17207 B2H Term Sheet
Page 17 of 32
BPA Redirect and
Assignment of existing
PTP transmission
service
Incorporate into
Agreement on Principles
and Timelines under
3(a)(1)
SAs 746 & 747), following the energization of B2H,
BPA will redirect its two 100 MW PTP transmission
service agreements (91629850 and 91629500, or any
applicable AREFs that supersede or replace them)
that it takes from IPC (i.e., IPC 1st Revised SAs 324
& 342) such that the new POR of each SA will be
Walla Walla and the new POD for each SA will be
Borah. Consistent with and pursuant to IPC OATT,
following approval of such redirects by IPC as
described above, BPA will assign those redirected
reservations to PAC. This redirect and assignment
will be delayed by BPA if B2H energization is
delayed past 07/01/2026. PAC shall be responsible
to pay for all costs associated with 91629850 and
91629500, or any applicable AREFs that supersede
or replace them, upon approval of such redirect by
IPC and assignment by BPA.
12. IPC & PAC & BPA,
with respect to B2H Plus
Facilities Expectations
IPC & PAC, with
respect to B2H
Construction Funding
Agreement
The B2H Project will include the installation of the
B2H Midline Series Capacitor Project and
development of a remedial action scheme ("RAS").
When considering BPA’s study methodology, the
B2H midline series capacitor reduces simultaneous
interactions between the NW AC Intertie, central and
southern Oregon load service, and WECC Path 14
(Idaho to Northwest). The Parties agree to funding of
the B2H Midline Series Capacitor Project as follows:
a. IPC: funding 45% of the cost.
b. PAC: funding 55% of the cost
c. BPA: funding 0% of the cost
The Parties will work in good faith to have the B2H
Midline Series Capacitor Project in-service when the
B2H Project is energized and to document
expectations of operation, maintenance, and future
reinforcements and upgrades.
13. IPC & PAC
B2H Grant or
Additional Funding
Under IPC and PAC’s existing OATT rate
procedures, IPC and PAC will include any United
States Department of Energy (“DOE”) grant or
additional funding received for the B2H project in
the appropriate FERC account provided such account
is allocated 100% to Transmission. Nothing in this
Term Sheet limits or waives any party’s right to
participate, review, comment, or challenge the other
Contract No. 22TX-17207 B2H Term Sheet
Page 18 of 32
party’s rate case or formula rate inputs through their
respective update processes.
14. IPC & PAC & BPA
Permit Funding
Agreement Amendment
Upon transfer of BPA’s Permitting Interest to IPC
identified in 3(b)(3) below, the Permit Funding
Agreement will be amended to recognize the re-
allocation of the Parties’ Permiting Interests and
related funding obligations.
b) NITSA Terms and Conditions, NITSA Security Agreement, NITSA
Backstop
1. IPC & BPA
New Agreements:
Network Integration
Transmission Service
Agreement to serve BPA
customers at Goshen
Network Integration
Transmission Service
Agreement to service
BPA’s customer at
Burley
Amendment to currently
effective Network
Integration
Transmission Service
Agreements
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
IPC and BPA will enter into two NITSAs for IPC to
provide firm network transmission service to BPA.
One NITSA will serve BPA customers at Goshen
(replacing what is, as of the Effective Date of this
Term Sheet, provided under PAC Service Agreement
746) and one NITSA will serve Idaho Falls (replacing
what is, as of the Effective Date of this Term Sheet,
provided under PAC Service Agreement 747) (“New
NITSAs”). The New NITSAs will be in addition to the
existing NITSAs BPA currently holds with IPC for
service to BPA’s customers located on IPC’s system
(“Existing NITSAs”).
The term of BPA’s New NITSAs will be 20-years
from energization of the B2H Project, with a renewal
or rollover option at BPA’s discretion as required and
permitted by FERC
a. The NITSA Security Agreement (as referenced
in Section 3(b)(2) of this table), and any related
other agreements necessary, between BPA and
IPC will be updated once the energization of
B2H has occurred to document the term and the
repayment periods with the actual energization
date.
b. The New NITSAs, NITSA Security Agreement,
and any related other agreements necessary, are
conditioned on the Goshen Area Asset
Exchange set forth in Section 3(a)(7) being
completed and all associated agreements being
in effect by the energization of the B2H line.
Contract No. 22TX-17207 B2H Term Sheet
