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HomeMy WebLinkAbout20220429Ellsworth Direct.pdf BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF IDAHO POWER COMPANY’S APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY TO ACQUIRE RESOURCES TO BE ONLINE BY 2023 TO SECURE ADEQUATE AND RELIABLE SERVICE TO ITS CUSTOMERS. ) ) ) ) ) ) ) ) CASE NO. IPC-E-22-13 IDAHO POWER COMPANY DIRECT TESTIMONY OF JARED L. ELLSWORTH ELLSWORTH, DI 1 Idaho Power Company Q. Please state your name, business address, and 1 present position with Idaho Power Company (“Idaho Power” or 2 “Company”). 3 A. My name is Jared L. Ellsworth and my business 4 address is 1221 West Idaho Street, Boise, Idaho 83702. I 5 am employed by Idaho Power as the Transmission, 6 Distribution & Resource Planning Director for the Planning, 7 Engineering & Construction Department. 8 Q. Please describe your educational background. 9 A. I graduated in 2004 and 2010 from the 10 University of Idaho in Moscow, Idaho, receiving a Bachelor 11 of Science Degree and Master of Engineering Degree in 12 Electrical Engineering, respectively. I am a licensed 13 professional engineer in the State of Idaho. 14 Q. Please describe your work experience with 15 Idaho Power. 16 A. In 2004, I was hired as a Distribution 17 Planning engineer in the Company’s Delivery Planning 18 department. In 2007, I moved into the System Planning 19 department, where my principal responsibilities included 20 planning for bulk high-voltage transmission and substation 21 projects, generation interconnection projects, and North 22 American Electric Reliability Corporation’s (“NERC”) 23 reliability compliance standards. I transitioned into the 24 Transmission Policy & Development group with a similar 25 ELLSWORTH, DI 2 Idaho Power Company role, and in 2013, I spent a year cross-training with the 1 Company’s Load Serving Operations group. In 2014, I was 2 promoted to Engineering Leader of the Transmission Policy & 3 Development department and assumed leadership of the System 4 Planning group in 2018. In early 2020, I was promoted into 5 my current role as the Transmission, Distribution and 6 Resource Planning Director. I am currently responsible for 7 the planning of the Company’s wires and resources to 8 continue to provide customers with cost-effective and 9 reliable electrical service. 10 Q. What is the purpose of your testimony in this 11 case? 12 A. The purpose of my testimony is to present the 13 load and resource balance utilized in the Integrated 14 Resource Plan (“IRP”) development and the identification of 15 Idaho Power’s 2023 capacity deficit. I will describe the 16 evaluation of potential solutions for meeting the capacity 17 deficiency. Finally, I will provide support for the 18 acquisition of new resources to address identified near-19 term peak capacity needs. 20 I. BACKGROUND 21 Q. What is the goal of the IRP? 22 A. The goal of the IRP is to ensure: (1) Idaho 23 Power’s system has sufficient resources to reliably serve 24 customer demand and flexible capacity needs over a 20-year 25 ELLSWORTH, DI 3 Idaho Power Company planning period, (2) the selected resource portfolio 1 balances cost, risk, and environmental concerns, (3) 2 balanced treatment is given to both supply-side resources 3 and demand-side measures, and (4) the public is involved in 4 the planning process in a meaningful way. Historically, 5 the Company developed resource portfolios to eliminate 6 resource deficiencies identified in a 20-year load and 7 resource balance. 8 Q. Please explain the “load and resource 9 balance.” 10 A. The load and resource balance is the Company’s 11 tabulated plan that identifies resource deficiencies during 12 the 20-year IRP planning horizon. It incorporates the 13 expected availability of Idaho Power’s existing resources, 14 comparing the total output to the Company’s forecasted 15 load, and illustrates the resulting surplus or deficit by 16 month. This will identify the Company’s first resource 17 need date, or the point at which Idaho Power’s reliability 18 requirements may not be met. The availability of existing 19 resources, including Public Utility Regulatory Policies Act 20 (“PURPA”) projects, power purchase agreements, hydro, coal, 21 gas, demand response, and market purchases, is determined 22 using a number of factors such as expected stream flows, 23 plant run times, forced outages, and transmission 24 availability, among other considerations. 25 ELLSWORTH, DI 4 Idaho Power Company Q. What is the purpose of the load and resource 1 balance? 2 A. The load and resource balance helps ensure 3 Idaho Power has sufficient resources to meet projected 4 customer demand plus a margin to account for extreme 5 conditions, reserves, and resource outages. It is critical 6 when comparing future resource portfolios that each plan 7 achieve at least a base reliability threshold. 