20230124Ellsworth Direct.DOCX

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-23-01IDAHO POWER COMPANYDIRECT TESTIMONYOFJARED L. ELLSWORTHQ.Please state your name, business address, and present position with Idaho Power Company (“Idaho Power” or “Company”).A.My name is Jared L. Ellsworthand my business address is 1221 West Idaho Street, Boise, Idaho 83702. I am employed by Idaho Power as the Transmission, Distribution & Resource Planning Director for the Planning, Engineering & Construction Department.Q.Please describe your educational background.A.I graduated in 2004 and 2010 from the University of Idaho in Moscow, Idaho, receiving a Bachelor of Science Degree and Master of Engineering Degree in Electrical Engineering, respectively. I am a licensed professional engineer in the State of Idaho.Q.Please describe your work experience with Idaho Power.A.In 2004, I was hired as a Distribution Planning engineer in the Company’s Delivery Planning department. In 2007, I moved into the System Planning department, where my principal responsibilities included planning for bulk high-voltage transmission and substation projects, generation interconnection projects, and North American Electric Reliability Corporation’s (“NERC”) reliability compliance standards. I transitioned into the Transmission Policy & Development group with a similar role, and in 2013, I spent a year cross-training with the Company’s Load Serving Operations group. In 2014, I was promoted to Engineering Leader of the Transmission Policy & Development department and assumed leadership of the System Planning group in 2018. In early 2020, I was promoted into my current role as the Transmission, Distribution and Resource Planning Director. I am currently responsible for the planning of the Company’s wires and resources to continue to provide customers with cost-effective and reliable electrical service.Q.What is the purpose of your testimony in this case?A.The purpose of my testimony is to present the need and justification for the Boardman to Hemingway transmission line (“B2H”).The following is a summary of the items I will discuss at length in my testimony: •As the B2H project entered into the permitting and pre-construction phase, project participants Idaho Power, PacifiCorp, and Bonneville Power Administration (“BPA”), executed a non-binding term sheet (“Term Sheet”) that addresses B2H ownership, transmission service considerations, and asset exchanges. The Term Sheet provides that Idaho Power will acquire a 45.45 percent ownership share of B2H – which reflect an increase of 24.24 percent over the ownership share previously anticipated in the Permit Funding Agreement. This increase results from Idaho Power’s acquisition of BPA’s 24.24 percent ownership share initially reflected in the Permit Funding Agreement. The Term Sheet reflects that, instead of an ownership interest, BPA will commit to acquiring B2H capacity from Idaho Power through transmission service agreements. The agreements necessary to facilitate Idaho Power’s increased ownership share in the B2H project are completed and ready for execution.The Company and PacifiCorp will execute a Construction Funding Agreement that will cover all work necessary to construct the B2H project.•First identified in the 2006 Integrated Resource Plan (“IRP”), the B2H project has proven to be a cost-effective resource through successive IRPs. The B2H project was identified as part of the preferred resource portfolio in Idaho Power’s 2009, 2011, 2013, 2015, 2017, 2019 and most recently in the 2021 IRP. •The results of the 2021 IRP preferred portfolio indicate the Base with B2H portfolio minimizes both cost and risk, and when compared to the lowest cost non-B2H portfolio, the cost difference definitively shows that the B2H project is a necessary component of the Company’s preferred portfolio, assuming comparable risk performance to other portfolios.•The transmission assumption used in the modeling of the 2021 IRP includes B2H project costs assuming Idaho Power’s 45.45 percent ownership share, which are offset by transmission wheeling revenue benefits associated with B2H.•Aside from being the least-cost preferred portfolio, the B2H project will provide: (1) improved economic efficiency and renewable integration, (2) grid reliability/resiliency, (3) resource reliability, (4) contingency reserves and reduced electrical losses, and (5) capacity to the Four Corners market hub.•Idaho Power evaluated B2H project capacity risk, cost risk, and in-service date risk extensively.Q.Have you prepared any Exhibits?A.Yes. Exhibit No. 1 is the Term Sheet between Idaho Power, PacifiCorp, and BPA that addresses B2H ownership, transmission service considerations, and asset exchanges.Exhibit No. 2 details the construction, ownership, operation, asset exchanges and service agreements necessary for the Boardman to Hemingway Project. Exhibit No. 3 is BPA’s Tech Forum notice dated January 5, 2023, announcing their completion of B2H project negotiations. Exhibit No. 4presents Idaho Power’s transmission system. Exhibit No. 5 shows a map of the region with the B2H project substation termination points. Exhibit No. 6 is the B2H Phase 2 Study Report – Western Electricity Coordinating Council (“WECC”) Rating Process. Exhibit No. 7details the initial branching scenario analysis performed as part of the 2021 IRP. I. THE B2H PROJECT PARTICIPANTSQ.What entities have participated in funding the permitting of the B2H project?A.Idaho Power, PacifiCorp, and BPA are parties to the Permit Funding Agreement, initially executed January 12, 2012, and amended several times (“Permit Funding Agreement”), to jointly support the regulatory processes associated with obtaining necessary permits and other work to develop the B2H project (“Parties”). Collectively, the Parties represent a very large electric service footprint in the western United States and have all recognized the regional significance of the B2H project. Q.What are the key provisions of the existing Permit Funding Agreement?A.The Permit Funding Agreement is intended to align the Parties’ cost responsibility for funding with their assigned B2H capacity allocations. Those allocations include a seasonal capacity arrangement between Idaho Power and BPA – which is a benefit for Idaho Power’s customers. Specifically, the agreement provides that Idaho Power’s west-to-east share of B2H capacity is 500 MW in the summer season (April-September), and 200 MW in the winter (January-March and October-November) to serve its customers, whereas BPA’s west-to-east share is 250 MW in the summer and 550 MW in the winter. Idaho Power and BPA’s share of the B2H project make up 750 MW of west-to-east capacity. This seasonal capacity arrangement affords Idaho Power 500 MW of summer season capacity at a cost equivalent to 350 MW, a significant cost-reduction benefit that I will discuss later in my testimony. The synergies between BPA’s capacity needs (winter focused) and Idaho Power’s capacity needs (summer focused) will lead to high utilization of the B2H project’s increased capacity. Finally, the Permit Funding Agreement includes a buyout option, stating that once the B2H project received a Record-of-Decision from the Bureau of Land Management, any party can trigger the Construction Negotiation Phase, and move forward with executing definitive construction funding agreements. If one party chooses not to move forward, the other parties that wish to move forward are required to buy that party out, with the exiting party receiving full compensation for its permitting costs. Q.What was BPA’s interest in the B2H project at the time the Permit Funding Agreement was initially executed?A.BPA has a load service obligation for its customers spread across southeast Idaho including Lost River Electric, Fall River, Salmon River Electric Cooperative, City of Idaho Falls, City of Soda Springs, and Lower Valley Electric. Starting back in the 1970s, Idaho Power worked with BPA to explore the construction of a 500-kV line from the Pacific Northwest to the Idaho Power area, which would have provided BPA a connection across southern Idaho for BPA to serve its customers (including its south Idaho customers BPA currently serves via Idaho Power transmission). This contemplated line was essentially what B2H is today but was never constructed. Rather than build the line, BPA and PacifiCorp executed a power exchange agreement whereby BPA would deliver power to PacifiCorp customers in the Oregon area, and in exchange, PacifiCorp would deliver power to BPA customers in southeast Idaho. PacifiCorp terminated this agreement, with five-years notice, in 2011. Since 2016, BPA has served its southeast load via combinations of firm transmission across PacifiCorp, conditional firm transmission across Idaho Power, and southern power market purchases. As a result of these events, BPA desired a direct transmission connection, with no transmission wheel, or a single transmission wheel, between the Federal Columbia River Power System and its customers. Q.What interest in B2H did the Permit Funding Agreement originally anticipate for BPA?A.Under the Permit Funding Agreement, BPA has a 24.24 percent ownership share. As discussed in more detail later in my testimony, Idaho Power is now planning to acquire BPA’s 24.24 percent ownership share of the permit funding. Q.What was PacifiCorp’s interest in the project at the time the Permit Funding Agreement was initially executed?A.Around the time Idaho Power began permitting the B2H project, the Company and PacifiCorp also began to jointly permit the Gateway West project. Gateway West extends between Hemingway, as the western terminus, and east-central Wyoming, as the eastern terminus. To complement Gateway West and connect its western Balancing Area (PACW) and eastern Balancing Area (PACE) together, PacifiCorp required an additional segment between the Pacific Northwest and Hemingway. The B2H project would provide strategic value to PacifiCorp connecting the two regions, providing bidirectional capacity to increase reliability and enable more efficient use of resources. Under the Permit Funding Agreement, PacifiCorp has a 54.55 percent ownership share.Q.What other related negotiations did the Parties pursue when executing the Permit Funding Agreement?A.Coincident with the development of the Permit Funding Agreement, the Parties also executed a Memorandum of Understanding, which detailed high-level parameters of different asset exchanges between Idaho Power, BPA, and PacifiCorp. The asset exchanges, as they are envisioned today, will be discussed later in my testimony.Q.Have the Parties made progress on final definitive agreements toward project ownership and participation?A.Yes. Via a revised Permit Funding Agreement, the B2H project is currently in the permitting and pre-construction phase. In addition, on January 18, 2022, and after significant discussions, study efforts, and negotiations, the Parties executed the Term Sheet, included as Exhibit No. 1, that addresses B2H ownership, transmission service considerations, and asset exchanges. The Parties entered into the Term Sheet after over two years of discussions related to next steps associated with the B2H project. Q.Does the Term Sheet reflect any changes to the ownership arrangements that had been contemplated in the Permit Funding Agreement?A.Yes. A decade has passed since the Parties signed the Permit Funding Agreement and the Parties’ capacity needs, strategies, and goals associated with the B2H project have evolved. As a result, the Parties negotiated the Term Sheet as the framework for future agreements required between and among the Parties as the B2H project moved towards pre-construction. As envisioned under the Term Sheet, BPA will transition out of its role as a joint permit funding coparticipant and will instead rely on the B2H project by taking transmission service from Idaho Power to serve its customers. To accommodate this change, Idaho Power will increase its B2H project ownership share from 21.21 percent to 45.45 percent by acquiring BPA’s B2H project capacity. Idaho Power’s Increased B2H Ownership ShareQ.Does the approach agreed to in the Term Sheet maintain the benefits to Idaho Power and its customers of the initially contemplated ownership arrangements?A.Yes. I will discuss the B2H project’s cost effectiveness later in my testimony. In terms of the arrangement with BPA, as previously discussed, BPA and Idaho Power identified synergies associated with each