Page 19 of 32
Target Execution Date:
Quarter 3 of Calendar
Year 2022 The New NITSAs and the Existing NITSAs will be
updated to include three Points of Receipt (PORs) over
which BPA can deliver energy to its customers located
on IPC’s system. The three PORs are as follows:
AMPS POR, LaGrande POR, and Longhorn POR.
The New NITSAs shall reflect the following
provisions:
a. Under the New NITSAs, IPC will plan for
and reserve transmission capacity for the
continued network service to BPA’s SILS
Customers’loads and ensure that it can
reliably serve the load for the term of the
contract prior to BPA assigning the PTP
service agreements to PAC pursuant to
Section 3(a)(11) above.
b. The New NITSAs between BPA and IPC
will permit BPA to assign service to
specific Points of Delivery (PODs) to
BPA’s wholesale customers who take
service at those PODs. Such assigned
PODs will be served by a separate NITSA
agreement between BPA’s wholesale
customer and IPC. The New NITSA
between BPA and IPC will state that the
customer requesting a separate NITSA for
its POD must meet credit rating standards
consistent with IPC’s OATT.
Notwithstanding assignment of the NITS
service, BPA would remain entitled to all
outstanding credits associated with the
Funded Amounts (as defined in Section
3(b)(2) below) as long as BPA continues to
be a NITS customer.
c.IPC will maintain the current practice of
letting BPA choose through the annual
delivery allocation process the PODs
where BPA will deliver power to serve its
loads. The current PODs include LaGrande
and AMPS. Once B2H is in service, the
PODs will include LaGrande, Longhorn,
and AMPS.
d. BPA would pay the NT rate as established
by IPC’s OATT transmission formula rate.
There shall be no adders or segmentation
Contract No. 22TX-17207 B2H Term Sheet
Page 20 of 32
like actions which result in a rate above the
NT rate and the amount BPA pays to IPC
under the NT service agreement will be
reduced as discussed in the NITSA
Security Agreement.
e.IPC will not charge BPA IPC’s system
losses for energy from BPA’s Palisades
resource used to serve load behind Goshen.
2. IPC & BPA
New Agreement:
NITSA Security and
Risk Backstop
Agreement
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
IPC and BPA will enter into an NITSA security and
risk backstop agreement (“NITSA Security
Agreement”), concurrently with the New NITSA and
the purchase and sale agreement referenced in Section
3(b)(3) of this table.
Reimbursement If IPC Receives all Permits and
Certificates of Public Convenience and Necessity
(CPCN) for Construction of B2H
IPC will reimburse BPA for the transfer of BPA’s
Permitting Interest under the Joint Permitting
Agreement in an amount consisting of BPA’s
investment in B2H prior to the transfer date (~$25m).
BPA will also pay to IPC an additional $10 million
upon execution of the New NITSAs and the NITSA
Security Agreement with the intent of offsetting
overall B2H project costs in IPC’s rate base. The
additional $10 million plus BPA’s investment in B2H
will be collectively referred to as the “Funded
Amount.”
IPC will retain the Funded Amount as follows:
If and when IPC obtains all necessary CPCNs and
permits for the B2H Project (and all appeals, if any,
have been resolved), IPC shall have until January 1,
2026 (“Commencement Date”) to commence
construction of B2H or to inform BPA of its intent
to not pursue construction of B2H.
(1) If IPC commences construction of B2H by or
before the Commencement Date, then:
a. Interest on the Funded Amount (~$35m)
payable by IPC to BPA will accrue from
the date of energization of B2H at the rate
Contract No. 22TX-17207 B2H Term Sheet
Page 21 of 32
established in the applicable IPC tariff for
customer funded projects;
b. The Funded Amount and all accrued
interest will be repaid to BPA starting year
11 following the energization date (the
“Refund Commencement Date”), with
repayment amortized over the remaining
10 years of the New NITSAs.
i. IPC and BPA will incorporate
the interest schedule and
payment amortization as an
exhibit to the NITSA Security
Agreement;
ii. If during the term of the New
NITSAs BPA defaults on its
payment obligations under the
New NITSAs, IPC will be
entitled to retain for its own
account an amount equal to the
defaulted payment obligation not
to exceed the amount not
reimbursed to BPA as of the
default date;
iii. BPA will not be considered in
default for any amount not paid
subject to a billing dispute; and