8 Q. Have previous load and resource balance 9 results indicated Idaho Power will be resource sufficient 10 in the near-term? 11 A. Yes. The Company has been generally resource-12 sufficient since the addition of the Langley Gulch natural-13 gas fired power plant almost a decade ago. The load and 14 resource balance from the Second Amended 2019 IRP did not 15 show a capacity deficiency occurring until the summer of 16 2028. However, Idaho Power has rapidly moved from an 17 expected resource-sufficient position through 2028, to a 18 near-term capacity deficiency starting in 2023, resulting 19 in the need to rapidly acquire resources as discussed in 20 the Company’s request in this case. 21 II. LOAD AND RESOURECE BALANCE MODIFICATIONS 22 Q. When did Idaho Power identify that there was a 23 resource deficiency starting in 2023? 24 ELLSWORTH, DI 5 Idaho Power Company A. The Company first identified a 2023 resource 1 deficiency in the spring of 2021 while refreshing the load 2 and resource balance during development of a Valmy Unit 2 3 exit analysis, as directed by the Commission in Order No. 4 34349, Idaho Power’s request to update rates to reflect the 5 accelerated depreciation associated with an early exit from 6 coal-fired operations at Valmy, Case No. IPC-E-19-08. 7 The Company filed this request on June 27, 2019; 8 however, during processing of the case, Idaho Power 9 determined that further review of the 2019 IRP modeling, 10 which was used to develop the Valmy Unit 2 exit analysis, 11 was necessary and the case schedule was suspended while the 12 review was performed. The Company completed its review of 13 the 2019 IRP modeling and filed its Second Amended 2019 IRP 14 in October 2020. Following the filing of the Second Amended 15 2019 IRP, in the first quarter of 2021, Idaho Power began 16 preparing the required Valmy Unit 2 exit analysis, which 17 included an evaluation of system reliability. This analysis 18 was performed simultaneously with preparation of the 2021 19 IRP, and the refreshed load and resource balance was 20 further refined through the remainder of the development of 21 the 2021 IRP. 22 Q. Did Idaho Power make any adjustments to the 23 load and resource balance used in the Second Amended 2019 24 ELLSWORTH, DI 6 Idaho Power Company IRP as a result of the review performed as part of the 1 Valmy Unit 2 exit analysis? 2 A. Yes. The load and resource balance was 3 updated to include modifications to existing resource 4 availability, as is standard when developing the load and 5 resource balance as part of the IRP process. 6 Q. Please describe the modifications to the 7 existing resource availability. 8 A. First, the Company identified changes to its 9 market purchase assumptions. Additionally, the existing 10 resource availability was revised to include updated 11 thermal capacity and reduced demand response capacity 12 determined through the refinement of its reliability 13 evaluation. The net change between the Second Amended 2019 14 IRP and the updated load and resource balance used for the 15 Valmy Unit 2 exit analysis was a reduction of approximately 16 480 MW - 500 MW in available capacity each July during the 17 2022 through 2025 time period. 18 Market Purchase Assumptions 19 Q. What market purchase assumptions were used to 20 develop the load and resource balance used for the Second 21 Amended 2019 IRP? 22 A. To explain the market purchase assumptions, it 23 is necessary to first describe the regional transmission 24 market in general. Transmission lines connect Idaho Power 25 ELLSWORTH, DI 7 Idaho Power Company to wholesale energy markets and help economically and 1 reliably mitigate variability of intermittent resources 2 through the transfer of electricity between utilities, not 3 only to serve load, but also to share operating reserves. 4 The Company experiences its peak load at different times of 5 the year compared to most Pacific Northwest utilities. As 6 a result, Idaho Power can purchase energy from Mid-C during 7 its peak and sell excess energy to the Pacific Northwest 8 utilities during their peak. Although energy is plentiful 9 at the Mid-C market, imports from Mid-C are frequently 10 limited by transmission availability. The proposed Boardman 11 to Hemingway (“B2H”) project would greatly increase this 12 transmission capacity, but the Company does not anticipate 13 the B2H project being in-service earlier than 2026. 14 Q. What transmission paths are available to Idaho 15 Power to bring in energy? 16 A. The Company typically imports energy from Mid-17 C during the summer months from the west on the Idaho to 18 Northwest transmission path. A portion of this 19 transmission capacity is reserved by BPA to serve its 20 southern Idaho customers. Energy can be brought in from 21 Mid-C via Montana on the Idaho to Montana path as well, 22 which consists of two lines connecting Montana to the 23 Northeast of the Company’s system. South of Idaho are the 24 ELLSWORTH, DI 8 Idaho Power Company Mead, Palo Verde, and Four Corners market hubs, 1 collectively referred to as the Southern Hubs. 2 Q. Does Idaho Power purchase energy from the 3 Southern Hubs? 4 A. Yes, but less frequently since the southern 5 utilities are also summer peaking. Simultaneous demand 6 increases in the intermountain region can create 7 unfavorable pricing. In addition, a purchase from the 8 Southern Hubs will often require multiple transmission 9 wheels that can