party’s B2H capacity needs. BPA needed more winter capacity between the Pacific Northwest and Idaho, and Idaho Power needed more summer capacity. BPA and Idaho Power negotiated the sum of their capacities to fit together like puzzle pieces with total capacity equal to 750 MW. BPA’s capacity included 400 aMW (250 MW summer / 550 MW winter) and Idaho Power’s capacity included 350 aMW (500 MW summer / 200 MW winter). The new arrangement, whereby BPA purchases transmission service on B2H for the capacity that it had formerly planned to acquire through ownership, maintains the benefits of the B2H project for each party and their customers. Q.What is the resulting capacity interest following execution of the Term Sheet?A.Idaho Power’s B2H project capacity will increase to 750 MW west-to-east, of which the Company plans to utilize 500 MW in the summer months (April–September) and 200 MW in the winter months (January–March and October–December) for Idaho Power retail customer service, and the remainder will primarily be used to provide BPA network transmission service under Idaho Power’s Open Access Transmission Tariff (“OATT”) across B2H and southern Idaho. PacifiCorp’s B2H ownership interest is not impacted by BPA transitioning out of ownership of the project and their B2H capacity will remain at 300 MW west-to-east and 600 MW east-to-west. There remains 400 MW of unallocated B2H east-to-west capacity, of which 182 MW is expected to be allocated to Idaho Power and 218 MW allocated to PacifiCorp, based on their respective ownership share.Q.Have the agreements envisioned in the Term Sheet with respect to the Company assumption of BPA’s 24.24 percent ownership share of the B2H project come to fruition?A.Yes. In January2023, the Parties reached a major project milestone, concluding negotiations on final agreements thatmemorialize and effectuate the change in ownership. There are five different agreements specific to Idaho Power and necessary to reflect adjustments to the funding and ownership percentages envisioned in the Term Sheet, all of which are nearly finalized and will be ready for execution. They consist of the: (1) Second Amended and Restated B2H Transmission Project Joint Permit Funding Agreement, (2) Network Integration Transmission Service Agreement (“NITSA”) for Goshen Load, (3) NITSA for Idaho Falls Load, (4) Purchase, Sale, and Security Agreement, and (5) point-to-point (“PTP”) transmission service agreements. These are summarized in Exhibit No. 2 to my testimony and identified as Agreements 1, 2, 3, 4, and 11.Q.When will the agreements be executed?A.The parties will execute the agreements following BPA’s public process, which is a standard administrative decision-making process applicable to all federal agencies and typically concludes within three months of BPA’s notice to the region.Q.Has BPA begun the public process for their proposed new role in the B2H project?A.Yes. On January 5, 2023, BPA provided public notice via their Tech Forum platform to customers and stakeholders announcing their completion of B2H project negotiations and releasing the customer engagement schedule, identifying dates for the comment period, customer workshop, and an expected final decision in March 2023. BPAreleaseditsLetter to the Region formally opening the comment period on January 9, 2023, providing their customers and stakeholders information about the agreements and notified them of a BPA-hosted workshop on January 23, 2023, to answer questions about the agreements. In addition, BPA explained customers and stakeholders have the opportunity to comment through February 10, 2023, prior to BPA proceeding with execution of the binding contracts for the B2H project. BPA’s public process is expected to conclude in March 2023 with the issuance of a letter to the region describing its reasoning behind its decision and responding to comments.A copy of the Tech Forum notice is included as Exhibit No. 3 to my testimony.Q.What is required of Idaho Power contractually once BPA’s ownership share is assumed?A.As I described earlier, BPA’s transition out of its role as a joint permit funding coparticipant will requirethe Second Amended and Restated B2H Joint Permit Funding Agreement, identified as Agreement 1 on Exhibit No. 2. As contemplated in the Term Sheet, funding and ownership percentages will be adjusted such that the Company will acquire BPA’s permitting interest and funding of 45.45 percent of the B2H project costs while providing transmission service across southern Idaho to BPA’s customers through NITSA’s under Idaho Power’s OATT, identified as Agreements 2 and 3 in Exhibit No. 2. In addition, the Company will reimburse BPA over time for the value of the permitting costs paid by BPA.Q.Will payments received from BPA under the NITSAs reimburse the Company for its increased share of the B2H project?A.Yes. Based on the yearly load estimates provided by BPA and the resulting forecasted transmission service payments to Idaho Power under the full term of the NITSAs are projected to offset the Company’s costs associated with its increased share of the B2H project to support BPA’s usage, and, therefore, Idaho Power’s customers will not be harmed by the changes to the arrangement. In addition, as an added protection for customers, BPA has agreed to a security and risk backstop payment in conjunction with the purchase and sale provisions associated with the Company’s assumption of BPA’s ownership share of the B2H project (“Purchase, Sale, and Security Agreement”). The Purchase, Sale, and Security Agreement is included as Agreement 4 to Exhibit No. 2.Under the Purchase, Sale, and Security Agreement, Idaho Power will hold, as a security payment, an amount equivalent to BPA’s investment in the B2H project prior to the transfer of permitting interest to Idaho Power, or the approximately $25 million BPA has paid towards permitting costs to date (“Transferred Permitting Interest”). BPA will also pay Idaho Power an additional $10 million (“Seller’s Security”), for a total security deposit of $35 million. The Seller’s Security will provide assurances that Idaho Power’s retail customers are insulated from risk associated with the Company purchasing BPA’s share of the Transferred Permitting Interest.Upon energization of B2H, interest will accrue on both the Transferred Permitting Interest and the Seller’s Security at a rate of 3.25 percent. Because the revenue associated with BPA’s usage of B2H in the early years of the agreement will be less than the associated annual revenue requirement, the unreturned portion of the $35 million should mitigate any potential default risk until BPA has fully paid for its share of B2H costs over time.Q.Please explain why BPA’s payments under the NITSAs will not immediately offset the Company’s costs associated with BPA’s usage of the B2H project. A.The rate for which BPA will be charged under the NITSAs is based on the network transmission service rates under Attachment H of Idaho Power’s OATT. Rates for transmission service are updated in October of each year, based on the previous calendar year’s actual financial data. Because of the regulatory lag that exists between when transmission costs are incurred and when transmission rates are updated, under recovery of revenue requirement amounts associated with the network transmission service provided to BPA will occur in the first few years the NITSAs are in effect. Once all agreements with BPA have been executed, and prior to energization of the B2H project, the Company will request authorization from the Commission for accounting treatment that will ensure the Company’s retail customers are not harmed by the arrangement and until such time as cumulative network transmission service revenues received from BPA exceed BPA’s cumulative share of the B2H revenue requirement.Q.Will the Company be responsible for repaying the Transferred Permitting Interest and Seller’s Security to BPA?A.Yes. Repayment of the Seller’s Security and all accrued interest related to the Seller’s Security will occur within 60 days following energization of B2H. The repayment of the Transferred Permitting Interest plus all related accrued interest will occur starting year eleven following energization of B2H if BPA’s total load under the Goshen and Idaho Falls NITSA’s for any rolling twelve-month basis averages 400 MW or more prior to the tenth anniversary of energization (“Repayment Event”). Or, in the alternative, if the total load for any rolling twelve-month basis averages 400 MW or more after the tenth anniversary of B2H energization, then the Repayment Event will commence on the next anniversary date of B2H energization. Q.Are there any additional terms agreed to between Idaho Power and BPA?A.Yes. The Term Sheet identified other related transactions between the Company and BPA, two were associated with necessary transmission service agreements and one related to substation funding. With respect to the transmission service agreements, first, Idaho Power will secure 500 MW of PTP transmission service from BPA from the Mid-Columbia (Mid-C) hub to the proposed Longhorn substation, which will provide the Company a direct connection to the Mid-C market with flexible long-term BPA wheeling rights. Second, as identified in the Term Sheet and as a component of Agreement 11 in Exhibit No. 2, BPA will redirect its two 100 MW PTP transmission service agreements that it takes from the Company, assigning them to PacifiCorp, a necessary redirect following termination of BPA’s existing NITSA with PacifiCorp.Q. Please describe the agreement required for substation funding.A.The Parties have also agreed to terms specific to funding of the Longhorn substation, which BPA will own and operate, and where the B2H project interconnects. The Longhorn Substation Funding Agreement, identified as Agreement 8 in Exhibit No. 2, was not required in advance of BPA’s public process and has not yet been finalized. However, provisions of the agreement were identified in the Joint Purchase and Sale Agreement (“JPSA”) that I will discuss later in my testimony. As a condition precedent to closing of the JPSA, Idaho Power and PacifiCorp must have finalized the agreement between the Parties for funding of a portion of the assets at, and directly adjacent to, the Longhorn substation where B2H will connect. The Longhorn Substation Funding Agreement will also describe the use of a facilities charge, or other similar charge, pursuant to BPA’s OATT, that will be paid by the Company and PacifiCorp allowing for each party to transact across the Longhorn bus in the future. It will detail the ownership, operation and maintenance of the B2H equipment by Idaho Power and PacifiCorp, including (1) a B2H project-related series capacitor at the substation, (2) the B2H project shunt line reactors, and (3) any ancillary equipment required to support the B2H project series capacitor and shunt line reactors.Q.Are there any other agreements you have not yet discussed necessary for facilitating Idaho Power’s increased ownership arrangement with BPA?A.No.New Partnership Agreements Necessary for B2HQ.As partners in B2H, what agreements are necessary between Idaho Power and PacifiCorp?A.In addition to the transactions directly related to construction and operation of the B2H project, under the Term Sheet the Company and PacifiCorp agreed to the exchange of undivided ownership interests in certain transmission assets to provide transmission capacity that better aligns with the current configuration of the parties’ respective future needs following the addition of B2H. The JPSA, included as Agreement 5 in Exhibit No. 2, facilitates these asset exchanges. Q.How will the asset exchanges between Idaho Power and PacifiCorp facilitate the objectives of the parties as envisioned in the Term Sheet?A.The Company agreed to exchange with PacifiCorp assets necessary to allow for (1) the transfer to PacifiCorp by Idaho Power of transmission assets between Midpoint and Borah to facilitate 300 MW of west-to-east capacity, (2) the transfer to PacifiCorp by Idaho Power of transmission assets between Borah and Hemingway to enable an additional 600 MW of east-to-west capacity, increasing from the current 1,090 MW to 1,690 MW, (3) the transfer to Idaho Power by PacifiCorp of transmission assets between Populus, Mona, and Four Corners to allow for 200 MW of bi-directional capacity, and (4)the transfer by PacifiCorp to Idaho Power of an ownership interest in identified Goshen area assets.