iv. IPC may prepay the Funded
Amount and interest thereon at
any time without penalty.
(2) If IPC does not commence construction of B2H
by or before the Commencement Date or if IPC
informs BPA before the Commencement Date
of its intent to not proceed with B2H, then:
a.IPC shall have 180 days from the
Commencement Date (or notice to
BPA of its intent to not proceed,
whichever is earlier) to sell its
Permitting Interests in the B2H Project;
b. No later than the close of the above
mentioned 180 days, IPC shall
i.pay to BPA BPA’s proportional
share of any proceeds received
from the sale of its Permitting
Interest in the B2H Project (if
any), and
Contract No. 22TX-17207 B2H Term Sheet
Page 22 of 32
ii. Pay to BPA the $10 million BPA
provided to IPC upon execution
of the New NITSAs.
Risk Backstop if IPC does not Receive all Permits or
CPCNs Necessary for constructing B2H.
If IPC does not obtain all necessary CPCNs and
permits for the B2H Project, or any such CPCNs or
permits are overturned on appeal, then (a) IPC will
return to BPA the $10 million BPA provided to IPC
upon execution of the New NITSAs; and (b) BPA will
reimburse IPC for funding the additional 24.24% share
of all B2H Permitting and Preconstruction Costs
incurred after BPA transfers its 24.24% Permitting
Interest to IPC.
The reimbursement obligation will not include any
costs related to Right of Way option acquisition or
exercising Right of Way Options.
The risk backstop commitment will remain in place
until IPC obtains all necessary CPCNs and permits for
the Project (and all appeals, if any, have been
resolved). The intent of the backstop is only to assist
IPC in mitigating the risk associated with receiving the
approvals for the B2H Project; not to assist in
mitigating business risk.
The risk backstop commitment will be as follows:
a. IPC will not compensate or reimburse
BPA for costs expended by BPA on B2H
prior to the transfer of the Permitting
Interest to IPC (i.e., ~$25m BPA has
expended to date);
b. BPA will reimburse 24.24% of actual
B2H Project Permitting Costs incurred
after IPC takes over funding 45% of the
project. (Current estimates for 2021-2024
– Total B2H Project estimated at
$9,125,466 with 24.24% of these costs
estimated at $2,212,234); and
c. BPA will reimburse 24.24% of actual
B2H Project Pre-Construction Costs
incurred after IPC assumes funding 45%
of the project. (Current estimates for
Contract No. 22TX-17207 B2H Term Sheet
Page 23 of 32
2021-2024 – Total B2H Project estimated
at $9,403,564 with 24.24% of these costs
estimated at $2,279,652).
Collectively, these amounts set forth in a. through c.
above will be the “Risk Backstop Amount.”
The Risk Backstop Amount will be adjusted, as
necessary, to the extent that IPC receives grants or
forms of other financial assistance from sources other
than BPA or PAC. For example, if IPC received a
government grant that defrayed the pre-construction
costs of B2H, BPA’s 24.24 % share of the pre-
construction costs would be reduced accordingly.
3. Transfer of Interest in
Joint Permitting
Agreement:
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
IPC and BPA will execute a purchase and sale
agreement, assignment, and other applicable transfer
documents, concurrently with the New NITSAs,
NITSA Security Agreement, and any related other
agreements necessary, to transfer all of BPA’s
Permitting Interest under the Joint Permitting
Agreement (and all of BPA’s interest in the assets
associated therewith) to IPC in exchange for IPC’s
agreement for repayment to BPA of BPA’s investment
in B2H through the Joint Permitting Agreement
through the effective date of the definitive purchase
and sale agreement contemplated in this Section 3(b)
(or other date specified therein). The proposed
purchase and sale agreement contemplated in this
Section 3(b)(3) will contain representations,
warranties, and covenants typical of a transaction of
the nature contemplated by these proposed terms. The
definitive agreements transferring BPA’s Permitting
Interest under the Joint Permitting Agreement and
related assets will be executed prior to any activities
BPA has indicated could impact federal environmental
regulatory requirements under NEPA, so as to prevent
additional delay in the development of B2H.
Following the transfer of BPA’s Permitting Interest
(and associated assets) under the Joint Permitting
Agreement to IPC, IPC will be solely responsible for
funding an additional 24.24% share of all B2H Project