be difficult to obtain due to transmission 10 availability constraints. The Idaho to Sierra path, the 11 path that energy from the Valmy 345 kV line connects to, 12 and the Idaho to Utah path, which has more line 13 interconnections, also run to the south of Idaho Power’s 14 transmission system. However, currently there is no firm 15 transmission capacity available across NV Energy’s 16 transmission system, and other than an existing 50 MW Idaho 17 Power reservation across the PacifiCorp East system, there 18 is limited availability through Utah. 19 Q. Were market purchase assumptions updated 20 during the development of the Valmy study load and resource 21 balance compared to the market purchase assumptions used in 22 the Second Amended 2019 IRP? 23 A. Yes. Market conditions changed dramatically 24 in the south due to ripple effects from the energy 25 ELLSWORTH, DI 9 Idaho Power Company emergency event in California in August 2020 (“August 2020 1 event”), requiring an update to the market purchase 2 assumptions used for the load and resource balance in the 3 Second Amended 2019 IRP. 4 Q. What happened during the August 2020 event? 5 A. During August 2020, the west experienced a 6 heat wave, increasing the demand for energy and causing 7 several balancing authorities across the Western 8 Interconnection to declare energy emergencies. Generation 9 was not able to meet demand in California and transmission 10 capacity was strained, limiting California’s ability to 11 import energy. As a result, the California Independent 12 System Operator was required to curtail customer demand to 13 maintain reliability and the security of the bulk power 14 system. 15 Understanding the importance of transmission 16 availability during times of high electricity demand, 17 entities began reserving transmission capacity across the 18 west, including just outside the Company’s border, 19 significantly limiting Idaho Power’s access to market hubs. 20 Idaho Power’s own transmission service queue was flooded 21 with multi-year requests with third-party marketing firms 22 looking to move energy from Mid-C across Idaho Power’s 23 transmission system to the south. The transmission service 24 ELLSWORTH, DI 10 Idaho Power Company requests have added to an already constrained transmission 1 market limiting the Company’s access to Mid-C. 2 Q. What market purchase assumptions used in the 3 load and resource balance for the Second Amended 2019 IRP 4 did the Company update in the load and resource balance 5 used for the Valmy Unit 2 exit analysis? 6 A. A key assumption used to develop the load and 7 resource balance for the Second Amended 2019 IRP was that 8 Idaho Power’s exit from coal-fired operations at Valmy 9 would free up transmission capacity for imports to Idaho 10 from the Southern Hubs. To reflect the recent market 11 changes, the Company eliminated this key assumption, and 12 assumed Idaho Power could only rely on access to the 13 Southern Hubs to provide 50 MW of capacity in the summer 14 months. 15 Q. Did Idaho Power test the possibility of a 16 market import to help meet reliability requirements? 17 A. Yes. The Company issued an RFP on April 26, 18 2021, for the delivery to Idaho of firm capacity and energy 19 during the summer months through 2025 to help determine 20 whether transmission availability exists to import from the 21 market to maintain reliability and at a price that is 22 economical. However, Idaho Power received no bids, 23 indicative of evolving market conditions. 24 ELLSWORTH, DI 11 Idaho Power Company Q. What was the net reduction in transmission 1 capacity availability incorporated into the updated load 2 and resource balance for the analysis review period? 3 A. For the years 2022 through 2025, Idaho Power 4 reduced the transmission availability within the load and 5 resource balance by approximately 140 MW to 277 MW during 6 the peak load month of July. 7 Planning Margin Assumptions 8 Q. What is Idaho Power’s planning margin? 9 A. The Company’s planning margin is intended to 10 provide a sufficient generation resource reliability margin 11 to prevent the need to curtail customer demand. The 12 planning margin is intended to cover (1) Idaho Power’s 13 contingency reserve obligation, (2) severe weather events, 14 both extreme heat and extreme cold, (3) poor water 15 conditions, and (4) planned and unplanned resource and 16 transmission outages. 17 Q. How did the Company compute the planning 18 margin in the Second Amended 2019 IRP? 19 A. In the Second Amended 2019 IRP, Idaho Power 20 established a 15 percent planning margin. Planning margin 21 was calculated as 15 percent of the Company’s average (50th 22 percentile) peak demand forecast for each month. For 23 example, if Idaho Power had a peak-hour-load of 3,500 MW, 24 ELLSWORTH, DI 12 Idaho Power Company the Company would add the planning margin and target 4,025 1 MW of resource capacity (3,500 multiplied by 1.15). 2 Q. Did Idaho Power consider any enhancements to 3 the planning margin utilized in the Second Amended 2019 IRP 4 to meet reliability requirements as part of the Valmy Unit 5 2 exit analysis? 