Four Corners/Populus Assets. The Company’s ownership interest in the Four Corners/Populus assets will include 345-kV transmission lines between the Four Corners, Pinto, Huntington, Camp Williams, Mona, Terminal, 90th South, Ben Lomond, and Populus substations. Consistent with federal processes, the Company and PacifiCorp will complete required studies to determine whether recent system upgrades result in a possible increase in existing transmission capacity between Borah and Populus to facilitate Idaho Power’s incremental transfer needs associated with this exchange. If determined necessary, the parties will identify revisions to existing agreements, upgrades, modifications, or other options to meet each party’s commercial needs between Borah and Populus.Goshen Area Assets. Under the Term Sheet, the Parties agreed to make best efforts to plan for service to BPA’s six preference customers in Southeast Idaho that requires only one leg of network transmission from the BPA transmission system. Idaho Power’s ownership interest in the Goshen area assets will enable BPA to serve its loads currently in PacifiCorp’s East transmission with one leg of firm network transmission service from the Company.Borah/Midpoint West Assets. The transfer by Idaho Power to PacifiCorp of Borah/Midpoint West assets will provide ownership to PacifiCorp on the Company’s existing transmission system from Borah/Kinport to Hemingway (east-to-west) and from Midpoint 500 to Borah/Kinport (west-to-east), including 500-kV and 345-kV transmission lines creating a path between the Borah, Kinport, Adelaide, Midpoint and Hemingway substations. In addition, upgrades will be required across the Borah West and Midpoint West paths to facilitate this portion of the proposed asset exchange.Q.Is Idaho Power requesting approval of these asset exchanges as part of the request in this case?A.No. The asset exchanges will not be effective until energization of the B2H project which is expected to occur in 2026. Exhibit A to the JPSA does however identify the assets necessary for facilitating the capacity rights agreed upon and acquired by Idaho Power or conveyed to PacifiCorp. Both the Company and PacifiCorp will request approval of the agreement pursuant to Idaho Code § 61-328, detailing the benefits associated with the assets being exchanged and demonstrating the transaction is consistent with the public interest, in a future proceeding.Q.Have Idaho Power and PacifiCorp contemplated who will be responsible for operations and maintenance of the exchanged assets?A.Yes. PacifiCorp and the Company will expand the existing Joint Ownership and Operating Agreement, as amended and restated August 22, 2019, (“JOOA”) to include operation and maintenance provisions associated with the assets acquired by both parties under the JPSA. In addition, the Second Amended and Restated JOOA, identified as Agreement 6 on Exhibit No. 2, will include the ownership, operation, and maintenance provisions associated with the B2H project.Q.Are there any additional agreements between the Company and PacifiCorp as envisioned under the Term Sheet?A.Yes. As described in the Term Sheet, the Company and PacifiCorp will execute the B2H Project Joint Construction Funding Agreement (“Construction Funding Agreement“) that will cover all work necessary to construct B2H. The Construction Funding Agreement, identified as Agreement 7 on Exhibit No. 2,will provide definitive terms and conditions by which the parties will jointly support and contribute funds, for the procurement, construction, and commissioning of the B2H project, allowing for energization of the project by the earliest in-service date needed by the parties. In addition, it appoints Idaho Power as the construction project manager, providing for full power and authority to do all things necessary or proper to develop and construct the B2H project. Finally, the Construction Funding Agreement will incorporate work associated with the installation of the Midline Series Capacitor substation, which was originally envisioned as a separate funding agreement in the Term Sheet. The Midline Series Capacitor substation is necessary to reduce simultaneous interactions between the NW AC Intertie, central and southern Oregon load service, and Path 14 (Idaho to Northwest). The Company expects to execute the Construction Funding Agreement with PacifiCorp in July 2023.Q.Are there any other construction agreements required for the B2H project?A.Yes. Idaho Power and PacifiCorp will, in conjunction with the JPSA, execute two additional construction agreements, the Midpoint 500/345-kV Transformer Project Construction Agreement (“Midpoint Transformer Construction Agreement”) and the Kinport – Midpoint 345-kV Series Capacitor Bank Project Construction Agreement (“Kinport Capacitor Bank Construction Agreement”). Under the Midpoint Transformer Construction Agreement, the Company will make capital upgrades to the Midpoint 500-kV and 345-kV transmission substations, including a second 500/345-kV transformer bank and 345-kV tie line. Capital upgrades will be made to the Midpoint 345-kV transmission line under the Kinport Capacitor Bank Construction Agreement including installation of Kinport-Midpoint 345-kV series capacitor bank. The two construction agreements, identified as Agreements 9 and 10 on Exhibit No. 2, are expected to be executed in March 2023.Q. Are any changes to transmission service agreements between the Company and PacifiCorp necessary to facilitate the proposed ownership structure of the B2H project?A.No. While initially contemplated in the Term Sheet, PacifiCorp has determined they will not terminate their existing 510 MW of east-to-west transmission service across southern Idaho as initially anticipated. Rather, as shown on Exhibit No. 2 as Agreement 11, PacifiCorp is expected to continue this existing 510 MW of PTP transmission service from Idaho Power. PacifiCorp’s PTP transmission service is term specific, and has roll over rights, so PacifiCorp will continue to reserve its rights to either terminate the service or roll it over. This decision will be made by PacifiCorp every five years. Idaho Power will continue to plan its system assuming PacifiCorp retains their transmission service.II. TRANSMISSION PLANNING AND THE IRP PROCESSQ.What is the goal of the IRP?A.The goal of the IRP is to ensure: (1) Idaho Power’s system has sufficient resources to reliably serve customer demand and flexible capacity needs over a 20-year planning period, (2) the selected resource portfolio balances cost, risk, and environmental concerns, (3) balanced treatment is given to both supply-side resources and demand-side measures, and (4) the public is involved in the planning process in a meaningful way. For reliability purposes, in the 2021 IRP the Company planned its resource portfolio to have a Loss of Load Expectation (“LOLE”) of 0.05 days per year or better (i.e. less than one resource adequacy related outage event in 20 years).Q.Please explain the Loss of Load Expectation.A.The LOLE is a statistical measure of a system’s resource adequacy, describing the expected number of days per year that a system would be unable to meet demand. Idaho Power plans to meet a reliability threshold of 0.05 days per year, or better, which represents one resource adequacy related outage event, or less, in 20 years. The Company utilizes test years, based on historical data, to calculate its LOLE. Given Idaho Power’s dependence on its hydro system, which fluctuates with water conditions, and the increased frequency of extreme events, the Company has aligned its resource adequacy methodology with the Northwest Power Conservation Council. The calculation of a system LOLE is complex, and not easily input into modeling software, therefore, the Company converts its LOLE methodology into a tabulated load and resource balance for the purposes of long-term planning.Q.Please explain the “load and resource balance.”A.The load and resource balance is the Company’s tabulated plan that identifies resource deficiencies during the 20-year IRP planning horizon. It helps ensure Idaho Power has sufficient resources to meet projected customer demand plus a margin to account for extreme conditions, reserves, and resource outages, and is checked against the LOLE. It is critical when comparing future resource portfolios that each plan achieve at least a base reliability threshold.Q.How is the resulting resource sufficiency or deficiency determined through the load and resource balance?A.At a high level, the load and resource balance incorporates the expected availability of Idaho Power’s existing resources, comparing the total output to the Company’s forecasted load, and illustrates the resulting surplus or deficit by month. This will identify the Company’s first resource need date, or the point at which Idaho Power’s reliability requirements may not be met. Q.How is the expected availability of the Company’s existing resources determined? A.The availability of existing resources, including Public Utility Regulatory Policies Act (PURPA) projects, power purchase agreements, hydro, coal, gas, demand response, and market purchases, is determined using a number of factors such as expected stream flows, plant run times, forced outages, historical performance, and transmission import capability, among other considerations.Q.You indicated this is compared to Idaho Power’s forecasted load. How is the load forecast determined?A.Each year, the Company prepares a forecast of sales and demand for electricity based on a combination of historical system data and trends in electricity usage along with numerous external economic and demographic factors. The anticipated average load and anticipated peak-hour demand forecast represent Idaho Power’s most probable outcome for load requirements during the planning period. The difference between the expected availability of the Company’s existing resources and the forecasted load is the resulting surplus or deficit by month. Q.How does the Company address a resource deficiency identified through the load and resource balance analysis?A.Deficits identified through the formation of the load and resource balance are then used to develop resource portfolios through potential combinations of supply-side resources, such as solar plus storage generation facilities, demand-side resources like energy efficiency measures, and transmission projects that increase access to energy markets. The portfolios are then analyzed and the portfolio that best minimizes cost and risk, and meets the LOLE, is selected in the plan as the preferred portfolio.Q.Please explain the importance of the Company’s transmission system with regard to resource planning. A. The Company’s transmission system is a critical component of Idaho Power’s ability to provide reliable and fair-priced energy services. Transmission lines facilitate the delivery of economic resources and allow resources to be sited where most cost effective. Furthermore, geographic diversity of resources and robust connections to neighboring systems facilitate system resiliency and minimize impacts from localized weather or events. For much of its history, Idaho Power has relied upon resources outside of its major load pockets to economically serve its customers. The existing transmission lines between Idaho Power and the Pacific Northwest have been particularly valuable. Transmission lines are constructed and operated at different operating voltages depending on purpose, location and distance. Idaho Power operates transmission lines at 138-kV, 161-kV, 230-kV, 345-kV, and 500-kV. Idaho Power also operates sub-transmission lines at 46-kV and 69-kV. The higher the voltage, the greater the capacity of the line and the lower the relative losses, but also greater construction cost and physical size requirements. Therefore, depending on the capacity needs, economics, distance, and intermediate substation requirements, either 230-kV, 345-kV, or 500-kV transmission lines may be chosen as a resource to facilitate the delivery of economic resources. Exhibit No. 4 shows an overview of the Company’s high-voltage transmission system.Q.Please describe the Company’s existing transmission capacity between the Pacific Northwest and Idaho Power. A.Idaho Power owns 1,280 MW of transmission capacity between the Pacific Northwest transmission system and the Company’s service territory. Of this, 1,200 MW are on the “Idaho to Northwest” path and 80 MW are on the “Montana-Idaho” path (the Company has transmission rights through Montana to the Pacific Northwest as part of the Amps Agreement – a legacy agreement currently scheduled to expire in 2025). Avista, BPA, and PacifiCorp share an allocation of capacity on the western side of the Idaho to Northwest path and Idaho Power owns 100 percent of the capacity on the eastern side of the path. To use the Company’s share of the Idaho to Northwest capacity to serve customer load, Idaho Power must purchase transmission service from Avista, BPA, or PacifiCorp. Similarly, in order to connect resources in the Pacific Northwest to Idaho Power’s transmission system via the Montana-Idaho path, the Company must purchase transmission service from either Avista or BPA to transmit, or wheel, the power across their system and deliver to Idaho Power’s transmission system. The Company fully utilizes the capacity of these lines.Q.Does Idaho Power own any transmission capacity to the south?A.Yes. The Company