Costs thereafter under Joint Permitting Agreement
Contract No. 22TX-17207 B2H Term Sheet
Page 24 of 32
(which includes permitting and preconstruction costs),
and IPC will be entitled to all rights, title, and interests
and assets that BPA would otherwise obtain under the
Joint Permitting Agreement if it were a remaining
funding party thereto.
c) Ownership, Operation, and Maintenance Agreement: Defines IPC’s and
PAC’s capacity and property ownership, and their roles and responsibilities for operating
and maintaining the B2H Project (“Ownership and Operation Agreement”). IPC will
prepare an initial draft of the Ownership and Operation Agreement based on the ownership
interests below and otherwise consistent with the terms of the JOOA between IPC and
PAC. Alternatively, in lieu of a new agreement, IPC and PAC may decide to amend the
existing JOOA to cover the B2H Project assets.
Idaho Power PacifiCorp BPA
Project ownership: 45.45% Project ownership: 54.55% Project ownership: 0%
d) Construction Funding Agreement: Defines IPC’s and PAC’s roles and
responsibilities in construction of the B2H Project (“Construction Funding Agreement”).
IPC will prepare an initial draft of the Construction Funding Agreement consistent with
the following terms:
1. Project In-Service Date June 1, 2026
2. Scope The Construction Funding Agreement covers all work
necessary to construct the B2H Project by the Project
In-Service Date, including any associated residual
work after the Project In-Service Date, but excluding
any work already covered by the Joint Permitting
Agreement.
3. Project Delivery System A competitive process is being completed to hire a
Construction Manager / Constructability Consultant
(“CM”) for the B2H Project in 2022 to: (1) provide
constructability feedback to the design engineer; and
(2) collaborate with PAC and IPC to complete the
BLM Construction Plan of Development and the
Oregon Energy Facility Siting Council’s Site
Certificate amendments. The hiring process of the CM
will be structured such that the CM may be retained to
construct the B2H Project.
Contract No. 22TX-17207 B2H Term Sheet
Page 25 of 32
IPC and PAC may mutually agree to modify the CM’s
role through the Construction Funding Committee (as
defined in Section 10 below -Project Funding and
Committee) without amending the Construction
Funding Agreement.
4. Project Manager IPC is the overall Project Manager for all B2H Project
permitting, design, procurement, construction, except
that BPA will be responsible for designing, procuring,
and constructing the Longhorn substation as described
in Section 3(a)(4)and relocating and replacing the
BPA 69 kV line off Navy property as described in
Section 3(a)(10).
Although IPC is the Project Manager, PAC is not
precluded from taking project management
responsibilities for all or selected tasks associated with
the B2H Project; provided that these delegations must
be made by the Construction Funding Committee.
5. Construction Project
Manager
IPC’s role as Construction Project Manager will be
generally consistent with the roles and responsibilities
of the Permitting Project Manager set forth in Article
IV of the Joint Permitting Agreement, provided that
the permitting responsibilities not relevant to
construction will be removed.
IPC, as the Construction Project Manager, will provide
monthly project updates, including updates on project
activities, financials, forecasts, and invoices detailing
costs incurred with breakdowns demonstrating all
Parties’ cost responsibilities based on their percentage
shares.
To provide the necessary flexibility to avoid
delay/additional costs, the Construction Project
Manager will administer and oversee all work
necessary to construct the B2H Project within the
approved budget, schedule and scope, and also have
authority to approve any non-material changes to the
B2H Project resulting in a price difference of less than
$500k, so long as the overall B2H Project costs remain
within the approved budget with the price change. All
changes to the B2H Project resulting in a change in the
approved budget, will require approval of the
Construction Funding Committee.
Contract No. 22TX-17207 B2H Term Sheet
Page 26 of 32
6. Component Specifications All B2H Project construction specifications shall meet
or exceed all applicable state and federal design
requirements and standards; provided that, such
specifications may be modified by the Construction
Funding Committee so long as the project complies