6 A. Yes. Following the development of the Second 7 Amended 2019 IRP, the Company looked to refine its planning 8 margin to ensure consideration of issues specific to Idaho 9 Power’s system. A simple 15 percent planning margin was 10 utilized in the Second Amended 2019 IRP. Individual 11 utilities experience varying frequencies of demand 12 extremes, forced outage rates among resources, and resource 13 size compared to load size, all of which should be 14 considered when determining the planning margin. Rather 15 than continue to utilize the 15 percent planning margin, 16 the Company used more sophisticated probabilistic methods 17 in the Valmy Unit 2 exit analysis to determine system needs 18 to ensure reliability for all hours of the day on the 19 Company’s system, referred to as the Loss of Load 20 Expectation (“LOLE”) method. 21 Q. What is the LOLE approach for determining the 22 planning margin to meet reliability requirements? 23 A. The LOLE approach allows for a comparison of 24 load to generation on an hourly basis over a specified 25 ELLSWORTH, DI 13 Idaho Power Company period. A common industry practice is to plan the power 1 system such that it has no more than one loss of load event 2 per 10 years, or an LOLE of 0.1 days per year1. The Company 3 used a 0.1 days per year LOLE in the Valmy Study. In the 4 2021 IRP, given feedback from the IRP Advisory Council, and 5 the increased frequency of extreme events, including 6 extreme water conditions, among other variables, the 7 Company ultimately aligned with the Northwest Power and 8 Conservation Council standard of no more than one loss of 9 load event per 20 years, or an LOLE of 0.05 days per year. 10 An LOLE of 0.05 days per year yields a planning margin of 11 approximately 15.5 percent. Idaho Power believes the LOLE 12 method’s hourly approach fully considers the reliability 13 value of renewable resources over time compared to the 14 previous method. 15 Q. Aside from taking a more granular hourly 16 approach, are there other components of the LOLE method 17 that impacted the Company’s determination of resource 18 needs? 19 A. Yes. The LOLE method also evaluates the 20 ability of existing resources to meet peak demand through 21 the determination of Effective Load Carrying Capability 22 (“ELCC”). 23 1 The Southwest Power Pool, PJM Interconnection, and the Midcontinent Independent System Operator are among those that use this probabilistic approach. ELLSWORTH, DI 14 Idaho Power Company Q. Did the use of the ELCC result in any changes 1 to the peak-serving capability of Idaho Power’s existing 2 resources? 3 A. Yes. When analyzing Idaho Power’s system on an 4 hour-by-hour basis, the results indicated the ability of 5 its existing demand response programs to meet peak load 6 under the changing dynamics of Idaho Power’s system was 7 significantly lower than previously assumed. This is 8 primarily the result of increased solar resources on the 9 Company’s system pushing net peak load hours outside the 10 longstanding demand response program dispatch window of 1 11 PM to 9 PM. 12 Q. Did the Company use the LOLE approach when 13 determining reliability requirements for the 2021 IRP? 14 A. Yes, the LOLE approach was also used for 15 meeting reliability requirements over the 20-year planning 16 horizon in development of the 2021 IRP. For purposes of 17 the Valmy Unit 2 exit analysis, Idaho Power performed the 18 LOLE analysis for the years 2023 and 2025. 19 Q. What capacity deficit was identified as a 20 result of the LOLE study performed for 2023? 21 A. Utilizing the new ELCC values and the updated 22 transmission assumptions, the load and resource balance 23 showed a deficit of 381 MW in July 2023 assuming the early 24 exit of Valmy Unit 2 and one unit at the Jim Bridger Power 25 ELLSWORTH, DI 15 Idaho Power Company Plant (“Bridger”) at year-end 2022, and the addition of 1 Jackpot Solar in 2023. 2 Other Assumptions 3 Q. Were any additional assumptions modified as 4 part of the development of the load and resource balance 5 for the Valmy Unit 2 exit analysis? 6 A. Yes. The peak load forecast was updated with 7 the latest expectations for 2023 through 2025. Although 8 relatively immaterial, the 2023 through 2025 peak load 9 expectations were approximately 8 MW greater than 10 anticipated in prior years for a total capacity deficit of 11 389 MW in July 2023.2 12 Q. Based on the results of load and resource 13 balance due to the revised assumptions, what was Idaho 14 Power’s conclusion? 15 A. After refining the load and resource balance, 16 it is clear that Idaho Power is unable to meet reliability 17 requirements if participation in coal-fired operations of 18 both Valmy Unit 2 and a Bridger unit cease in 2022 without 19 an alternate source of peak capacity. The Company 20 determined it needed to keep both Valmy Unit 2 and all 21 Bridger units through 2023. 22 2 Assuming the early exit of Valmy Unit 2 and one unit at Bridger at year-end 2022, and the addition of Jackpot Solar in 2023. ELLSWORTH, DI 16 Idaho Power Company Q. What was the final capacity deficiency 1 identified for 2023 as a result of the previously discussed 2 analyses? 