owns or controls transmission capacity between utilities in the south via the Idaho – Nevada path with NV Energy, which is utilized to import energy from the North Valmy Power Plant, and the Idaho – Utah path (“Path C”) with PacifiCorp. There is no firm transmission availability across Nevada to leverage the Idaho – Nevada path’s import capacity to access Desert Southwest markets. Regarding Path C, PacifiCorp is the owner and operator of all Path C transmission lines. Idaho Power has secured 50 MW of transmission capacity across PacifiCorp between the months of June and October to access the Desert Southwest markets. Q.When did the Company begin analyzing transmission adequacy and/or projects in the IRP?A.Idaho Power began analyzing transmission adequacy as part of the 2000 IRP. Prior to this time, Idaho Power planned for temporary water-related generation deficiencies through the use of short-term power purchases. As a summer-peaking utility, short-term power purchases were successful because the majority of other utilities in the Pacific Northwest region experienced peak loads during the winter. Therefore, prior to 2000, Idaho Power’s IRPs emphasized acquisition of energy rather than construction of generating resources to satisfy load obligations as transmission constraints were not a major impediment of the Company’s purchasing power to meet its service obligations. In addition, IRP planning periods were ten years at the time and therefore significant resource deficiencies did not exist in the ten-year planning period. However, because the Company had started experiencing transmission constraints, coupled with expected renewable resource development in the region, transmission adequacy analyses began being performed as part of the 2000 IRP planning process.Q.How did Idaho Power analyze transmission adequacy?A.To better assess the adequacy of the power supply and the transmission system, the Company performed a peak-hour transmission analysis which quantifies the magnitude of off-system market purchases that may be required to serve the load and determines if adequate transmission capacity is available to deliver those purchases. The results of the analysis performed as part of the 2000 IRP indicated transmission deficiencies under low water conditions of approximately 150 MW in 2002, growing to 500 MW by 2009. Q.Did Idaho Power continue to include transmission planning as part of the IRP preparation?A.Yes. The results of the 2002 IRP transmission adequacy analysis, under a 90th percentile water and 70th percentile load condition, were July peak transmission deficiencies of 141 MW and 225 MW in 2003 and 2004, respectively, increasing by 75-90 MW per year beginning in 2006, with deficiencies beginning to appear in December and January as well. The results of the 2004 IRP again showed July peaks were expected to increase by approximately 90 MW per year. By 2013, transmission deficiencies began appearing in May through September and reached to nearly 800 MW. Q.Were any changes made to the 2006 IRP with respect to transmission adequacy? A.Yes. Beginning with the 2006 IRP, Idaho Power commenced analyzing transmission system constraints for a 20-year planning period. In addition, it was at this time that the transmission analysis began factoring a 95th percentile peak-hour load along with a 90th percentile water and 70th percentile load condition for establishing a capacity target for planning purposes. Q. How did these refinements impact transmission deficiencies during the 20-year planning period?A.Deficiencies continued to exist during the summer months throughout the planning period growing from 450 MW in 2011 to as much as 1,800 MW in 2025. As a result, the preferred portfolio selected through the 2006 IRP process, and accepted by the Commission with Order No. 30281, included two significant supply-side resource additions, one of which was 225 MW of additional transmission capacity to occur in 2012 via a connection to the Pacific Northwest power markets, a project at the time envisioned as a 230-kilovolt transmission line between the McNary substation and Boise. Q.Was this the first time Idaho Power had considered transmission capacity as a supply-side resource addition?A. Yes, and soon after completion of the 2006 IRP, with Order No. 07-002, the Public Utility Commission of Oregon adopted guidelines regarding integrated resource planning including a guideline specific to transmission:Guideline 5: Transmission. Portfolio analysis should include costs to the utility for the fuel transportation and electric transmission required for each resource being considered. In addition, utilities should consider fuel transportation and electric transmission facilities as resource options[emphasis added], taking into account their value for making additional purchases and sales, accessing less costly resources in remote locations, acquiring alternative fuel supplies, and improving reliability.Q.How are supply-side resources compared when evaluating costs of resources during the IRP process? A.When evaluating and comparing alternative resources, two major cost considerations exist: the capital cost of the project, or fixed costs, and the energy cost of the project, or variable costs. Capital costs are derived through cost estimates to install the various projects and energy costs are calculated through a detailed modeling analysis, using the AURORA software, for both transmission capacity and supply-side resource additions. Energy prices are based on forecasted gas prices, coal prices, nuclear prices, hydro conditions, and variable operations and maintenance expenses. Portfolios that include transmission capacity as a resource addition include costs associated with market purchases, as forecasted in the AURORA model.Q.At what point did the plan for the 230-kV transmission line change to a 500-kV transmission line?A.Following inclusion of the 230-kV transmission line between the McNary substation and Boise in the preferred portfolio of the 2006 IRP, Idaho Power determined there was insufficient room at the existing McNary substation for major transmission expansion options. In addition, as part of the regional transmission planning public review process conducted by the Northern Tier Transmission Group (“NTTG”), it was determined a 230-kV project would be unable to meet the Company’s overall resource planning requirements and would underutilize a substantial transmission corridor. A project operating at a voltage of 500-kV was selected to match the existing Pacific Northwest transmission grid. The resulting project identified to meet this need, the B2H project, is an approximately 300-mile long, overhead, 500-kV high voltage transmission line between the proposed Longhorn Station near Boardman, Oregon, to the existing Hemingway Substation in southwest Idaho, which is designed to increase capacity between the Pacific Northwest and Idaho Power’s service area, adding 1,050 MW of capacity to the Idaho to Northwest path in the west-to-east direction, and 1,000 MW of capacity from east-to-west.Exhibit No. 5 shows a map of the region with the B2H project substation termination points.Q.Has the Company evaluated whether alternative transmission arrangements might better serve Idaho Power’s need for transmission capacity?A.Yes. Idaho Power studied a number of alternative transmission additions to determine the best solution to the Company’s need. The Company’s analysis assumed the 300-mile line between the Longhorn station and the Hemingway station. The following is a summary of relative capacities, anticipated ratings, and losses for new transmission lines at different operating voltages:Table 1. Comparison of Transmission Line Capacity Scenarios – New Lines from Longhorn to HemingwayScenarioLine Capacity1Potential Path 14 W-E Increase2Losses on New Circuit(s)3a. Longhorn to Hemingway 230-kV single circuit956 MW525 MW10.8%b. Longhorn to Hemingway 230-kV double circuit1,912 MW915 MW9.5%c. Longhorn to Hemingway 345kV single circuit1,434 MW730 MW6.6%d. Longhorn to Hemingway 500-kV single circuit3,214 MW1,050 MW4.2%e. Longhorn to Hemingway 500-kV – two separate lines6,428 MW2,215 MW3.7%f. Longhorn to Hemingway 500-kV double circuit6,428 MW1,235 MW2.9%g. Longhorn to Hemingway 765-kV single circuit4,770 MW1,200 MW2.4%1 Line Capacity is the thermal rating of the assumed conductors and does not account for system limitations of voltage, stability, or reliability requirements.2 Potential Rating is based upon study results to date to meet reliability design requirements for the WECC ratings processes, not including simultaneous interaction studies.3 Estimated Losses are percent losses for the new line at the Potential Rating loading level. Annual energy losses are dependent on total system loss reductions. All of the scenarios would likely yield a total system loss reduction for the flow levels above.In addition, the Company evaluated the possibility of constructing a new line built in place of an existing transmission line, known as a rebuild, for a portion of the total line length and new line built in a new right-of-way for the remaining portion of the total line length. Every rebuild scenario required at least 136 miles of new construction in a new right-of-way. Table 2. Comparison of Transmission Line Capacity Scenarios – Rebuild Existing Lines to the NorthwestScenarioLine Capacity1Potential Path 14 Increase2Losses on New Circuit(s)3Length of Line / New ROW4a. Replace Oxbow - Lolo 230 kV with Hatwai - Hemingway 500 kV3,214 MW430 MW W-E 675 MW E-W3.8%255 Miles / 136 Miles b. Replace Oxbow - Lolo 230kV with Hatwai - Hemingway 500 kV - No double circuiting with existing lines3,214 MW710 MW W-E 745 MW E-W4.1%255 Miles / 167 Milesc. Replace Walla Walla to Brownlee 230 kV with Sacajawea Tap- Hemingway 500 kV3,214 MW400 MW W-E 675 MW E-W 3.5%288 Miles / 150 Milesd. Replace Walla Walla to Pallette 230 kV with Sacajawea Tap - Hemingway 500 kV - No double circuiting with existing lines3,214 MW720 MW W-E 730 MW E-W3.8%288 Miles / 181 Milese. Build double circuit 500 kV/230 kV line from McNary to Quartz. Build 500 kV from Quartz to Hemingway3,214 MW765 MW W-E 870 MW E-W3.9%298 Miles / 168 Miles1 Line Capacity is the thermal rating of the assumed conductors and does not account for system limitations of voltage, stability, or reliability requirements.2 Potential Rating is based upon study results to date to meet reliability design requirements for the WECC ratings processes, not including simultaneous interaction studies.3 Estimated Losses are percent losses for the new line at the Potential Rating W-E loading level. Annual energy losses are dependent on total system loss reductions. All of the scenarios would likely yield a total system loss reduction for the flow levels above.4 In addition to utilizing the existing 230-kV right-of-way, each of the scenarios above will require a new ROW to be obtained.The result of these analyses indicated the only scenarios capable of providing 1,050 MW of west-to-east capacity are new lines at an operating voltage of 500-kV or greater. Q.Has the capacity of the B2H project received a rating from any other entity?A.Yes. Early in the B2H project development, the Company coordinated with other utilities in the Western Interconnection via a peer-review process known as the WECC Path Rating Process. Through the WECC Path Rating Process, Idaho Power worked with other western utilities to determine the maximum rating (power flow limit) across the transmission line under various stresses, and system flow conditions on the bulk power system. Based on industry standards to test reliability and resilience, Idaho Power simulated various outages, including the outage of B2H, while modeling these various stresses to ensure the power grid was capable of reliably operating with increased power flow. Through this process, the Company also ensured the B2H project did not negatively impact the ratings of other transmission projects in the Western Interconnection. Idaho Power completed the WECC Path Rating Process in November 2012 and achieved a WECC Accepted Rating of 1,050 MW in the west-to-east direction and 1,000 MW in the east-to-west direction. It was determined that the B2H project would add significant reliability, resilience, and flexibility to the Northwest power grid. Exhibit No. 6to my testimony is the Project Review Group Phase II Rating Report resulting from this study.Q.Was the B2H project identified as part of the preferred portfolio of subsequent IRPs?A.Yes. The B2H project was identified as part of the preferred resource portfolio in Idaho Power’s 2009, 2011, 2013, 2015, 2017, 2019 and most recently in the 2021 IRP. In addition, the B2H project has been identified as a regionally significant project, producing a more efficient or cost-effective plan in NTTG’s 2007, 2009, 2011, 2013, 2015, 2017, and 2019 biennial regional transmission plans, and in the NorthernGrid, NTTG’s successor regional planning organization, 2021 biennial regional transmission plan. The B2H project has proven to be a regionally significant project through the regional transmission planning process as well as a cost-effective resource through successive IRPs.III. THE B2H PROJECT AND THE 2021 IRPQ.Please describe the process for analyzing resources as part of Idaho Power’s most recent IRP, the 2021 IRP.A.Historically, the Company manually developed portfolios to eliminate resource deficiencies identified in a 20-year