with all applicable state and federal design
requirements and standards.
7. Real Property Ownership B2H real property, except Longhorn substation: IPC
will acquire rights of way, grants, easements, or other
interests in real property necessary to construct,
operate and maintain the B2H transmission line and
grant to PAC perpetual and sufficient rights of access,
to be set forth in the Ownership and Operation
Agreement.
Longhorn Substation: Upon completion of BPA’s
obligations and responsibilities under NEPA, NHPA,
and other requisite environmental compliance laws
and if BPA decides to proceed with construction of
Longhorn substation, BPA will continue to own all
real property associated with the Longhorn substation,
and in relation to the B2H Project equipment BPA
shall grant to IPC and PAC perpetual and sufficient
rights of access, to be set forth in one or more
Longhorn Substation Agreements as described in
Section 3(a)(4).
8. Equipment and Facilities
Ownership
Equipment and facilities ownership will be consistent
with the Ownership and Operation Agreement.
B2H equipment/facilities, except Longhorn
substation: IPC and PAC will jointly own as tenants
in common the transmission line and all associated
facilities and equipment, including all associated
facilities located in Hemingway Substation as well as
supporting communication facilities and B2H Project
substation equipment.
Longhorn Substation: Upon completion of BPA’s
obligations and responsibilities under NEPA, NHPA,
and other requisite environmental compliance laws
and if BPA decides to proceed with construction of
Longhorn substation, BPA will own all equipment and
facilities in the Longhorn substation, except the B2H
specific equipment and facilities which will be jointly
owned by IPC and PAC as tenants in common. BPA
will grant IPC and PAC access rights to the equipment
Contract No. 22TX-17207 B2H Term Sheet
Page 27 of 32
and facilities in Longhorn substation that are
constructed as part of and necessary to the operation of
the B2H transmission line facilities, to be set forth in
one or more Longhorn Substation Agreements as
described in Section 3(a)(4).
9. Material Procurement All material specifications shall be in accordance with
IPC’s procurement policies and standards, unless
otherwise agreed by the Construction Funding
Committee to exceed the same.
10.Project Funding and
Committee
Funding: IPC and PAC will fund the B2H Project
consistent with their respective ownership shares.
Construction Funding Committee: The Construction
Funding Agreement shall create a Construction
Funding Committee consistent with IPC and PAC’s
ownership interests in the B2H Project, and generally
consistent with the Permit Funding Committee created
by the Joint Permitting Agreement (Article III).
The Project Manager’s reporting requirements set
forth in the above Section 5 (Construction Project
Manager)will be delivered to all members of the
Construction Funding Committee prior to, and
discussed during, each of the Committee’s regularly-
scheduled monthly meetings.
Obligations, disputed amounts, and audit rights will be
generally consistent with Article III of the Joint
Permitting Agreement.
The Project Manager will have flexibility to make day-
to-day decisions associated with construction of the
Project but will be required to seek resolution/approval
from the Construction Funding Committee on larger
dollar/impact decisions, consistent with that set forth
in the above Section 5 (Construction Project
Manager).
BPA will be responsible for designing, procuring, and
constructing the Longhorn substation as described in
Section 3(a)(4) and relocating and replacing the BPA
69 kV line off Navy property, as described in Section
3(a)(10).
11.Payment Schedule Costs Accrued Prior to Agreement Execution: Prior to
executing the Construction Funding Agreement, IPC
Contract No. 22TX-17207 B2H Term Sheet
Page 28 of 32
and PAC will have the opportunity to audit all accrued
construction-related expenses included therein that
have not otherwise been funded under the Joint
Permitting Agreement. IPC and PAC will align on
ownership shares prior to execution of the
Construction Funding Agreement and pay their
respective portions of accrued expenses within 30 days
of the effective date of the Construction Funding
Agreement. Until which time BPA fully divests its
ownership interest in the B2H Project, the Parties
acknowledge that the B2H Project is bound to
compliance with NEPA, NHPA, and other
environmental laws associated with federal agency
action.
Costs Incurred After Execution: Following execution
of the Construction Funding Agreement, the Project
Manager will invoice the Construction Funding
Agreement participants monthly, requiring payment
within 30 days of the invoice date.
12.Transfer/Assignment of
Rights/Interests (Some or
all of these terms may be
instead placed in the
Ownership Agreement)
IPC and PAC may sell some or all of their respective
ownership interests in the B2H Project, together with
associated capacity, subject to the Construction
Funding Committee’s agreement and approval of the
terms of any such transaction;provided that, such
approval will not be unreasonably withheld.
IPC will not transfer or assign rights or interests in the
B2H Project that would materially impact the BPA
load service commitments set forth in Section 3(b) of
this Term Sheet.
13.Term
Early Termination
Withdrawal
Term: The term of the Construction Funding
Agreement will extend through completion of B2H
Project construction, as well as final billing and any
reconciliation or mitigation associated with the final
expenses, unless otherwise agreed by the Construction
Funding Committee.
Early Termination/Withdrawal:Absent approval of
the Construction Funding Committee, no Party shall
have a right to withdraw from the Construction
Funding Agreement following the earlier of (1)
awarding the B2H Project construction contract, or (2)
commencing procurement of long-lead items and
equipment.
Contract No. 22TX-17207 B2H Term Sheet
Page 29 of 32
Assignments of IPC’s or PAC’s rights and obligations
under the Construction Funding Agreement shall be
managed pursuant to the above Section 12
(Transfer/Assignment of Rights/Interests).
14.Event of Default Generally consistent with Article VIII of the Joint
Permitting Agreement.
15.Force Majeure Generally consistent with Article IX of the Joint
Permitting Agreement.
16.Reps and Warranties Generally consistent with Article X of the Joint
Permitting Agreement.
17.Common Defense &
Limitation of Liability
Generally consistent with Article XI of the Joint
Permitting Agreement, except that the Article will be
expanded to address construction claims.
18.Proprietary
Information/Confidentiality
Generally consistent with Article XII of the Joint
Permitting Agreement, except that the Article will
provide IPC the ability to share information as
necessary to work with potential and selected
engineers and contractors.
19.Dispute Resolution Generally consistent with Article XIII of the Joint
Permitting Agreement.
20.Miscellaneous Generally consistent with Article XIV of the Joint
Permitting Agreement and including any standard
terms that are necessary for PAC agreements (e.g.
assignment and jury trial waiver provisions).
4. Additional Agreements.The Parties agree that they may consolidate any or all of
the above-described Agreements and are not precluded from pursuing additional
agreements, or amending existing agreements as needed, related to the B2H Project besides
those discussed herein.
5. Expenses.Each Party will bear its own expenses (including attorneys’ fees)
incurred in connection with preparation, negotiation, and execution of this Term Sheet,
including preparation, negotiation and execution of the Agreements described herein.
ACKNOWLEDGED AND AGREED TO BY THE PARTIES:
IDAHO POWER COj NY
Signature:
Printed Name:
Title:
Date:
w4,/t 4-604444-4-)
11542_
Contract No. 22TX-17207 B2H Term Sheet
Page 30 of 32
Contract No. 22TX-17207 B2H Term Sheet
Page 31 of 32
PACIFICORP
Signature: _________________________________
Printed Name: Rick Link
Title: Senior Vice President, Resource Planning, Procurement and Optimization
Date: _________________________________
Signature: _________________________________
Printed Name: Rick Vail
Title: Vice President, Transmission
Date: _________________________________
Contract No. 22TX-17207 B2H Term Sheet
Page 32 of 32
BONNEVILLE POWER ADMINISTRATION
Signature: _________________________________
Printed Name: _________________________________
Title: _________________________________
Date: _________________________________
Signature: _________________________________
Printed Name: _________________________________
Title: _________________________________
Date: _________________________________
Tina Ko
Vice President, Transmission Marketing and
1/18/2022
Kim Thompson
Vice President, Requirements Marketing
1/18/2022

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-01

IDAHO POWER COMPANY

CONFIDENTIAL

ELLSWORTH
TESTIMONY

EXHIBIT NO. 2

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-01

IDAHO POWER COMPANY

ELLSWORTH
TESTIMONY

EXHIBIT NO. 3
1
From:Tech Forum <[e-mail]>
Sent:Thursday, January 5, 2023 3:39 PM
To:Tech Forum
Subject:[EXTERNAL]BPA Southeast Idaho Loads and B2H Transfer Service Workshop
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
Bonneville Power Administration
__________________________________________________________ _ ___
Requested Action: Information Only
_________________________________________________________________________
Subject Description:
In a Letter to the Region dated January 18, 2022 (“2022 Letter”), BPA announced its signature of a
non-binding term sheet (“Term Sheet”) that clarified and updated BPA’s role in Idaho Power and
PacifiCorp’s potential future construction of their new transmission line from Boardman, Oregon to
Hemingway, Idaho (the “Boardman to Hemingway Project” or “B2H”).
The term sheet developed a plan referred to as “B2H with Transfer Service”, and would allow BPA
to reliably and cost-effectively meet firm power service obligations to southeast Idaho customers
by acquiring transmission service on B2H rather than becoming a part owner in the line as
previously considered. The 2022 Letter and the Term Sheet are available on BPA’s Southeast Idaho
Load Service (SILS) webpage.
It was also noted that Idaho Power, PacifiCorp, and BPA intended to negotiate binding contracts to
effectuate the B2H with Transfer Service plan of service. As those negotiations near conclusion,
BPA is providing customers and stakeholders with advance notice of the following public
engagement schedule which will include a formal comment period for stakeholders:
•Monday, Jan. 9: BPA will release a Letter to the Region, describing the contracts
associated with B2H with Transfer Service that BPA is proposing to execute.
•Monday, Jan. 9: BPA will make an online comment page available at
https://publiccomments.bpa.gov for B2H with Transfer Service comments.
•Monday, Jan. 23: from 1-3 p.m., BPA will hold a public workshop to discuss the
binding contracts and BPA’s business case, as well as provide Q&A opportunities.
•Thursday, Feb. 9: BPA will close the public comment period and begin preparing
responses.
BPA will present information at the Jan. 23 workshop (details below) intended to help interested
parties prepare public comments on the proposal to execute the binding contracts. Materials for the
Jan. 23 meeting will be available on BPA’s SILS webpage prior to the workshop.
BPA will be accepting public comments at https://publiccomments.bpa.gov until Thursday, Feb. 9,
2023.
________________________________________________________________________
Meeting Details:
When: Jan. 23, 2023
Time: 1 p.m. to 3 p.m.
Where: Webex join the meeting
2
Phone Bridge: 415-527-5035
Meeting Number (access code): 2763 013 9005
_____________________________________________________________________ __
For the most up-to-date calendar of events, please visit the BPA Event Calendar.
To submit comments and questions or unsubscribe, email to [e-mail]. Click here to subscribe. 

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-01

IDAHO POWER COMPANY

ELLSWORTH
TESTIMONY

EXHIBIT NO. 4
Idaho Power’s Existing Voltage Transmission System 

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-01

IDAHO POWER COMPANY

ELLSWORTH
TESTIMONY

EXHIBIT No. 5
Boardman to Hemingway Project 

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-01

IDAHO POWER COMPANY

ELLSWORTH
TESTIMONY

EXHIBIT NO. 6

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-01

IDAHO POWER COMPANY

ELLSWORTH
TESTIMONY

EXHIBIT NO. 7

2021 IRP: Branching Evaluation