3 A. The load and resource balance utilized in the 4 development of the Valmy Unit 2 exit analysis identified a 5 78 MW capacity deficit in 2023. 6 Q. Were any changes made to the load and resource 7 balance used for the 2021 IRP process? 8 A. Yes. Subsequent to the completion of the 9 Valmy Unit 2 exit analysis in May 2021, the Company 10 continued to update its load and resource balance through 11 the 2021 IRP, resulting in an increase to the expected 2023 12 capacity deficit from 78 MW to 101 MW. A number of factors 13 drove this increase including, but not limited to: (1) 14 greater load growth projections, (2) revisions to the 15 aforementioned LOLE from 0.1 days per year to 0.05 days per 16 year, (3) updates to expected capacity of the Company’s 17 demand response programs, (4) further refinement of the 18 ELCC’s of variable resources, and (5) limiting “market 19 purchases” to only transmission secured across third-party 20 transmission providers to a market hub, among other items. 21 III. MEETING THE CAPACITY DEFICIENCY 22 Q. Has the Company taken actions to acquire 23 resources to meet the 2023 capacity deficit? 24 ELLSWORTH, DI 17 Idaho Power Company A. Yes. Under Idaho law, Idaho Power has an 1 obligation to provide adequate, efficient, just, and 2 reasonable service on a nondiscriminatory basis to all 3 those that request it within its certificated service area.3 4 In order to meet its obligations to reliably serve customer 5 load, and given the extremely short turn-around to 6 construct a resource to meet a summer 2023 deficit, 7 particularly in the midst of supply chain disruption, 8 ongoing COVID-19 impacts, and constraints in the industry 9 and in ancillary industries, on June 30, 2021 the Company 10 conducted a competitive solicitation through a Request for 11 Proposals (“RFP”) seeking to acquire up to 80 MW of peak 12 capacity resources to meet the 2023 capacity deficit - 13 seeking projects to be online by June of 2023. 14 Company witness Eric Hackett will discuss in greater 15 detail the development of the RFP, the issuance of the RFP, 16 and the evaluation of the RFP responses, as well as the 17 investigation into potential Company-owned and constructed 18 battery storage opportunities in his testimony. 19 Q. Did Idaho Power evaluate any alternative 20 solutions for meeting the 2023 capacity deficiency to avoid 21 building a new resource? 22 A. Yes. Idaho Power investigated several 23 alternative options for meeting the identified capacity 24 3 Idaho Code §§ 61-302, 61-315, 61-507. ELLSWORTH, DI 18 Idaho Power Company deficits, including possible modifications to existing 1 demand response programs, expansion of the existing pricing 2 programs, and the potential for other short-term market 3 solutions. None of those alternative options proved to be 4 viable at this time. 5 Q. What was the result of Idaho Power’s 6 investigation into potential modifications to the existing 7 demand response programs? 8 A. As I mentioned earlier, when analyzing Idaho 9 Power’s system on an hour-by-hour basis, the results 10 indicated that under current program parameters, the ELCC 11 of the existing 380 MW demand response portfolio is 12 estimated to be approximately 17 percent. That is, of the 13 total 380 MW demand response portfolio capacity, only 65 MW 14 can be relied upon to meet the highest-risk Loss-of-Load 15 Probability (“LOLP”) hours, or the statistical likelihood 16 of the system demand exceeding the available generating 17 capacity during a given time period, typically an hour. 18 The existing demand response programs, as structured, were 19 not effective at meeting system needs over the planning 20 horizon. 21 Q. Did the Company evaluate what modifications 22 could be made to the demand response program parameters to 23 more effectively meet future high-risk LOLP hours? 24 ELLSWORTH, DI 19 Idaho Power Company A. Yes. Idaho Power evaluated potential 1 modifications to program parameters in an attempt to better 2 align the resource with system needs. The Company 3 conducted several sensitivity analyses to determine the 4 parameter adjustments needed to more effectively meet the 5 high-risk LOLP hours. The Company identified several 6 program criteria, including events per week, events per 7 season, time available, length of program season, and total 8 hours dispatched per week, and then evaluated the impact to 9 the ELCC of the demand response portfolio. The sensitivity 10 analyses concluded that the dispatch times available and 11 the length of the program season had the highest impact on 12 the ELCC of demand response. 13 Q. Did Idaho Power file a request with the 14 Commission to modify its demand response programs based on 15 these evaluations? 16 A. Yes. On October 1, 2021, following completion 17 of the evaluation, the Company filed a request in Case No. 18 IPC-E-21-32 to modify several demand response programs to 19 address the changes in system need and operations. On 20 March 4, 2022, the Commission issued Order No. 35336, 21 approving Idaho Power’s proposed modifications to the 22 demand response programs, and tariff revisions, to be 23 effective prior to the 2022 demand response season that 24 begins June 15, 2022. 25 ELLSWORTH, DI 20 Idaho Power Company Q. What resource potential does demand response 1 provide? 2 A. As part of the rigorous examination of the 3 potential for expanded demand response, the Company 4 utilized a Northwest Power and Conservation Council 5 (“NWPCC”) assessment of demand response potential in the 6 Northwest. Based on this assessment Idaho Power estimated 7 584 MW of demand response potential within the Company’s 8 service area. With the assumed reduction in participation 9 beginning in 2022 as a result of the demand response 10 program modifications approved with Order No. 35336, the 11 380 MW nameplate capacity was adjusted to 300 MW for 2022. 12 Q. What is the ELCC of the 300 MW demand response 13 portfolio using the parameters with the modifications? 14 A. The Company estimates the approximate ELCC of 15 a demand response portfolio with the modifications to be 16 58.5 percent, or approximately 176 MW, a 170 percent 17 improvement in effectiveness from current program 18 parameters. However, clarity on program subscription and 19 the resulting ELCC will not occur until mid-May 2022 20 providing some uncertainty around contribution to peak load 21 during the upcoming program seasons. 22 Q. How was demand response included in Idaho 23 Power’s 2021 IRP modeling? 24 ELLSWORTH, DI 21 Idaho Power Company A. The 2021 IRP modeling process included the 1 total 584 MW of demand response potential, with an estimate 2 of 300 MW of capacity from existing resources, and the 280 3 MW of additional demand response available for selection in 4 the AURORA long-term capacity expansion modeling. This 5 additional demand response capacity was divided into 20-MW 6 bundles per year for selection by the model up to the 7 threshold. 8 Q. Were any of these bundles selected in the 9 Preferred Portfolio of the 2021 IRP as a solution for 10 meeting the 2023 capacity deficit? 11 A. Yes. The 2021 IRP Preferred Portfolio 12 included an additional 100 MW of demand response that comes 13 in 20 MW bundles, in varying years: 20 MW in 2023, 20 MW in 14 2025, and the remaining 60 MW beyond 2037. However, it is 15 important to note that Idaho Power first identified the 16 2023 capacity deficit of 78 MW in March 2021, when the 2021 17 IRP was still in development, prior to finalizing the 18 demand response program evaluation and the filing with the 19 Commission of proposed changes. Recognizing the urgency of 20 the capacity deficit, the Company began work to develop and 21 process an RFP for 2023 peak capacity resources while the 22 2021 IRP was in development. So, while the results of the 23 2021 IRP indicate 20 MW of demand response is a cost-24 effective resource addition in 2023, it is insufficient 25 ELLSWORTH, DI 22 Idaho Power Company without other resources to ensure Idaho Power can provide 1 reliable and adequate electric service to customers. 2 Q. Did the evaluation of existing and potential 3 pricing programs identify any potential resource solutions? 4 A. No. The NWPCC assessment of demand response 5 also included the potential associated with pricing 6 programs, notably time-of-use (“TOU”) and critical peak 7 pricing (“CPP”), for possible peak shifting. The Company 8 currently has existing TOU offerings in both its Idaho and 9 Oregon jurisdictions, with 1,000 customers enrolled in the 10 Idaho offering and less than five customers enrolled in the 11 Oregon pilot program. With the level of customer 12 participation data, the sample used to develop a 13 comprehensive and reliable assessment of residential peak 14 shifting would be outside an acceptable margin of error 15 tolerance limit at approximately +/- 60 percent. As such, 16 circumstantial behavioral changes could misrepresent peak 17 shifting impacts when expanded to the full residential 18 customer class. Without comprehensive historical data from 19 a larger sample population, Idaho Power believes it is 20 premature to modify existing, or implement new pricing 21 programs as a potential resource solution to the 2023 22 capacity deficiency. 23 ELLSWORTH, DI 23 Idaho Power Company Q. Will Idaho Power continue to evaluate the TOU 1 program performance for possible peak shifting in the 2 future? 3 A. Yes. The Company continues to assess the TOU 4 programs and any potential modifications that could 5 encourage customer participation. In addition, Idaho Power 6 is actively evaluating the potential for a CPP offering. 7 At the direction of the Public Utility Commission of 8 Oregon, the Company will report the TOU pilot performance 9 and potential changes to the offering as well as the 10 potential for a CPP offering as part of its annual 11 Distribution System Planning report, beginning in the 12 summer 2022 report. 13 Q. What other potential short-term market 14 solutions did the Company pursue? 15 A. During preparation of the Valmy Unit 2 exit 16 analysis and identification of transmission constraints 17 requiring changes to load and resource balance assumptions, 18 the Company issued an RFP on April 26, 2021, for the 19 delivery of firm capacity and energy during the summer 20 months beginning 2023. The intent was to test the 21 transmission deliverability and resource market 22 availability of a replacement resource for Valmy Unit 2. 