load and resource balance. Under this process, Idaho Power developed portfolios that were demonstrated to eliminate the identified resource deficiencies. However, beginning with the Second Amended 2019 IRP, and again with the 2021 IRP, the Company began using AURORA’s long-term capacity expansion (“LTCE”) modeling capability to develop portfolios.The logic of the LTCE model optimizes resource additions and exits of generating units based on the performance of each zone defined within WECC and develops resource portfolios under various future conditions, such as sensitivities for natural gas prices, carbon costs, load growth and electrification, transmission and clean energy constraints and timelines. The LTCE model applies a planning margin hurdle and regulation reserve requirements, and then optimizes resource selections around those constraints to determine a least-cost, least-risk portfolio. Available future resources possess a wide range of operating, development, and environmental attributes. Impacts to system reliability and portfolio costs of these resources depend on future assumptions. Each portfolio consists of a combination of resources derived from the LTCE process to enable Idaho Power to supply cost-effective electricity to customers over the 20-year planning period. Q.Was any further analysis performed on the portfolios that resulted from the LTCE modeling?A.Yes. For the 2021 IRP, the Company developed a branching scenario analysis strategy to ensure thatthe resulting portfolios reasonably identified an optimal solution specific to its customers. Exhibit No. 7 details the initial branching evaluation where Idaho Power compared AURORA-optimized portfolios for a base scenario (i.e., planning conditions for all key inputs such as load growth, natural gas price, carbon price, etc.) for six potential future portfolios. Each of these portfolios was fully optimized by the LTCE model:(1) Base with the B2H project, (2) Base with the B2H project but without Gateway West,(3) Base with the B2H project andPacifiCorp Bridger Alignment,(4) Base without the B2H project, (5) Base without the B2H project and without Gateway West, and(6) Base without the B2H project but with PacifiCorp Bridger Alignment. Idaho Power compared the base portfolios that included the B2H project to determine an optimal B2H project-included portfolio (“Base with B2H”) and compared the base portfolios that did not include the B2H project to determine an optimal B2H-excluded portfolio (“Base without B2H PAC Bridger Alignment”).Q.What occurs once the LTCE modeling and robustness testing is complete?A.Once the portfolios are created using the LTCE model, Idaho Power performs the portfolio cost analysis using the AURORA electric market model, determining operating costs for the 20-year planning horizon for each of the six resource portfolios. The AURORA software applies economic principles and dispatch simulations to model the relationships between generation, transmission, and demand to forecast market prices. Various mathematical algorithms simulate the regional electrical system to determine how utility generation and transmission resources operate to serve load. Portfolio costs are calculated as the net present value (“NPV”) of the 20-year stream of annualized costs, fixed and variable, for each portfolio. Q.What were the results of the AURORA electric market modeling of the six different portfolios?A.Each of the six different portfolios were evaluated through three different hourly simulations, including the planning case scenario as well as bookends for natural gas and carbon adder price forecasts. The hourly simulations enable the Company to compare how the portfolios will perform throughout the 20-year timeframe and identify a potential option for a preferred portfolio. The following table presents the results of the hourly simulations:Table 3. 2021IRPportfolios,NPVyears2021–2040($x1,000) 1The Company did not continue further evaluation of this portfolio beyond planning conditions due to the portfolio’s inferior performance (high-cost, poor reliability, and poor emissions performance).2 All portfolios were optimized with planning conditions. The “Base with B2H—High Gas High Carbon (HGHC) Test” portfolio includes total renewables equivalent to the “Base without B2H” portfolio and was evaluated to test B2H as an independent variable. The results indicate that B2H remains cost effective, independent of gas price and carbon price and that a pivot to even more renewables in a future with a high gas and carbon price would be appropriate.This comparison indicates the Base with B2H portfolio best minimizes both cost and risk and is the appropriate choice for the preferred portfolio. Q.For the portfolios that include the B2H project, do the modeled costs reflect Idaho Power’s 45.45 percent ownership share reflected in the Term Sheet and subsequently the Purchase, Sale and Security Agreement?A.Yes. The 2021 IRP modeled B2H costs based on an Idaho Power ownership share of 45.45 percent. Q.How did the cost of the Base with B2H portfolio compare to the Base without B2H PAC Bridger Alignment portfolio as determined through the LTCE modeling?A.Comparing the NPV cost of the Base with B2H portfolio to the Base without B2H PAC Bridger Alignment portfolio, results in a $266 million difference, or $266 million more costly than the preferred portfolio. This cost difference definitively shows that the B2H project is a necessary component of the Company’s preferred portfolio, assuming comparable risk performance to other portfolios.Q.Did Idaho Power perform any additional testing of the branching scenario analysis? A.Yes. To further validate transmission planning results, the Company performed additional robustness testing including various sensitivities and scenarios on the portfolios that includedthe B2H project, including one specific to the robustness of the B2H project, and testing capacity sensitivities, cost risks and timing, which I will describe in more detail later in my testimony.The results of all the sensitivities and scenarios performed validated and further verified that the results of the LTCE modeling identified optimal solutions for Idaho Power’s customers.Q.You indicated the cost of a resource is based on the capacity cost, or fixed costs, and the energy cost, or variable costs of that resource. How did the capacity cost of the B2H project compare to alternative resources when evaluated in the 2021 IRP?A.The table below provides capital costs for resource options found in the 2021 IRP to have the lowest cost from a capacity perspective:Table 4. Total capital dollars ($/kW) for select resourcesconsidered in the 2021 IRP (2021$)
Resource Type
Total Capital $/kW
Depreciable Life
B2H$6471
55 years
Combined-cycle combustion turbine (CCCT) (1x1) F Class (300 MW)$1,656
30 years
Simple-cycle combustion turbine —Frame F Class (170 MW)$900
35 years
Reciprocating Gas Engine (55.5 MW)$1,560
40 years
Solar PV—UtilityScale 1-Axis (100 MW) + 4-hr Battery (100 MW)$2,150
30 years21 Uses the B2H 750-MW capacity.2 Depreciable life assumed for the solar component is 30 years and is 15 years for the storage component.The capital costs for the B2H project include local interconnection costs and the project is still roughly 70 percent of the cost of the next lowest-cost resource. Additionally, transmission lines, have a longer depreciable life when compared to a gas plant or a solar plant. The low up-front cost and longer depreciation period further reduces the rate impact to Idaho Power’s customers. The summation of these factors show the B2H project is the lowest capital-cost resource by a substantial margin.Q.Has the Company performed any modeling outside of the IRP to test whether Idaho Power’s current 45.45 percent ownership share in the B2H project is the most cost effective and least risk option?A.Yes. Although entirely hypothetical, Idaho Power analyzed alternatives to the ownership structure to evaluate the risk associated with, and cost-effectiveness of, a 45.45 percent ownership share to gauge reasonableness of the modeling results. First, bookends were created using results from the 2021 IRP modeling. As shown in Table 3, the least-cost portfolio without the B2H project, Base without B2H PAC Bridger Alignment, is approximately $8.208 billion and the least-cost portfolio with the B2H project, Base with B2H, has a cost of $7.942 billion, indicating a $266 million difference between the two bookends. Next, the Company modeled an extremely conservative scenario in which there is no value associated with the additional capacity Idaho Power gains through acquisition of BPA’s ownership share. That means that even under the highly unlikely scenario where the Company receives no transmission revenues associated with its 45.45 percent ownership share, the B2H portfolio remains the most cost effective and least risk.Q.What were the resulting portfolio costs?A. Assuming the unlikely hypothetical scenario results in a portfolio cost of $8.089 billion, indicating that even absent value to the additional capacity Idaho Power will receive with 45.45 percent ownership, the portfolio is still $119 million more cost effective than the lowest cost “without B2H” portfolio. The results indicate that acquisition of BPA’s ownership share of the B2H project, with payment from BPA for network transmission service, is the most cost-effective solution for the Company’s customers. The B2H project as a resource has repeatedly demonstrated to be the most cost-effective method of serving projected customer demand, and as a transmission line the B2H project also offers incremental ancillary benefits, additional operational flexibility, and access to abundant clean energy in the Pacific Northwest.IV. THE B2H PROJECT COSTS INCLUDED
IN THE PREFERRED PORTFOLIOQ.What were the B2H project costs included in the 2021 IRP preferred portfolio?A.The cost estimate included in the 2021 IRP preferred portfolio included B2H project costs assuming Idaho Power’s ownership share under the Term Sheet, or 45.45 percent. Prepared between 2020 and 2021, the cost estimate was based on a 10 percent detailed design/indicative design, the best available information at the time. Ms. Barretto will discuss the detailed design/indicative design milestones in more detail in her testimony. The capital costs modeled, including Allowance for Funds Used During Construction but excluding any contingency amounts, were $435.5 million. In addition, the 2021 IRP preferred portfolio included approximately $49.7 million in additional capital costs associated with the B2H project transmission upgrades, $35.3 million for local 230-kV upgrades necessary to integrate the project into Treasure Valley load center and an estimated $14.4 million associated with the NPV of the buyout of BPA’s permitting interest.Q.How were the B2H project costs determined?A.The Company contracted with HDR, Inc. (“HDR”) to serve as the B2H project’s third-party owners’ engineer and prepare the B2H transmission line cost estimate. HDR has extensive industry experience, including experience serving as an owner’s engineer for BPA for the last seven years. HDR has prepared a preliminary transmission line design that locates every tower and access road needed for the project. HDR used utility industry experience and current market values for materials, equipment, and labor to arrive at the B2H estimate. Material quantities and construction methods are well understood because the B2H project is utilizing BPA’s standard tower and conductor design for 500-kV lines. BPA has used the proposed towers and conductor on hundreds of miles of lines currently in-service.Q.Were substation costs included in this estimate?A.Yes. Costs associated with three substations are included in the B2H project cost estimate, the Longhorn station, the Hemingway substation, and a Midline Series Capacitor substation. The northern terminus for B2H requires the new Longhorn station to tap into the existing BPA 500-kV transmission network. BPA owns the land for the Longhorn station and intends to construct the substation, at the request of Umatilla Electric for load service purposes, once all environmental compliance laws are met. As agreed under the Term Sheet, BPA will own all equipment and facilities in the Longhorn station, except B2H-specific equipment and facilities that will be jointly owned by Idaho Power and PacifiCorp. The Company’s ownership share of the jointly owned equipment is included in the B2H project costs modeled in the 2021 IRP. The Idaho Power-owned existing Hemingway substation is designed to accommodate the B2H line terminal but will require the addition of new equipment, which was also included in the total B2H project costs. The Midline Series Capacitor station was added to the project scope between the 2019 IRP and 2021 IRP to facilitate the operational needs of the parties, and at this time consists of only a fenced yard and series capacitor. Finally, the B2H project costs also include costs associated with necessary local interconnection upgrades, upgrades necessary to the southern Idaho transmission system and BPA’s permitting buyout.Q.How did the Company calibrate the total B2H project costs for reasonableness?A.The B2H project costs included in the modeling of the 2021 IRP were reviewed and approved by BPA and PacifiCorp, both of whom have recent 500-kV transmission line construction projects to calibrate against. In addition, Idaho Power worked collaboratively with NV Energy and Southern California Edison to calibrate the B2H project cost estimate using their experience on two recent 500-kV projects.Q.Transmission capacity can be sold to third parties when not being utilized by the Company. How did Idaho Power model the transmission wheeling revenue benefits associated with B2H?A.The B2H project is modeled in AURORA as additional transmission capacity available for Idaho Power energy purchases from the Pacific Northwest. In general, for new supply-side resources modeled in the IRP process, surplus sales of generation are included as a cost offset in the AURORA portfolio modeling. Transmission wheeling revenues, however, are not included in AURORA calculations. To account for this, in the 2021 IRP, Idaho Power modeled incremental transmission wheeling revenue from non-native load customers outside of AURORA as an annual revenue credit. Therefore, the preferred portfolio which includes the B2H project, includes a reduction in project costs associated with incremental transmission revenues, ultimately benefiting the Company’s retail customers. The transmission revenue credit incorporates any changes in point-to-point reservations with BPA and PacifiCorp as agreed to under the Term Sheet, including expected revenues from the NITSAswith BPA I discussed earlier in my testimony.Q.Are there any potential additional benefits in transmission revenues Idaho Power did not include in its quantification?A.Yes. Due to significant increase in capacity that the B2H project provides to the Idaho to Northwest path, the Company believes firm, short-term firm, and non-firm usage of the Idaho Power transmission system by third parties could increase, as supported by the over 1,000 MWs of transmission requests that the Company has seen across the Idaho to Northwest path over the past 24 months. Additionally, Idaho Power’s acquisition of 200 MW of bidirectional capacity to Four Corners, New Mexico will only further enhance the value of the Company transmission system to third parties. These potential revenues would further reduce the cost of the project, however, to be conservative, Idaho Power assumed a constant transmission usage by third parties (no increase or decrease) from an average of usage over recent years.Q.Did the B2H project costs modeled in the 2021 IRP include a contingency?A.No. None of the modeled resources in the 2021 IRP included a contingency amount, including the B2H project. Therefore, it would have skewed the IRP modeling results to have included a contingency amount in the B2H cost estimate. That said, the Company did perform a risk analysis in the 2021 IRP for informational purposes in which Idaho Power evaluated 10 percent, 20 percent and 30 percent cost contingencies for the B2H project.The following table presents the B2H project costs, by cost category, and cost contingency utilized in the risk analysis:Table 5. B2H Project Costs by Cost Contingency
Contingency %
B2H Main Project
Local 230 Upgrades
NPV BPA Permitting Buyout
Total
Total Portfolio NPV Impact
B2H 0%
$435.5M
$35.3M
$14.4M
$485M
$159.6M
B2H 10%
$472.7M
$38.8M
$14.4M
$526M
$178.4M
B2H 20%
$509.8M
$42.4M
$14.4M
$566M
$197.2M
B2H 30%
$546.8M
$45.9M
$14.4M
$607M
$216.1MThe line labeled B2H 0% reflects the costs described earlier and modeled in the 2021 IRP. For IRP purposes, the Company reports Total Portfolio Net Present Value (“NPV”) Impact because this is the amount that must be added to the Preferred Portfolio. The total costs of all resources are levelized into an annual amount, and quantified over the 20-year IRP planning period, for fair comparison purposes. The table below presents the results of the risk analysis that evaluated the various cost contingencies:Table 6. B2H Cost Sensitivities

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 The 2021 IRP portfolio NPV cost for B2H is $159.6 million assuming a 0 percent contingency amount. B2H with a 30 percent contingency increases the cost of B2H by $122 million ($607 million less $485 million) but that increase only results in increased B2H portfolio costs of $56.5 million NPV.As I mentioned earlier, the difference between the Preferred Portfolio, and the best alternative portfolio that did not include B2H was approximately a $266 million NPV. Additionally, IRPs are based on comparing portfolios, and the best alternative portfolio that did not include B2H included the Gateway West project, another 500-kV transmission project. An increase in B2H costs would likely mean that there would be a comparable increase to Gateway West costs.Therefore, B2H costs could increase significantly, and well beyond 30 percent, and the project would remain cost effective.Q.Has Idaho Power updated the B2H project cost estimate since publishing the 2021 IRP?A.Yes. As Ms. Barretto discusses in her testimony, the Company’s constructability consultant assisted the Company in updating its B2H project cost estimate. Assuming Idaho Power’s 45.45 percent ownership share, B2H project costs are estimated to be $670.5 million, including a 20 percent contingency. The increase from the 2021 IRP B2H project cost estimate of $485 million can primarily be attributed to (1) increased material and labor costs due to inflation and supply chain issues, and (2) the inclusion of approximately $135.9 million in contingency costs, at a total project level, which were not included in the 2021 IRP B2H project costs.Q.Please explain the increased material and labor costs resulting from inflation and supply chain issues. A.Inflationary pressures and supply chain disruptions are pushing up the cost of labor and materials necessary to construct B2H. However, transmission expansion is required independent of the portfolio selected to drive least-cost. The least-cost non-B2H portfolio requires a sub-segment of Gateway West in 2027, and another Gateway West segment in 2033. The cost estimate of these Gateway West segments in the 2021 IRP was based on the estimated cost of B2H, therefore, the cost of the optimal non-B2H portfolio would also increase. In the case of the least-cost non-B2H portfolio, the cost increases associated with Gateway West (assuming the same inflationary and supply chain pressures) would be nearly offsetting when compared to the Preferred Portfolio. Inflationary pressures and supply chain disruptions are therefore immaterial, as the Company must build something to meet its load service requirement, and there is no economic way to avoid a major 500-kV transmission project.Q.How does the increased B2H cost estimate impact the economics of the project and the conclusions drawn in the 2021 IRP?A.The following table presents the December 2022 B2H project cost estimate and total portfolio NPV impact together with the 2021 IRP B2H project costs by cost category and cost contingency presented earlier in my testimony in Table 5.Table 7. B2H Project Costs by Cost Contingency Using Updated Costs
Contingency %
B2H Main Project
Local 230 Upgrades
NPV BPA Permitting Buyout
TOTAL
TOTAL Portfolio NPV Impact
B2H 0%
$435.5M
$35.3M
$14.4M
$485M
$159.6M
B2H 10%
$472.7M
$38.8M
$14.4M
$526M
$178.4M
B2H 20%
$509.8M
$42.4M
$14.4M
$566M
$197.2M
B2H 30%
$546.8M
$45.9M
$14.4M
$607M
$216.1M
2022 B2H Costs
$605.4M
$46.9M
$18.2M
$671M
$238.9MWhile the total B2H cost increases from $485 million (zero percent contingency) to $671 million (20 percent contingency), the Preferred Portfolio NPV cost impact is only an increase from $159.6 million to $238.9 million, a $79.3 million impact. By inspection, a $79.3 million increase does not result in a change to the Preferred Portfolio, as the best non-B2H portfolio is $266 million more costly. And, as I explained earlier in my testimony, the best non-B2H portfolio would see similar increases due to increased Gateway West costs.In addition, if Idaho Power were to update costs of all capital projects based on current conditions, the B2H project is not the only variable that would change. As I noted above, a primary factor driving the increase in the B2H cost estimate is increased material and labor costs due to inflation and supply chain issues—which would impact the cost of capital projects in all portfolios studied. B2H replacement resources have also seen price increases due to inflationary and supply chain pressures since the 2021 IRP was published, therefore, the least-cost non-B2H portfolio would experience cost increases as well. Even with the cost increase, the Company has sufficient information to ascertain that the B2H project remains the least-cost, least-risk optionusing theDecember 2022 updated estimate of $670.5 million. V. JUSTIFICATION FOR THE B2H PROJECTQ.Aside from the B2H project being a component of the least-cost preferred portfolio, what other benefits does the line provide?A.In a low-carbon future dominated by renewable resources, geographical diversity of wind and solar, as well as regional utility loads, is a vital component of reliability and affordability, and transmission is the enabler of geographical diversity. In-depth studies and experts, such as the American Clean Power Association, cite the need for an expanded and robust transmission system in a decarbonized future. Indeed, the Americans for a Clean Energy Grid highlighted B2H as one of 22 projects that were needed to enable the interconnection of around 60,000 MW of additional renewablecapacity in the United States.In addition, a variety of other benefits are expected: capacity to the Four Corners market hub, improved economic efficiency, renewable integration, grid reliability/resiliency, resource reliability, contingency reserves, reduced electrical losses, flexibility, Energy Imbalance Market (“EIM”) value, and economic value along the B2H project route.Improved Economic Efficiency and Renewable IntegrationQ.How does the B2H project improve economic efficiency and the integration of renewable resources?A.Transmission congestion causes power prices on opposite sides of the congestion to diverge as higher cost, less efficient resources are dispatched to ensure the transmission system is operating securely and reliably. Congestion can have a significant cost. Historically, during peak summer conditions, the Idaho to Northwest path in the west-to-east direction often becomes fully constrained with zero firm transmission available between the regions and power prices in Idaho and to the east willgenerally be higher than power prices in the Pacific Northwest, a market inefficiency caused by inadequate transmission capacity to economically move power between regions. The B2H project will help alleviate this constraint and enable generators in the Pacific Northwest to gain further value from their existing resource, and load-serving entities in the Mountain West region will be able to meet load service needs at a lower cost. At other times, such as the winter, the roles may reverse with the Pacific Northwest benefiting from economical resources from the Mountain West region with B2H’s additional east-to-west capacity.Similarly, the lack of transmission capacity, at times, prevents the energy from existing renewable generation to move to load, which in turn requires renewable resources to be curtailed. The B2H project is necessary to integrate and balance variable energy resources like wind and solar as it will facilitate the transfer of geographically diverse renewable resources across the western grid and help ensure the clean energy grid of the future, both Idaho Power’s and surrounding states’, is robust and reliable. Lawrence Berkley National Laboratory recently published a study titled “Empirical Estimates of Transmission Value using Locational Marginal Prices.” In the study, the difference between the EIM_BPAHub node and the EIM_UT node (the EIM Utah node is a close surrogate for Idaho Power), has an approximately $13.50 per MWh mean power spread between 2012 and 2022, resulting in approximately $125 million per year in potential energy arbitrage related value. This value, or a subset, was not factored into the 2021 IRP but represents a real benefit to Idaho Power’s customers, nevertheless.Grid Reliability/ResiliencyQ.Please explain how the B2H project will contribute to the reliability and resiliency of the grid.A.The B2H project will increase the robustness and reliability of the regional transmission system by adding high-capacity bulk electric facilities designed with the most up-to-date engineering standards. Major 500-kV transmission lines, such as B2H, substantially increase the grid’s ability to recover from unexpected disturbances.Q.What are some examples of unexpected disturbances whose impacts would be reduced with the addition of the B2H project?A.While unexpected disturbances are difficult to predict, I can provide a few examples of disturbances whose impacts would be reduced with the addition of B2H. First, the loss of the Hemingway–Summer Lake 500-kV transmission line, the only 500-kV connection between the Pacific Northwest and Idaho Power, during peak summer load, is one of the worst possible contingencies the Company’s transmission system can experience. Once the Hemingway–Summer Lake 500-kV disconnects, the transfer capability of the Idaho to Northwest path is reduced by over 700 MW in the west-to-east direction. After the addition of the B2H project, there will be two major 500-kV connections between the Pacific Northwest and Idaho Power, reducing risk by increasing redundancy.Another