23 Idaho Power received no bids, indicative of the evolving 24 market conditions leading to the Company’s reduced 25 ELLSWORTH, DI 24 Idaho Power Company transmission import assumption in the load and resource 1 balance. 2 Q. Based on the lack of viable alternatives to 3 meet the near-term capacity deficits identified by the IRP 4 planning process, what actions has the Company taken to 5 ensure continued, safe, and reliable operations? 6 A. As detailed in Company witness Mr. Hackett’s 7 testimony, the RFP process resulted in the selection of a 8 40 MW solar PV plus 40 MW energy storage project, 9 consisting of a 20-year PPA associated with a 40 MW solar 10 PV facility that supplies energy to the Company’s system 11 combined with an Idaho Power-owned 40 MW battery storage 12 facility. In addition, the Company’s parallel investigation 13 into different configurations of grid-charged battery 14 energy storage systems identified a second capacity 15 resource: an Idaho Power-owned 80 MW battery storage 16 facility. The combined 120 MW of battery storage will 17 adequately address near-term capacity deficits and ensure 18 the Company is able to provide safe, reliable service to 19 its customers. 20 Q. Since the completion of the 2021 IRP, has the 21 Company continued to monitor other factors that could 22 influence the load and resource balance, and by extension, 23 Idaho Power’s resource need? 24 ELLSWORTH, DI 25 Idaho Power Company A. Yes. While the load and resource balance 1 prepared for an IRP is the primary source of information 2 used to inform resource procurement decisions, the Company 3 also recognizes that during the near-term resource 4 decision-making phase, the capacity deficit period can be 5 very fluid. As a result, it is important that the IRP load 6 and resource balance continue to be evaluated to also 7 consider near-term known changes, operational enhancements, 8 limitations, or constraints on the existing system, if any, 9 to adequately inform resource needs today. 10 Q. As part of this near-term evaluation, did the 11 Company identify any near-term known changes having the 12 potential to impact the need for new resources? 13 A. Yes. First, Idaho Power’s service area 14 continues to experience very high load growth. Based on 15 recent economic activity, the 2023 load forecast has 16 increased by 33 MW, or 38 MW after applying the 15.5 17 percent planning margin, when compared to the load forecast 18 used for the 2021 IRP. Also, in late 2021, an opportunity 19 arose for the Company to purchase 76 MW of energy delivered 20 to its border. On December 16, 2021, Idaho Power executed 21 an agreement for the delivery of 76 MW to Idaho Power’s 22 border, for the months June through September 2022 through 23 2024, seven days a week during heavy load hours. 24 ELLSWORTH, DI 26 Idaho Power Company Q. Does this short-term market purchase of 76 MW 1 have the potential to help address the deficit identified 2 in 2023? 3 A. Yes. The 76 MW market purchase will reduce 4 the projected capacity deficit identified in the load and 5 resource balance for 2023. However, because the 76 MW 6 purchase is for 2022 through 2024, this short-term purchase 7 only has the effect of deferring, not eliminating, the 8 growing resource need. 9 Q. Is Idaho Power aware of any factors that 10 contribute to operational enhancements, limitations, or 11 constraints on the Company’s system that would impact the 12 capacity deficit in 2023? 13 A. Yes. Idaho Power has identified some 14 incremental resource opportunities and constraints. The 15 Company plans to install a number of battery storage 16 systems at various distribution substations as a cost-17 effective resource, allowing the deferral of transformer 18 upgrades, and providing an additional 11 MW of four-hour 19 duration storage capacity. In addition, the Company has 20 identified cost-effective upgrades at two gas plants and 21 expects to gain approximately 20 MW of capacity. Finally, 22 a planned refurbishment of one hydro unit at the American 23 Falls facility will reduce the overall resource 24 availability by 30 MW during the summer of 2023. Similar 25 ELLSWORTH, DI 27 Idaho Power Company outages are planned at American Falls through the summer of 1 2025. 2 In addition to the known impacts to the 2023 3 capacity deficiency, there are three more factors that 4 could potentially impact the continued safe, reliable 5 operations of Idaho Power’s existing resources during the 6 summer of 2023. First, uncertainty exists around Bridger 7 Unit 2 operations beginning May 2022 and Bridger Unit 1 8 operations beginning January 1, 2023, and their ability to 9 help meet peak capacity needs until a resolution for 10 meeting Regional Haze compliance has been achieved. The 11 uncertainty at Bridger is further amplified by the 12 Environmental Protection Agency’s proposed expansion of its 13 Federal Implementation Plan Addressing Regional Ozone 14 Transport for the 2015 National Ambient Air Quality 15 Standards (CSAPR) to include the state of Wyoming, which 16 will establish NOx emissions budgets requiring fossil fuel-17 fired power plants such as Bridger to participate in an 18 allowance-based ozone season trading program beginning in 19 2023. 20 Second, one of the three Hells Canyon units, Unit 1 21 which has a name plate rating of approximately 150 MW, 22 recently experienced an outage unexpectedly due to an 23 internal fault and is now out of service indefinitely. The 24 Company has been unable to inspect the outaged unit due to 25 ELLSWORTH, DI 28 Idaho Power Company maintenance work nearing completion on Unit 3. Internal 1 faults often result in severe damage, and it is uncertain 2 whether Idaho Power will have this unit back online by 3 summer of 2023. Finally, those items, coupled with the 4 lack of clarity around demand response program contribution 5 to peak load discussed earlier in my testimony, contributes 6 to a very fluid capacity deficit period. 7 Q. Based on your evaluation of the near-term 8 factors having the potential to impact the load and 9 resource balance, what is your estimate of the resulting 10 surplus or deficit? 11 A. Given the various increments and decrements, 12 including the 120 MW of battery storage, to the load and 13 resource balance, the Company estimates that it will exceed 14 the 0.05 LOLE threshold by approximately 30 MW in 2023, net 15 of current, near-term factors. This slight capacity length 16 will become a capacity deficit if aforementioned 17 uncertainties around Bridger materialize, or Hells Canyon 18 Unit 1 remains out of service. However, if a capacity 19 length exists, Idaho Power will use the 30 MW to reduce 20 power purchases. 21 Q. Do you believe there is sufficient support for 22 the procurement of the combined 120 MW of battery storage 23 resources? 24 ELLSWORTH, DI 29 Idaho Power Company A. Yes, I do. The 120 MW of battery storage was 1 pursued and procured as a least cost/least risk method of 2 meeting the 2023 capacity deficit identified in the 3 Company’s 2021 IRP. The fluidity of the load and resource 4 balance, continued high load growth, and the risks 5 associated with resource availability in the near-term 6 further support this resource procurement. 7 Q. Will this resource procurement impact Idaho 8 Power’s need for additional resources in 2024? 9 A. The Company is currently evaluating its needs 10 for 2024 based on the various near-term factors, including: 11 (1) an additional year of load growth, (2) 72 MW of PURPA 12 solar contracts for incremental resources in Oregon that 13 have been executed, (3) the possible 30 MW of capacity 14 length in 2023, (4) implications of the Western Resource 15 Adequacy Program (WRAP), (5) greater certainty around 16 demand response program potential in late-spring of 2022, 17 and (6) evaluation of the resource need in 2025 and the 18 potential of spreading the acquisition over multiple years. 19 The Company will continue to monitor these near-term 20 operational factors and their potential impact on Idaho 21 Power’s need for additional resources in 2024. 22 // 23 // 24 // 25 ELLSWORTH, DI 30 Idaho Power Company IV. CONCLUSION 1 Q. Please summarize your testimony. 2 A. The load and resource balance was updated as 3 part of the Valmy Unit 2 exit analysis and again as part of 4 development of the 2021 IRP to include modifications to 5 existing resource availability ultimately identifying a 6 capacity need in 2023 of 101 MW. Idaho Power evaluated 7 potential solutions for meeting the capacity deficiency 8 that might avoid the need for a new supply-side resource, 9 but did not ultimately identify any viable options. In the 10 absence of such viable alternatives, the Company has 11 executed an agreement to procure a combined 120 MW of 12 battery storage resources to satisfy the identified 13 capacity need. To further inform its near-term resource 14 procurement decisions, the Company performed a supplemental 15 evaluation of currently known operational enhancements, 16 limitations, and constraints on the system that have the 17 potential to impact resource needs. The results of those 18 evaluations continue to support the near-term need for the 19 acquisition of 120 MW of peak capacity resources. 20 Q. Does this complete your testimony? 21 A. Yes, it does. 22 ELLSWORTH, DI 31 Idaho Power Company DECLARATION OF JARED L. ELLSWORTH 1 I, Jared L. Ellsworth, declare under penalty of 2 perjury under the laws of the state of Idaho: 3 1. My name is Jared L. Ellsworth. I am 4 employed by Idaho Power Company as the Transmission, 5 Distribution & Resource Planning Director for the Planning, 6 Engineering & Construction Department. 7 2. On behalf of Idaho Power, I present this 8 pre-filed direct testimony in this matter. 9 3. To the best of my knowledge, my pre-filed 10 direct testimony is true and accurate. 11 I hereby declare that the above statement is true to 12 the best of my knowledge and belief, and that I understand 13 it is made for use as evidence before the Idaho Public 14 Utilities Commission and is subject to penalty for perjury. 15 SIGNED this 29th day of April 2022, at Boise, Idaho. 16 17 Signed: 18 19