potential Idaho Power disturbance could be on the same Hemingway-Summer Lake 500-kV line but east-to-west. In this disturbance, an existing remedial action scheme (power system logic used to protect power system equipment) will disconnect over 700 MW of generation at the Jim Bridger Power Plant or Wyoming wind to reduce path transfers and protect bulk transmission lines and apparatus. Due to the magnitude of the generation loss, recovery from this disturbance can be extremely difficult. After the addition of the B2H project, this sizable amount of generation shedding will no longer be required. With two 500-kV lines between Idaho and the Pacific Northwest, the loss of one can be absorbed by the other. Keeping 700 MW of generation on the system for major system outages is important for grid stability.Third, the loss of a single 230-kV transmission tower in the Hells Canyon area could create another transmission disturbance. Idaho Power owns two 230-kV transmission lines, co-located on the same transmission towers, that connect Idaho to the Pacific Northwest. Because these lines are on a common tower, Idaho Power must consider the simultaneous loss of these lines as a realistic planning event. Historically, such an outage did occur on these lines in 2004 during a day with high summer loads. By losing these lines, Idaho Power’s import capability was dramatically reduced, and the Company was forced to rotate customer outages for several hours due to a lack of resource availability. With the addition of the B2H project, the impact of this outage would be substantially reduced.Finally, a more general example is discussed in a recent paper titled “Transmission Makes the Power System Resilient to Extreme Weather” by Grid Strategies which explored the benefits that transmission can provide to regions experiencing extreme weather. During Winter Storm Uri alone, the paper identifies seven different transmission connections that could have provided over $80 million of benefits per 1,000 MW of transmission capacity for that single event, with one specific connection that would have provided nearly $1 billion in benefits per 1,000 MW. Extreme events, such as the 2021 Pacific Northwest heat dome, are seemingly increasing in frequency, and transmission lines provide a significant regional diversity, reliability, and resilience benefit.Resource ReliabilityQ.How does the reliability of a transmission line compare to that of a generation resource?A.The forced outage rate of a resource is the best measure of its reliability, and, in general, the forced outage rate of transmission lines has historically been lower than traditional generation resources. NERC has historically tracked the forced outage rate for transmission availability through a Transmission Availability Data System (“TADS”) and generation availability through a Generation Availability Data System (“GADS”). Q.What are the comparable NERC forced-outage rates of the various resources?A.The NERC forced-outage rates used in modeling of the 2021 IRP were approximately 6 to 9 percent for coal generation, 3.6 percent for hydro generation, approximately 4.4 percent to 7.3 percent for simple cycle gas generation, 2 percent for combined cycle gas generation and one-quarter of one percent for transmission resources. A transmission line with a forced outage rate of less than 1 percent is significantly more reliable than a power plant - the B2H project is expected to have 99.75 percent availability when needed. Of course, a transmission line requires generating resources to provide energy to the line to serve load. However, energy sold as “firm” must be backed up and delivered even if a source generator fails. Therefore, firm energy purchases would have an equivalent forced outage rate demand – or EFORd - consistent with the transmission line, which is more reliable than traditional supply-side generation. In the management of cost and risk, B2H will provide Idaho Power’s operators additional flexibility when managing the Idaho Power resource portfolio. In addition to lower costs, the 2021 IRP preferred portfolio is significantly more reliable than the best portfolio that did not include B2H.Contingency Reserves and Electrical LossesQ.How will the B2H project support the Company’s contingency reserve obligations?A.During real-time operations, Idaho Power holds generation in reserve to meet its NERC contingency reserve obligation, or generation in reserve equaling at least three percent of network demand plus three percent of internal generation. For market purchase imports, the three percent contingency requirement for the generation is not borne by the Company but rather the producer in the external balancing area is required to meet the reserve obligation associated with its resource, reducing Idaho Power’s reserve obligation. The Company plans to make additional market purchases with B2H and therefore the selling entity will carry the contingency reserve obligation. This reduction in reserve obligation will offset the additional reserve obligations taken on by the Company through the increased amount of BPA customer network load and generation in the Idaho Power area. Idaho Power’s reserve obligation during summer peak will be reduced with the B2H project as compared to a replacement internal resource.Q.Is the B2H project expected to reduce electrical losses?A.Yes. Losses on the power system are caused by electrical current flowing through energized conductors, which in turn create heat.By constructing the B2H project, less efficient, lower voltage transmission lines with very large transfers are relieved, reducing the electrical current through these lines and reducing the losses due to heat.Q.How did Idaho Power estimate the reduction in electrical losses that is expected to result from addition of the B2H project?A.The electrical losses vary throughout the year depending on flow levels on the lines. To determine an average electrical loss saving benefit for the Company resulting from the B2H project, various seasonal WECC power flow base cases were utilized to simulate flow conditions with and without the addition of B2H. In six of the seven cases the B2H project resulted in a beneficial reduction of losses in the Idaho Power balancing area. To develop an average loss savings benefit for the B2H project that considers all flow hours, regression analysis was performed to develop quadratic equation coefficients that relate path flows to predicted energy loss savings. Next, historical transmission path flows from the previous five years were captured and analyzed with developed loss savings coefficients. The result of the analysis was an Idaho Power 6.4 MW per hour average electrical loss savings with the addition of the B2H project. Capacity to Four Corners Market HubQ.Please explain the value of the capacity gained to the Four Corners Market Hub.A.As explained earlier in my testimony, under the Term Sheet, Idaho Power will acquire from PacifiCorp transmission assets and their related capacity sufficient to enable the Company to utilize 200 MW of bidirectional transmission capacity between the Company’s system, at the Populus substation, and the Four Corners substation, a desert Southwest market hub. Eight entities with transmission have connectivity to the Four Corners market hub. Along the route between Populus and Four Corners, the Company will also have a connection to Mona substation, in central Utah, establishing a direct connection between Idaho Power and the Los Angeles Department of Water and Power. The 200 MW of bidirectional capacity will provide the Company with long-term strategic value from a market that is diverse from the Pacific Northwest. Importantly, the desert Southwest is rich with solar potential which is expected to continue its significant growth in the future, New Mexico has significant wind potential, and the number of desert Southwest entities with a presence at this market hub presents significant market diversity opportunities. Idaho Power believes additional access to this market hub during the winter months will prove to be extremely valuable in a low carbon future. Moreover, the transmission assets between Idaho and Four Corners will provide a valuable firm transmission connection to a market hub that is diverse from Mid-C, enabling two diverse connections to two major western market hubs. As a conservative planning approach, this additional 200 MW of import capacity is set to zero in planning margin calculations for the summer peaking months. The diversity of capacity from multiple market hubs solidifies and supports that the overall B2H project capacity will achieve 500 MW of peak import capacity into Idaho Power.Q.When will the winter value of the Four Corners market access materialize?A.In the 2021 IRP, the Company expected to start seeing this value in the mid-2030s with winter load increasing, and dispatchable coal resources retiring. As the Company is currently developing its 2023 IRP, however, Idaho Power is seeing the Four Corner’s capacity as likely especially valuable in the mid to late-2020s. This change is due to the sizeable increase in the load forecast, and specifically the winter load forecast, due to increased industrial loads.Q.How has the value of the Four Corners capacity been quantified? A.In the 2021 IRP, the value of the Four Corner’s capacity was not quantified due to its value starting very late in the plan. Generally, the Company did not see any winter reliability issues in its 20-year plan. The Company expects the Four Corners capacity will provide substantial value in its 2023 IRP when portfolios inclusive of B2H and the Idaho Power and PacifiCorp asset exchange are compared against portfolios not inclusive of B2H and the asset exchange. Due to the latest load growth forecasts, winter capacity needs will likely be a key consideration in the development of the 2023 IRP.Borah West and Midpoint West Capacity UpgradesQ.What value do the Borah West and Midpoint West upgrades provide?A.The Borah West and Midpoint West upgrades consist of the addition of a series capacitor to one of the Borah West transmission lines (the 345-kV line between the Kinport substation and the Midpoint substation), and a new high-voltage transformer added to the Midpoint 500-kV substation. These upgrades are required to facilitate the asset exchange with PacifiCorp, enabling PacifiCorp’s usage of its share of B2H project capacity.In the 2021 IRP, as a conservative estimate, the Company assumed the full $46.8 million cost of these upgrades would be Idaho Power’s responsibility. The conservative estimate was chosen because these assets are intended to be utilized to balance the Idaho Power and PacifiCorp asset exchange transaction, and the total values of the assets for each company were unknown. However, subject to final negotiations, it is likely that a portion of these assets will be paid for by PacifiCorp.Q.Given the capacity being acquired by PacifiCorp, will they continue to take 510 MW of point-to-point transmission service across the Company?A.Under the Term Sheet, and the Company’s 2021 IRP analysis, the expectation was that PacifiCorp would terminate 510 MW of transmission service. PacifiCorp has since indicated their intent to continue to take this service, as is their right as a long-term transmission customer taking PTP service with roll-over rights.Q.Does PacifiCorp’s continued usage of the 510 MW change the decision to move forward with B2H?A.No. In the 2021 IRP, PacifiCorp terminating the 510 MW of PTP transmission service was evaluated as a cost to B2H due to lost transmission revenue compared to a base “do-nothing” alternative. PacifiCorp continuing to take this PTP transmission service enhances the B2H business case.Q.What is the trade-off for the Company with PacifiCorp continuing to take 510 MW of transmission service? A.In the 2021 IRP, the Company was planning to repurpose the transmission that was being used by PacifiCorp to interconnect new resources in Eastern Idaho to be delivered to the growing Treasure Valley area. The impact of the 510 MW transmission service obligation remaining will be evaluated as part of the 2023 IRP. Additional B2H Project Benefits and ValueQ.Please describe the additional expected benefits and value of the B2H project you have not yet discussed in your testimony.A.The B2H project provides Idaho Power with flexibility in the acquisition and transfer of generation resources. As advances in technology are driving some generation resources, such as coal plants, toward economic obsolescence, the B2H project serves as an alternative to constructing a new supply-side resource. In this way, B2H reduces the risk of technological obsolescence by ensuring Idaho Power customers always have access to the most economic resources, regardless of the resource type. In addition, because the existing electrical system is so heavily used, new transmission line infrastructure like the B2H project will create additional operational flexibility. The B2H project will increase the ability to take other system elements out of service to conduct maintenance and will provide additional flexibility to move needed resources to load when outages occur on equipment. This additional transmission capacity and operational and resource flexibility also provides value in the EIM and should a day ahead market structure be determined economically beneficial to Idaho Power’s customers, the B2H project will complement the Company’s market participation and facilitate additional economic benefits.Q.How will the B2H project provide additional value in the energy imbalance market, or EIM?A.The expansion of the transmission system, through the addition of the B2H project, will facilitate further benefits by increasing transmission capacity between Idaho Power and other EIM participants. As fluctuations in supply and demand occur for EIM participants, the market system will automatically find the best resources from across the large-footprint EIM region to meet immediate power needs. This activity optimizes the interconnected high-voltage system as market systems automatically manage congestion, helping maintain reliability while also supporting the integration of variable energy resources and avoiding curtailing excess supply by sending it to where demand can use it. Greater transmission transfer capacity between participants in a market reduces congestion costs and allows the lowest cost energy to reach a wider load footprint. Idaho Power views the B2H project as a complement to any resource type. The B2H project will enhance access to the least-cost and most efficient resources andunlock additional regional diversity to benefit the Company as well as all customers in the West.Q.Will the B2H project provide any economic benefits to the region?A.Yes. First, the B2H project will result in positive economic impacts for eastern Oregon communities in the form of construction jobs, economic support associated with infrastructure development (i.e., lodging and food), and an estimated increase of $5.8 million in annual tax benefits in total to the counties for project-specific property tax dollars. It will also provide economic development opportunities because it will create available capacity for additional economic development to take place. In Union and Umatilla counties, BPA’s McNary–Roundup–La Grande 230-kV line has limited ability to serve additional demand in the Pendleton and La Grande areas but is currently capable of meeting the 10-year load forecast. The B2H project will increase the transfer capability through eastern Oregon by 1,050 MW. This capacity will provide a regional benefit to the entire Northwest and specifically benefit load service to eastern Oregon and southern Idaho. It is possible this added capacity resulting from the B2H project could be used to serve additional demand in Union and Umatilla counties. Portions of Baker County are served by Idaho Power, including the communities of Durkee and Huntington. BPA currently provides energy to Oregon Trails Electric Cooperative (“OTEC”), which serves Baker City via transmission connections between the Northwest and Idaho Power’s transmission system. The existing transmission connections between the Northwest and Idaho Power are fully utilized for existing load commitments, with very little ability to meet load growth requirements. The B2H project associated increased transmission connectivity between the Northwest and Idaho Power will allow BPA to serve additional demand in Baker City. Finally, additional transmission capacity can create opportunities for new energy resources, which can add to the county tax base and create new jobs. Q.Are there any additional benefits you have not discussed?A.The B2H project will also provide local area electrical benefits. La Grande and Baker City are served by OTEC. Portions of Morrow County and Umatilla County are served by Umatilla Electric Cooperative (“UEC”) and Columbia Basin Electric Cooperative (“CBEC”). OTEC, UEC, and CBEC pay BPA’s network transmission rate to receive transmission service from the BPA system. As I discussed earlier in my testimony, BPA kicked off a public process related to the B2H project on January 5, 2023, presenting BPA’s business case that shows B2H is a cost-effective solution to meet BPA customer needs. Correspondingly, given the sharing of BPA’s transmission costs among all of BPA’s transmission customers, OTEC, UEC, and CBEC customers would also benefit from this long-term cost-effective solution.VI. RISK ASSOCIATED WITH THEB2H PROJECTQ.Are there any risks associated with the B2H project?A. Risk is inherent in any infrastructure development project. As mentioned earlier in my testimony, as part of the 2021 IRP, Idaho Power evaluated capacity risk, cost risk, and in-service date risk extensively. The capacity risk analysis evaluated the impact on portfolio costs in the event that the Company cannot access the fully expected capacity of B2H. The cost risk was evaluated by performing a tipping point analysis. And finally, the Company evaluated the impacts of a 2027 in-service date, a year later than expected. Q.How was the capacity risk analysis performed?A.The B2H project capacity evaluation looked at portfolio costs assuming the Company can access 350 MW, 400 MW, 450 MW, 500 MW (equivalent to the preferred portfolio), and 550 MW of capacity. The sensitivities performed with capacity amounts less than 500 MW are set up to evaluate risk related to reduced market access. The 550 MW capacity amount sensitivity quantifies potential benefits associated with leveraging additional market purchases to avoid the need for a new resource. To evaluate the impact of different B2H capacity levels, the Company added or subtracted comparable capacity in the form of battery storage (the least-cost alternative to providing sufficient amounts of capacity) to maintain an adequate planning margin, while maintaining the same cost of B2H to reflect that B2H’s capacity contribution toward the planning margin is reduced with no offsetting cost reduction. The results indicated that even with a substantially reduced planning margin contribution, B2H portfolios remain cost-effective. Additionally, if Idaho Power is able to access an additional 50 MW from the Mid-C hub, that may present a cost-saving opportunity for customers.Q.What did the cost risk evaluation conclude?A.A transmission line such as B2H requires significant planning, organization, labor, and material over a multi-year process to complete and place in-service. Therefore, it is important to evaluate cost risks when planning for such a project. Idaho Power evaluated the cost of the B2H project assuming no contingency, a 10 percent contingency, a 20 percent contingency, and a 30 percent contingency. The results indicated the B2H project would have to increase significantly beyond a 30 percent contingency before the project would no longer be cost-effective, i.e., the tipping point is well beyond a reasonable 30 percent contingency bookend. As I discussed earlier, if the actual costs were to reach these levels, it is likely that other comparable resources, and alternative transmission facilities such as Gateway West, would have their own increases in costs as well.Q.Please explain the in-service date risk evaluation.A.The current planned in-service date for B2H is prior to the summer of 2026, which is necessary to meet the peak demand growth needs. Should the B2H in-service date slip to 2027, other new resources will be required in 2026. Slippage in the schedule from 2026 to 2027 is a possibility and would require new resources, however, as the 2021 IRP preferred portfolio demonstrates, the B2H project remains the most cost-effective long-term resource.Q.Were there any additional risk analyses performed with respect to the B2H project?A.Yes. Idaho Power also performed a liquidity and market sufficiency risk analysis. As explained earlier in my testimony, the Pacific Northwest is a winter peaking region and Idaho Power operates a system with a summer peak which aligns with the Mid-C hydro runoff conditions when the Pacific Northwest is flush with surplus power capacity. However, the existing transmission system between the Pacific Northwest and the Company is constrained. Constructing the B2H project will alleviate this constraint and add 1,050 MW of total transfer capability between the Pacific Northwest and the Intermountain West region. To evaluate the market sufficiency, Idaho Power assessed five different data points. The first data point was a peak load analysis. British Columbia and other utilities in the Pacific Northwest have forecast 2030 winter peaks that exceed their forecast 2030 summer peaks by a combined 8,200 MW. Given the difference in seasonal peaks, coupled with Columbia River runoff hydro conditions aligning with the Company’s summer peak, resource availability in the Pacific Northwest during Idaho Power’s summer peak is highly likely. For the second data point, the Company reviewed a recent resource adequacy assessment performed by BPA that evaluated resource adequacy from 2021 through 2030.Idaho Power concluded from this analysis that: (1) summer capacity will be available in the future, and (2) additional summer capacity will likely be added as the region adds resources to meet winter peak demand. Next, Idaho Power gathered peak load data for the major Pacific Northwest entities in Washington and Oregon to compute the peak coincident load. The results illustrated a wide difference between historical winter and summer peaks.The fourth data point evaluated the Renewable Portfolio Standard (RPS) goals by states such as California, Oregon and Washington which will drive policy-driven resource additions, and likely result in more solar generation and additional dispatchable flexible ramping resources, such as battery storage. Solar and solar plus storage align very well with summer peak needs, but their value can be limited in the winter months. Meeting winter needs will require the Pacific Northwest region to overbuild these resources above the level to meet a similar summer demand, likely aligning well with the Company looking to access summer energy needs from the market.Finally, the fifth data point evaluated the potential new resources reported by northwest utilities in their IRPs. The list of resources includes 6,389 MW of planned new resources through 2031. As expected, the Northwest utilities are continuing to plan for growing winter peak demands by adding capacity resources, furthering the depth of the market for the summer season. All data points demonstrate that there will be sufficient market resources in the future to utilize the B2H transmission line. VII. CONCLUSIONQ.Please summarize your testimony.A.B2H has been a cost-effective resource identified in each of Idaho Power’s IRPs since 2009 and continues to be a cornerstone of Idaho Power’s 2021 IRP preferred portfolio. In the 2021 IRP, as has been the case in prior IRPs, the B2H project is not simply evaluated as a transmission line, but rather as a resource that will be used to serve Idaho Power load. That is, the B2H project, and the market purchases it will facilitate, is evaluated in the same manner as a new gas power plant, or a new utility-scale solar plus storage project.As a resource, the B2H project is demonstrated to be the most cost-effective method of serving projected customer demand and meeting clean energy goals. As can be seen in the 2021 IRP, the lowest-cost resource portfolio includes B2H, and the best non-B2H portfolio has a significant cost premium. As a resource alone, the B2H project is the lowest-cost alternative to serve the Company’s customers in Oregon and Idaho. As a transmission line, B2H also offers incremental ancillary benefits and additional operational flexibility.The B2H project is nearing its construction phase and project certainty continues to grow. Idaho Power, PacifiCorp, and BPA executed a Term Sheetin early 2022 and have drafted definitive agreements, ready or near ready for signature, associated with the provisions of the Term Sheet. The agreements address the Parties’ capacity needs, strategies, and goals associated with the B2H project. The Company has extensively evaluated the B2H project as a supply-side resource, explored many of the ancillary benefits offered by the transmission line, and considered the risks and benefits of owning a transmission line connected to a market hub in contrast to direct ownership of a traditional generation resource. Once operational, the B2H project will provide Idaho Power increased access to reliable, clean, low-cost market energy purchases from the Pacific Northwest. In addition, the B2H project will increase the efficiency, reliability, and resiliency of the electric system by creating an additional pathway for energy to move between major load centers in the West. The benefits in aggregate reflect the B2H project’s importance to the Company’s commitment to reliability and affordability.Q.Does this complete your testimony?A.Yes, it does.////////////////////DECLARATION OF JARED L. ELLSWORTHI, Jared L. Ellsworth, declare under penalty of perjury under the laws of the state of Idaho:1.My name is Jared L. Ellsworth. I am employed by Idaho Power Company as the Transmission, Distribution & Resource Planning Director for the Planning, Engineering & Construction Department. 2.On behalf of Idaho Power, I present this pre-filed direct testimony and Exhibit Nos. 1 through 7 in this matter.3.To the best of my knowledge, my pre-filed direct testimony and exhibits aretrue and accurate.I hereby declare that the above statement is true to the best of my knowledge and belief, and that I understand it is made for use as evidence before the Idaho Public Utilities Commission and is subject to penalty for perjury.SIGNED this 9thday of January2023, at Boise, Idaho.Signed: