20210430Ellsworth Direct-Redacted.pdf

BEFORE THE IDAIIO PI'BI,IC UTUJITIES COMMISSION
rN THE II{ATTER OF TDA}IO POVfER
COMPANY'S APPLICATION FOR A
DETERMIT'IIATION ACKNOWIJEDGfNG ITS
NORTH VAIJT(Y POWER PI,AIiIT UNTT 2
EXIT DATE.
IDAITO POWER CO}dPAI\I1T
DIRECT TESTIMOI{ff
OF
'JARED L. ELLSWORTH
CASE NO. TPC-E-2L-L2
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a Please state your name, business address, and
present position
"Company").
with Idaho Power Company ("Idaho Power" or
A. My name is Jared L. Ellsworth and my business
address is L221 West Idaho Street, Boise, Idaho 83702. I
am employed by Idaho Power as the Transmission,
Distribution & Resource Planning Director for the Planning,
Engineering c Construction Department.
a. Please describe your educational background.
A. I graduated in 2004 and 2010 from the
University of Idaho in Moscow, Idaho, receiving a Bachelor
of Sci-ence Degree and Master of Engineering Degree in
Electrical Engineering, respectively. f am a licensed
professional engineer in the State of Idaho.
O. Please describe your work experience with
Idaho Power.
A. ln 2004, I was hired as a Distribution
Planning engineer in the Company's Delivery Planning
department. Tn 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 Reliabil-ity Corporation's (*NBRC")
reliability compliance standards. I transj-tioned into the
Transmission Policy & Development group with a similar
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1 ro1e, and in 2013, I spent a year cross-training with the
2 Company's Load Serving Operations group. In 2074, I was
3 promoted to Engineering Leader of the Transmissj-on Policy &
4 Development department and assumed leadership of the System
5 Planning group in 201-8. In early 2020, I was promoted into
6 my current role as the Transmission, Distri-bution and
7 Resource Planning Director. I am currently responsible for
8 the planning of the Company's wires and resources to
9 continue to provide customers with cost-effective and
10 reliable electrical service.
LL O. What is the purpose of your testimony in this
12 case?
13 A. The purpose of my testimony is to present the
14 near-term economic and reliability impact analyses
15 performed following Idaho Power's Second Amended 2079
1,6 Integrated Resource Plan (*IRP") that support an exit from
1-7 operations of Valmy Unit 2 in 2025 based on currently known
LB information.
1-9 a. What specific action j-s the Company requesting
20 of the ldaho Public Utilities Commission ("Commission") in
2L this case?
22 A. As directed by the Commission in Order No.
23 34349, Idaho Power is requesting the Commission acknowledge
24 its appropriate exit date from Valmy Unit 2 as December 31,
25 2025, based on information known today. The Company
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respectfully reguests a Commission order no later than
September 29, 2021-, to a11ow adequate time for notification
to plant operator IW Energy should the Commission determine
an earlier exit date of Valmy Unit 2 is appropriate.
I. BACKGROIIIID
O. Please describe the Valmy p1ant.
A. Valmy is a coal-fired power plant that
consists of two units and is located near Battle Mountain,
Nevada. Unit 1 went into service in 1981 and Unit 2
followed in 1985. Idaho Power owrrs 50 percent, or 284
megawattsl ("MW") (generator nameplate rating), of Va1my.
I{IV Energy is the co-owner of the plant with the remaining
50 percent ownership and operates the Valmy facility. IW
Energy and Idaho Power (col1ectively, the "Parties") work
jointly to make decisions regarding Va1my. The plant is
connected via a single 345 kil-ovol-t ("kV") transmission
line to the Idaho Power control area at the Midpoint
substation. Idaho Power owns the northbound capacity and
I{IV Energy owns the southbound capacity of this 1ine.
O. How have the Parties been operating Valmy?
A. Recently, Valmy has primarily operated as a
summer resource and only operates during the winter months
I For planning purposes, Idaho Power uses the net dependable
capability of 262 W. It should also be noted that the remaining
capacity avai-l-abl-e to Idaho Power is 134 MW due to the Company's exitof coal-fired operations at UniU 1 at year-end 2019.
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1 if driven by t,he market. For example, in 2OL9 when the
2 Mid-Columbia market hub (*Mid-C") prices were high, Valmy
3 was economically dispatched during the winter months to
4 meet load while the excess generation provided customers
5 benefits through off-system sales.
5 Q. What. are the current agreements under which
7 IIV Energy and Idaho Power own and operate Valmy?
I A. The ownership and operation of Valmy is
9 dicEated by three agreements: the Agreement for the
L0 Ownership of the North Valmy Power Plant Project
1L ("Ownership Agreement"), the Agreement for the Operation of
12 the North Valmy Power P1ant Project ("Operation
L3 Agreement"), both of which are dated December 12, L978, and
t4 the North Valmy Station Operating Procedures Crj-teria,
L5 dat,ed as of February 11, L993, between ldaho Power Company
L6 and Sierra Pacific Power Company, as amended by Amendment
17 No. L to the Operating Procedure Criteria for Valmy Coal
1-8 Diversion Procedures and Usage, dated as of .Tanuary 1, 201-2
L9 (collectively, the "Existing North Valmy Agreements").
20 Additionally, as presented in Case No. IPC-E-19-08, the
21- Parties entered into the North Valmy Project Framework
22 Agreement between I{IV Energy and ldaho Power dated as of
23 February 22, 2019 ("Framework Agreement"), memorializing
24 the terms and conditj-ons under which either partner may
25 elect exj-t of participation of Valmy by means of a 15 month
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1 notice. Commissi-on Order No. 34349 deemed the Framework
2 Agreement with NV Energy as prudent and commercially
3 reasonable.
4 O. What are the current end-of-Iife assumptions
5 used by the Parties for each Valmy unita
5 A. rn its 201,8 Update to the Life Span Analysis
7 Process of Valmy Units 1 and 2, I'[V Energy recommended
8 retirement dates of both units at year-end 2025.2 However,
9 on December 21, 201,8, in Docket No. l-8-05003, the Public
10 Utllities Commission of Nevada ("Nevada PUC' ) issued an
11 order adopting NV Energy's 2079-2038 Triennial Integrated
1,2 Resource P1an, 201,9-2021 Action P1an, and 201-9-2021 Energy
1-3 Supply P1an, all of which included an early retirement of
14 Unit 1 on December 31, 2021, under NV Energy's stated
15 conditions3. The end-of-Iife date for Unit 2 remained at
L6 Idaho Power, in the Settlement
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year-end 2025.4
approved by the Commission with Order No. 3377]-
Stipulation
in Case No.
l-8 IPC-E-1-6-24, agreed to use prudent and commercially
2 tppTication of Sierra Pacific Power Company d/b/a IW Energy and Nevada
Power Company d/b/a NV Energy for approvaT of its 2017-2036 TrienniaTIntegrated Resource Plan and 201-7-201-9 Energy SuppTy Plan, 201-6 Annual
Demand Side Management Update Report as it reTates to the AcEion PTanof its 20L6-2035 Integrated Resource Plan, and the second amendnent toits 20L6-2035 Integrated Resource Pl-an and 201-6-20L8 Action PLan to
incTude the acguisition of the South Point Energy Center, Docket No.
76-07001-. Updated Lite Span AnaTysis Process in compTiance with Order
dated February L6, 2017, filed on February 16, 2078.3 ,foint AppTication of Nevada Power Company d/b/a Nv Enerry and SierraPacific Power Company d/b/a NV Enerry for approwal of their 20L9-2038Triennial Integrated Resource PTan and 2079-2021- Enerry Supply P7an,
Docket No. 1-8-06003 (December 27, 20L8).a Nevada PUC Order dated December 2L, 201-8, DoctJnent ID 34967.
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Idaho Power Company
L reasonable efforts to end its participation in the
2 operation of Unit 1 by December 3L, 2019, and Unit 2 by
3 December 31, 2025.
4 O. Did Idaho Power's cessation of coal-fired
5 operations in Unit L occur?
6 A. Yes. On December 37, 2019, the Company's
7 participation in coal-fired operations at Unit L concluded.
8 The remaining capacity available to Idaho Power from Valmy
9 Unit 2 is L34 MW.
l-0 O. Does Commission Order No. 343495 address the
11 Company's proposed cessation of Unit 2 operations by
L2 December 3L, 2025?
13 A. Yes. Durlng review of Idaho Power's
1-4 Application in Case No. IPC-E-L9-08, Commission Staff
15 indicated that they reviewed the Company's Unit 2 closure
15 analysis but did not have adequate informatj-on from Idaho
1-7 Power at the time to determine whether the Company had
18 completed a thorough review of a unit withdrawal date of
1-9 December 3l-, 2025. Therefore, Order No. 34349 directed the
20 Company to use best efforts to file within Zt days of the
21- service date of the order: (1) an analysis validating the
22 December 31, 2025, economic retirement date of Unit 2, or
s rn the Matter of the AppTication of rdaho Power Company for
Authority to Increase fts Rates for Electric Service to Recover Costs
Associated with the North Vahny Plant, Case No. IPC-E-I-9-08 (May 31,
20L9) .
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L (2) an analysis supporting a different economic retirement
2 date of Unit 2.
3 Q. Did Idaho Power comply with the Commissi-on's
4 directi-ve in Order No. 34349?
5 A. Yes. On .Tune 27, 2019, the Company filed a
6 reguest for acknowledgement that it had sufficiently
7 validated the economic retj-rement date of Valmy Unit 2 as
8 year-end 2025 in Case No. IPC-E-l-9-l-8. However, during
9 processing of the case, the Company determined that further
10 review of Idaho Power's 20L9 IRP modeling was necessary.
11 Because the 2019 IRP modeling was also used to develop the
1,2 Valmy Unit 2 closure analysis, the case schedule was
13 suspended while the review was performed. The review of the
t4 201,9 IRP modeling ultimately resulted in the filing with
l-5 the Commisslon of Idaho Power's Second Amended 20L9 IRP.
16 O. Did the model updates performed for the Second
L7 Amended 201-9 IRP impact the Valmy Unit 2 closure analysis?
18 A. Yes. After performing a revised analysis
19 based on adjustments stemming from the IRP review, certain
20 modeling runs indicated the potential for additional
21, savings from a Valmy Unit 2 exit date as early as year-end
22 2022. However, the potential savings included a key
23 assumption that firm market purchases from the south of
24 Idaho Power's service area would be availabl-e to replace
25 Valmy Unit 2 capacity. This key assumption warranted
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further examination with regard to economics and
reliability. As such, Idaho Power withdrew its Application
in Case No. IPC-E-19-18 to perform the additional
evaluation of both the economic and reliability impacts of
an early Valmy Unit 2 closure. As initially directed by
Commission Order No. 34349, the Company is presenting the
results of the additional evaluation in this case.
II. THE SECOIID AMENDED 2019 IRP
O. What is the goal of the IRP?
A. As described in the Second Amended 2019 IRP,
Idaho Power believes the goal of the IRP is to ensure: (1)
Idaho Power's system has sufficlent 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.
O. How are the portfolios developed through the
IRP process?
A. Historically, the Company developed portfolios
to eliminate resource deficiencies identified in a 2l-year
load and resource balance. Under this process, Idaho Power
developed portfolios which were demonstrated to eliminate
the identified resource deficiencies. However, beginning
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1 with the Second Amended 2019 IRP, the Company began using
2 AURORA's long-term capacity expansion ("LTCE") modeling
3 capability to develop portfolios.6
4 O. Please describe the LTCE modeling capability
5 of AURORA.
5 A. In the Second Amended 2019 IRP, the LTCE
7 modeling capability of AURORA produced portfolios optimized
8 for the Western Electrlcity Coordinating Council (*V0ECC")
9 under various future conditions, such as varying natural
10 gas prices and carbon costs. The WECC-optimized portfolios
L1 included the addition of supply and demand-side resources
L2 for Idaho Power's system while sj-multaneously evaluati-ng
13 the economics of exiting from current generation units.
L4 O. What was the outcome of the modeling performed
15 Eo identify the Preferred Portfolio in the Second Amended
1.6 2OL9 IRP?
17 A. As part of this robust method of assessing
18 future resource options over a two-decade time frame, the
19 Preferred Portfolio was deri-ved from a combination of two
20 AURORA LlCE-produced portfolios that were manually
21- optimized for Idaho Power under Planning Gas and Planning
22 Carbon conditions wi-th the selection of the Boardman to
23 Hemingway (*B2H") transmissj-on 1ine. Although the AURORA
24 modeling consistently showed an economic exit of Valmy Unit
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6 Case No. IPC-E-19-19
l- 2 in 2025 in WECC-optimized runs, the refinement of these
2 analyses specific to Idaho Power's service area suggested
3 the potential for additional savings from earlier exit
4 dates.
5 O. What were the potential savings associated
6 with a 2022 Valmy Unit 2 exit as identified in the Second
7 Amended 2019 IRP?
8 A. The long-term analysis performed as part of
9 the Second Amended 20L9 IRP suggested net present value
L0 savings of approximately $3 million associated with a Valmy
11 Unit 2 exj-t in 2022 due to the avoided capital investment
1,2 and net operations and maintenance ("O&M") reductions
13 compared to a year-end 2025 exit.
1,4 O. fn the event of a Valmy Unit 2 exit prior to
l-5 2025, what are the notification reguirements under the
1,6 Framework Agreement?
1,7 A. Under the terms of the Framework Agreement, to
18 exit operations of Unit 2, Idaho Power is required to
19 provide IiIV Energy notice l-5 months in advance of the
20 Company's date to cease participation in coal-fired
2l operations. Therefore, for a year-end 2022 exit date,
22 Idaho Power would be required to provide I{tV Energy notice
23 by September 30, 2021.
24 O. Based on the results of the Second Amended
25 201-9 fRP, was it the recommendation of the Company to
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Idaho Power Company
1 proceed with providing NV Energy notice of cessation of
2 participation in coal-fired operations of Valmy Unit 2
3 based on the long-term analysis results?
4 A. No. As presented in the Second Amended 201-9
5 IRP, Idaho Power does not believe that the potential
5 savings based on a long-term analysis should be the sole
7 consideration in the decision to exit Valmy Unit 2. Once
8 the exit notice is given, it cannot be withdrawn.
9 Q. What considerations did Idaho Power suggest
10 evaluating in addition to the long-term analysj-s?
1l- A. A key component of the Second Amended 20L9 IRP
12 that allowed for the exit of Valmy Unit 2 aL year-end 2022
13 was the availability of firm market purchases from the
L4 south of ldaho Power's service area over the transmission
l-5 path currently utilized by Idaho Power's share of the Valmy
L6 plant output. While the Company considered the availability
L7 of wholesale energy for import across the Idaho to Nevada
l-8 path as less certain, it had been considered as a potential
19 to source seldom-needed capacity during peak-loading
20 periods. As discussed later in my testimony, Idaho Power
2l subseguently evaluated this assumption in light of recent
22 changes in regional transmission availability.
23 Additionally, as part of the Valmy Unit 2 exit discussion
24 included in the Second Amended 201-9 IRP, the Company
25 indicated economic and reliability impacts of an earlier
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Unit 2 exj-t must be evaluated using data points such as
forward market hub price forecasts, planned unit outages,
and recent market conditions. The objective of these
analyses is to identify any tradeoffs between an earlier
exit date and the ability to provide re1iab1e, affordable
power.
IIT. VALMY T'NIT 2 EXIT A}IAI,YSIS
A. Has Idaho Power completed the analysis of the
reliability and economic impacts associated with an exit of
Valmy Unit 2 prior to year-end 2025?
A. Yes. The Company conducted focused system
reliability and economic analyses to assess the appropriate
timing of a Valmy Unit 2 exit between 2022 and 2025. The
intent of these analyses is to ensure customer reliability,
while considering more current operating budgets and up-to-
date economics, to inform a decision that will minimize
costs for customers while also maintaining system
reliability.
O. Did the Company evaluate exit dates beyond
2025?
A. No. Under the Framework Agreement with NV
Energy, and the Settlement Stipulation approved by the
Commission with Order No. 33771, the Company agreed to
cease coal-fired operations of Unit 2 by December 3l-, 2025.
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1 Therefore the analyses performed in this case only apply to
2 the years between 2022 and 2025.
3 Q. Please summarize the Company's approach to the
4 reliability and economic impact analyses.
5 A. Idaho Power began the analysis with an
5 evaluation of system reliability, as the Company must first
7 ensure dependable capacity resources exist to meet expected
8 Ioad. Next, Idaho Power analyzed the economics of various
9 portfo1ios with resources that coul-d replace the Company's
L0 existing 134 MW at Valmy Unit 2. The result of the
11- reliability and economj-c evaluations is the most reliable
1,2 and economic path toward an exit from coal-fired operations
13 of Valmy Unit 2.
1,4 IV. RELIABIIJITY E1IALUATION
15 O. Why is a reliability analysis necessary?
A. Reliability is the foundation for any resource
plan; the Company must ensure it has sufficient resources
to meet customer demand. It is critical when comparing
future resource portfolios that each plan achieve a base
reliability threshold. To analyze the reliability impacts
associated with an early exit from coal-fired operations at
Valmy Unit 2, Idaho Power (1) refined the load and resource
balance to determine any resource deficiencies, (2)
enhanced the approach to computing the planning margin, and
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(3) identified multiple options to replace the 1-34 MW of
firm capacity in the absence of Valmy Unit 2.
Load and Resource BaLance
o Please explain the "load and resource
bal-ance".
A. The load and resource balance is the Company's
operational plan that identifies resource deficiencies
during the 2O-year IRP planning horizon. It incorporates
the expected availability of Idaho Power/ s existing
resources, comparing the total output to the Company's
forecasted Ioad, and computes the resulting surplus or
deficit by month. This will identify the Company's first
resource need date r ox the point at which Idaho Power's
reliability requirements may not be met. The availability
of existing resources, including Public Utility Regrrlatory
Policies Act ("PURPA") projects, power purchase agreements,
hydro, coa1, g?s, demand response, and market purchases, is
determined using a number of factors such as e>pected
stream fIows, plant run times, forced outages, and
transmission availability, among' other considerations.
O. What is the purpose of the load and resource
balance?
A. The load and resource balance ensures Idaho
Power has sufficient resources to meet projected customer
demand plus a margin to account for extreme conditions and
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1 resource outages. It is critical when comparing future
2 resource portfolios that each plan achieve at least a base
3 reliability threshold.
4 O. Did Idaho Power make any adjustments to the
5 load and resource balance used in the Second Amended 201,9
5 IRP as part of the Valmy analysis presented in this case?
7 A. Yes. Because development of the 2021 IRP is
8 occurring simultaneously to the Valmy Unit 2 reliability
9 and economic impact analyses, the load and resource balance
10 was updated to include modifications to existing resource
LL avallability, as is standard when developing the load and
12 resource balance as part of the IRP process.
13 O. Please describe the modifications to the
14 existing resource availability.
L5 A. First, the Company identified changes to its
16 market purchase assumptions, which I will discuss later in
L7 this section. Additionally, the existing resource
1-8 availability was revised to include updated thermal
19 capacity and reduced demand response capacity determined
20 through the refinement of the planning margin calculation,
2l which I will explain later in my testimony. The net change
22 between the Second Amended 2019 IRP and the updated load
23 and resource balance is a reduction of approximately 480 MV'I
24 - 500 MW in available capacity each ,Ju1y during the 2022
25 through 2025 time period.
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1 A. What market purchases assumptions have been
2 used to develop the load and resource balance?
3 A. To e>p1ain the market purchase assumptions, it
4 is necessary to first describe the regional transmission
5 market in general. Transmission lines cor:nect Idaho Power
6 to wholesale energy markets and help economically and
7 reliably mitigate variability of intermittent resources
8 through the transfer of electricity between utilities, not
9 only to serve 1oad, but also to share operating reserves.
10 O. Please describe the Company's transmission
1l- system.
L2 A. Exhibit No. 1 presents ldaho Power's
13 transmission system, with the thick black lines
14 representing the boundaries. The Company owns the
l-5 transmission assets within the boundaries and thus can
16 reserve transmission within this area to serve Ioad.
L7 However, once outside the boundaries, Idaho Power must
18 reserve transmission from third-party entities which is
1,9 subject to availability.
20 Historically, the Company experiences its peak load
21- at different times of the year than most Pacific Northwest
22 utilities. As a result, Idaho Power can purchase energ"y
23 from Mid-C during its peak and se1l excess energy Eo the
24 Pacific Northwest, utilities during their peak. Although
25 energ'y is plentiful at the Mid-C market, imports from Mid-C
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l- are frequently limited by transmission availability. The
2 proposed Boardman to Hemingway ("B2H") project would
3 greatly increase this transmission capacity.
4 O. What transmission paths are available to Idaho
5 Power to bring energy in from Mid-C?
6 A. The Company typically imports energy from Mid-
7 C during the summer months from the west on the Idaho to
I Northwest transmission path. A portion of this
9 transmission capacity is reserved by BPA to serve their
10 southern Idaho customers. Energy can be brought in from
1l- Mid-C via Montana on the Idaho to Montana path as we1l,
12 which consists of two lines to the Northeast of the
13 Company's system.
14 O. Does Idaho Power have options to purchase
l-5 energy from the southern markets?
15 A. Yes. South of Idaho are the Mead, Palo Verde,
l7 and Four Corners market hubs, collectively referred to as
18 the Southern Hubs. However, the Company infrequently
19 purchases energy from the Southern Hubs as the southern
20 utilities are also summer peakj-ng, increasing demand in the
21, region thus creating unfavorable pricing. In addition, a
22 purchase from the Southern Hubs will often require multiple
23 transmission wheels that can be difficult to obtain due to
24 transmission availability constraints. The Idaho to Sierra
25 path, the path that energy from the Valmy 345 kV line
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1- connects to, and the Idaho to Utah path, which has more
2 line intercor:nections, also run to the south of Idaho
3 Power's transmission system.
4 O. Is there firm transmission availability south
5 of Idaho for the Company to access the Southern Hubs?
5 A. Currently there is no firm transmission
7 capacity avail-abl-e across NV Energy's transmission system,
8 and, other than an existing 50 MW Idaho Power reservation
9 across the PacifiCorp East system, there is limited
L0 availability through Utah.
11 O. Does Idaho Power anticipate any firm
1-2 transmission capacity availability south of Idaho in the
l-3 near-term?
14 A. No. There is, however, a chance that a power
15 marketer may control some of this transmission capacity
16 south of Idaho and wish to se11 energy to the Company.
L7 Idaho Power's intention is to test this possibility with a
18 market request for proposals (*RFP"), which I wilL discuss
1,9 later in my testimony.
20 O. In the Second Amended 20:..9 IRP, the Company
2l assumed Valmy Unit 2 could be replaced with capacity
22 purchases from the south. What has changed?
23 A. Market conditions have changed dramatically in
24 the south because of ripple effects stemming from the
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l- energy emergency event in California in August 2O2O
2 ("August 2020 event").
3 Q. What happened during the California energy
4 emergency event?
5 A. During Augrust, 2020, the west e>rperienced a
6 heat wave, increasing the demand for ener!ry 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 the ability to import
11 energ"y. As a result, the California Independent System
1-2 Operator was required to shed firm load to maintain
13 reliability and the security of the bulk power system.
1-4 O. How did this impact Idaho Power's transmission
15 system?
16 A. Understanding the importance of transmission
l7 availability during times of high electricity demand,
18 third-party marketing firms began reserving transmj-ssion
19 capacity just outside the Company's border, significantly
20 limiting Idaho Power's access to market hubs. Soon after
21, the event, Idaho Power's own transmission service queue was
22 flooded with multi-year requests totaling 1,,293 Irfl,ll, as of
23 April 202L, enabling these third-party marketing firms to
24 move energy from Mid-C across Idaho Power's transmission
25 system to the south. These transmission servj-ce requests
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L have been overlaid on the Company's transmj-ssion system map
2 to illustrate the flood of requests in Exhibit No. Z.
3 Q. Why would the third-parEy marketing firms
4 request transmission service on paths from Mid-C Eo the
5 south when energy from the Southern Hubs would 1ike1y
5 require fewer wheels?
7 A. A comparison of the summer market forward
8 prices between the two hnbs demonstraEes why it is 1ike1y
9 the markeEing firms saw the opportunity at Mid-C. The
l-0 following table presents a comparison of the hearry load
L1 hour forward prices, in costs per megawatt-hour (*MWh"),
L2 between Mid-C and Palo Verde as of March 2021-z
13 Table 1. Forward Market Priees, March 202L
uid-c Palo Verde
iluly, 202L
Augrugt, 202L
iluLy, 2022
August, 2022
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l-5 With a wheeling cost of approximately #3.42 per MWh
to use Idaho Power's transmission system, marketing firms
are able Eo economically deliver energ"y from Mid-C and seII
to summer peaking utilities in the south even with multiple
wheeling charges.
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l- O. Does this al-so impact Idaho Power's ability to
2 access the Mid-C market?
3 A. Yes. The transmj-ssion service reguests have
4 added to an already constrained market limiting the
5 Company's access to Mid-C. However, as I w1l-I dj-scuss
6 later ln my testimony, Idaho Power is testing the market
7 availability with the RFP issued April 26, 2021-, to further
8 assess these transmj-ssion system constraints. Because a
9 key assumption used to develop t,he load and resource
1-0 balance for the Second Amended 201,9 IRP was that Idaho
11 Power's exit from coaL-fired operations at Valmy would free
12 up transmission capacity for imports to Idaho from the
13 south, it is essential that the Company update the
1,4 transmission availability assumptions used in the
15 development of the load and resource balance to reflect
15 these recent changes.
17 O. What was the net reduction in transmission
l-8 capacity availability incorporated into the updated load
19 and resource balance for the analysis review period?
20 A. For the years 2022 through 2025, Idaho Power
21, reduced the transmission availability within the load and
22 resource balance by approximately 140 MW to 277 MW during
23 the peak load month of ilu1y.
24 Planning Margin
25 O. What is Idaho Power's planning margin?
ELLSWORTH, DI 21,
Idaho Power Company
1 A. The Company's planning margJ-n j-s intended to
2 provide a sufficient reliability margin to prevent the need
3 to curtail customer demand more than one time in l-0 years,
4 the industry standard. The planning margin is intended to
5 cover (1) Idaho Power's contj-ngency reserve obligation, (2)
6 severe weather events, both extreme heat and extreme co1d,
7 (3) poor water conditions, and (4) planned and unplanned
I resource and transmission outages.
9 Q. How did the Company compute Ehe planning
10 margj-n in the Second Amended 201-9 IRP?
1L A. In the Second Amended 201,9 IRP, Idaho Power
1-2 established a l-5 percent planning margin. Planning margin
13 was calculated as 15 percent of the Company's average (50.t
L4 percentile) peak demand forecast for each month. For
15 example, if Idaho Power had a peak-hour-load of 3,500 MW,
16 the Company would add the planning margin and target 4,025
1-7 MW of resource capacity (3,s00 multiplied by 1.15) .
L8 O. Is Idaho Power considering any enhancements to
!9 the planning margin utilized in the Second Amended 201-9 IRP
20 to meet reliability reguirements as part of the Valmy Unit
21 2 reliability analyses?
22 A. Yes. Following the development of the Second
23 Amended 2Oa9 fRP, the Company looked to refine its planning
24 margin to ensure consideration of issues specific to Idaho
25 Power's system. The 15 percent planning margin utilized in
ELLSWORTH, DI 22
Idaho Power Company
l- the Second Amended 201,9 IRP is essentially a "rul-e of
2 thumb". Individual utilities can experience dj-fferent
3 freguencies of demand extremes, varyj-ng forced outage rates
4 among resources, and resource sj-ze compared to load size,
5 all of which should be considered when determining planning
6 margin. Rather than continue to util-ize this "rule of
7 thumb" planning margin, the Company used probabilistic
8 methods in the Valmy Unit 2 exit analysis to determine
9 system needs to ensure reliability for all hours of the day
10 on the Company's system, referred to as the Loss of Load
l-1 Expectation ("LOLE" ) method.
12 O. What is the LOLE approach for determining the
l-3 planning margin to meet reliability reguirements?
14 A. The LOLE approach aIlows for a comparison of
L5 load to generation on an hourly basis over a specified
15 perlod. The industry standard to plar:ning is no more than
l7 one loss of load event per L0 years, ot an LOLE of 0.1 days
18 per year7.
19 O. Why does ldaho Power believe the hourly
20 approach of the LOLE calculation for det,ermining plaru:ing
21, margin improves upon the previous method from the Second
22 Amended 2Ol9 IRP?
7 The Southwest Power Pool, PJM Tnterconnection, and the Midcontinent
Independent System Operator are among those that use this probabilistic
approach.
ELLSWORTH, DI 23
Idaho Power Company
1 A. The Company believes the LOLE method's hourly
2 approach fu11y considers the reliability value of renewable
3 resources over time compared to the previous method. Table
4 2 below utilizes the forecasted peak day in 2023 to
5 illustrate the j-mportance of an hourly approach in
6 determining planning margin requirements.
7 Table 2. Planning Margin Example8
A B c D
2023
Peak Day
at5PM
2023
Peak Day
at9PM
2023
Peak Day
at 10 PM
2023
Peak Dayat 11 PM
1 Demand (l , alz)(3,357)(3 ,272)(3, 1oo)
2
Resourees
(w/o Solar
e Wind)
2,774 2,763 2,755 2,754
3 Demand
ReEponse
340 40 0 0
4 SoIar 243 0 0 0
5 Wind 69 1t_1 r-3 3 95
5 Market Need (246)(443 )(373 )(25L1
Row 1 reflects the system demand. Column A presents the
calculation of the deficj-t when only considering the daily
resource availability. Demand response and solar are
helping meet the peak demand hour with the aid of some wind
resources, reducing the deficit and resulting market need
to 245 MW.
I
9
10
t-1
L2
13
8 Forecasted demand and resource val-ues are representative and subject
to change.
ELLSWORTH, DI 24
Idaho Power Company
L4
l- Columns B, C and D present measurements on the same
2 peak day, but in three different hours. As can be seen, by
3 9 PM, most of the demand response is no longer available as
4 many of the Company's existing programs have ended and
5 solar has dropped to zero because the sun has set.
5 Although wind generation has increased, the deficit has
7 increased to 443 MV'I. While not the peak demand hour, in
8 this example 9 PM is the "net peak" hour for the system,
9 i.e. the peak demand net of variable resources and demand
10 response. By 11 PM, when the decrease in load e>cperienced
11 during late evening hours has been reflected, coupled with
12 the j-ncreased wind generation, the deficit reduces lo 25L
l-3 MW. The hour-by-krour look better reflects the variability
14 of renewable resources on the system and will better inform
15 Idaho Power of its resource needs.
15 O. Aside from taking a more granular hourly
L7 approach, are there other components of the LOLE method
18 that lmpacted the Company's determination of resource
19 needs?
20 A. Yes. The LOLE method also evaluates the
21 capability of existing resources to meet peak demand
22 through the determination of Effective Load Carrying
23 Capability (*ELCC").
EITIJSWORTH, DI 25
Idaho Power Company
1 a. Did the use of the ELCC result in any changes
2 to the peak-serving capability of ldaho Power's existing
3 resources?
4 A. Yes. When analyzing fdaho Power's system on
5 an hour-by-hour basis, the results indicate the ability of
5 demand response to meet peak load under the changing
7 dynamics of Idaho Power's system is significantly lower
8 than previously assumed. This is prJ-marily the result of
9 increased solar resources on the Company's system pushing
10 net peak load hours outside the current demand response
l-1 program window.
12 a. Does the Company plan on using the LOLE
13 approach when determining reliability requirements for the
L4 2O2L IRP?
L5 A. Yes, the LOLE approach will be used for
t6 meeting reliability requirement,s over the 2O-year planning
17 horizon in development of the 2021- IRP. For purposes of
1-8 the reliability analysis associated with a Valmy Unit 2
19 exit date, Idaho Power performed the LOLE analysis for the
20 years 2023 and 2025.
2l a. What capacity deficits were identified as a
22 result of the LOLE study performed for the years 2023 and
23 2025?
24 A. Utilizing the new ELCC values and the updated
25 transmission assumptions, the load and resource balance
ELL,SWORTH, DI 26
Idaho Power Company
l- shows a deficit of 381 Mw in .fu1y 2023 and a deficit of 490
2 MW in ,Ju1y 2025. ft should be noted that these deficits
3 reflect resource actions from the Second Amended 201"9 IRP:
4 the exit of Valmy Unit 2 and one unit at the Jim Bridger
5 Power Plant ("Bridger") at year-end 2022, and the addition
6 of ,Jackpot Solar in 2023.
7 Q. You previously stated Idaho Power's current
8 share of Valmy Unit 2 is 134 MW. Based on the results of
9 the LOLE analysis, is Idaho Power able to exit Valmy Unit 2
l-0 at the end of 2022 while meeting its reliability threshold?
L1 A. No. Given the capacity deficits of 381 MhI and
12 490 MW in 2023 and 2025, respectively, with assumed unit
L3 exits at Valmy and Bridg€r, it is not feasible to exit
14 coal-fired operations at Valmy Unit 2 at year-end 2022
l-5 without procuring additional firm capacity, which I will
L6 discuss in the following section.
L7 Options for Meet ReIia-bility Needs
t-8
t_9
20
2L
22
23
O. How did the Company evaluate optJ-ons for
meeting reliability needs given the fact that Idaho Power's
share of capacity at Valmy Unit 2 is 134 MI{, and previously
identified capacity deficits are 381- MW in 2023 and 490 MW
in 2025?
A. The intent of this case is to determine the
appropriate exit date for Valmy Unit 2 and its associated
134 MW of firm capacity. Therefore, when evaluating options
ELLSWORTH, DI 27
Idaho Power Company
24
25
1 for meeting reliability needs, the Company considered
2 effective replacements for the 1-34 MW of firm capacity at
3 Valmy Unit 2. The 2021- IRP currently in development will be
4 utilized to address the broader capacity needs.
5 Q. Pl-ease describe in general the Company's
6 approach for evaluating options for meeting reliability
7 needs.
I A. The results of the LOLE analysis j-ndicate that
9 exiting from Valmy Unit 2 aE year-end 2022 results in a
10 capacity deficit. Therefore, an initial option is to delay
l-L the exj-t from this unj-t given the identified need for firm
12 capacity for 2023 through 2025 and retain the existing 1-34
13 MW to meet expected capacity needs. The Company then
14 evaluated other options to provide the 134 MW in firm
l-5 capacity in place of retaining Valmy Unit 2 operations
15 through 2025.
17 O. What other options did ldaho Power evaluate
L8 for meeting reliability reguirements other than delaying
L9 the exit of Valmy unit 2?
20 A. There are a number of other potential optj-ons
2l for meeting the reliability hurdle in addition to the delay
22 in the exit of coal-fired operations of Valmy unit 2,
23 including firm market imports through transmission
24 interconnections, new internal resources, an e>q>anded
25 demand response program, or delaying the 2022 exit from the
ELLSWORTH, Dr 28
Idaho Power Company
1 Bridger unit to 2025. The economic analysis of each of
2 these options is presented later in my testimony.
3 Q. You stated earlier that forward market prices
4 in the Southern Hubs were significantly higher than Mid-C.
5 Why are you indicating the possibility a market import will
5 ensure the Company meets the reliability reguirements when
7 it appears to be very costly?
I A. As I discussed earlier, forward market prices
9 of hear44 load hours at Palo Verde are forecast to be nearly
l-0 four-times the price of Mid-C in 2021-. However, the
l-l- pricing f orecasted at Palo Verde settles af ter a few years.
1-2 When examining heavy load hour forward market prices at
13 Palo Verde, by 2023 the prices drop near $I/uwfr, and
!4 below $I/uwfr ln 2024 and 2025. Given this price trend,
l-5 and the ability to purchase targeted guantities of energy
16 through a market purchase, it is possible that the Southern
l7 market hubs could alIow for a more cost-effective approach
18 than delaying the exit of valmy unit 2.
19 O. How will ldaho Power determine whether
20 transmission availability exists to import from the market
2l to maintain reliability and at a price that is economical?
22 A. The Company issued an RFP on April 26, 2021,
23 with responses due May 4, 202:-., for the delivery to Idaho
24 of firm capacity and energy during the summer months
25 through 2025.
ELLSWORTH, DI 29
Idaho Power Company
1 a. How will the Company incorporate the results
2 of the RFP into this proceeding?
3 A. Given the timing constraints associated with
4 the September 30, 202L, deadLine for notice to IW Energy,
5 Idaho Power is filing this case concurrently with the
6 processing of the RFP. This will a11ow the Commission and
7 interested stakeholders to begin reviewing the Company's
8 case without delaying the filing date. Upon conclusion of
9 the RFP, the Company will evaluate the varj-ous proposals
10 received and supplement its filing in this case in ,fune
11 202L to inform stakeholders of proposals recej-ved.
12 V. ECONOMIC AI{AIJYSIS OF RESOURCE OPTIONS
13 O. What was the nature of the economic analysis
performed for this case?
A. Arry number of resources can be added to a
resource portfolio, and, provided the resource portfolio
meets or exceeds the reliability threshold, the costs of
the various portfolios can be compared. Idaho Power
evaluated the costs of portfolios under the various
scenarios for replacing generation from an early exit of
Valmy Unit 2 and identified the portfolio that is least-
cost and least-risk to the Company and its customers.
O. Please describe each of the portfolios
analyzed.
l4
15
t6
1,7
18
1,9
20
21
22
23
ET,LSWORTH, DI 30
Idaho Power Company
24
1_
2
3
4
5
6
7
8
9
A. Idaho Power analyzed four portfolios, each
with the addition of a di-fferent resource in 2023 to
replace the exit from Valmy unit 2 at year-end 2022, and
compared the cost of each to the portfolio cost of exiting
Valmy Unit 2 at year-end 2025: (1) a Valmy Unit 2 exit in
2022 with the addition of solar plus battery storage in
2023 ("Solar Pl-us Battery Portfolio"), (2) a Valmy Unit 2
exit in 2022 with the addition of only battery storage in
2023 ("Battery Portfolio"), (3) a Valmy Unit 2 exit in 2022
with an expansion of Idaho Power's existing demand response
programs in 2023 ("Demand Response Portfolio"), and (4) a
Valmy Unit 2 exit in 2022 with a delayed Bridger unit exit
from 2022 to 2025 ("Bridger Portfolio").
O. why did rdaho Power not consider a portfolio
that includes a new thermal resource such as natural gas?
A. The Valmy Unit 2 exit analysis is focusing on
the near-term with a resource on-Iine date of 2023. The
assumes it is not
10
t-1
L2
13
l4
15
1,5
1,7
l_8
1,9
22
23
20 Idaho Power focused on those resources that
21, located within its transmission system area,
Company
natural gas resource prr-or
and online by 2023.
Portfolio Cost Development
feasible to permit
to the summer of
and install a
2023. Instead,
could be
constructed,
ELLSWORTH, DI 31
Idaho Power Company
How were the portfolio costs determined?24 a
l- A. Idaho Power used AURORA, the Company's
2 electric modeling forecasting and analysis software, to
3 quantify the total portfolio costs of each of the
4 portfolios for the 2022 through 2025 time period.
5 Q. Is Idaho Power utilizing the LTCE
6 functionality in AURORA to inform the analysis in this
7 case?
8 A. No. As mentioned previ-ously, the LTCE
9 functionality of AURORA is utilized in the Company's long-
l-0 term 2O-year planning analysis to construct the least-cost,
l-1 l-east-rj-sk portfollo. Because the Company's analysis in
12 this case is limited to the time period 2023 to 2025, and
13 because the suj-t,e of viable options is limited as discussed
L4 previously, the Company is utilizing AURORA solely to
l-5 determine the relative cost performance of the identified
15 portfolios.
t7 O. What cost inputs did Idaho Power use for this
1-8 analysis?
19 A. The Company used the most up-to-date cost
20 information possible for the economic analysis. Although
21- work to update inputs for the 2021- IRP has begun, this work
22 is sti1l in progress. Therefore, Idaho Power updated
23 AURORA with those inputs it tytrlically updates when
24 preparing a base net power supply expense update, including
25 variable coal costs, natural gas prices, and the load
ELLSWORTH, DI 32
Idaho Power Company
1
2
3
4
5
6
7
8
9
forecast. The breadth of this update is appropriate given
the limited use of AURORA in this case.
O. Did the Company update the relevant Valmy
fixed costs associated with the various portfolios?
A. Yes. For the base portfolio, the Valmy Unit
2 exj-t of 2025, the fixed costs defined by the Framework
Agreement that are Idaho Power's responsibility shoul-d the
Company continue participation in coal-fired operations in
Unit 2 through 2025 are not included in the AURORA
modeling, therefore they must be added to the varj-abIe
costs from AURORA to determine the total base portfolio
cost.
O. How were the fixed costs associated with the
Solar Plus Battery Portfolio determined?
A. The Solar Plus Battery Portfolio costs are
based on the do1lar per MhI cost of a solar array and an
associated dolIar per MW cost of a battery storage project,
including the 26 percent Investment Tax Credit ("ITC"1s.
The fixed costs reflect information gathered from industry
data, p€€r utilities, and regional developers. The fixed
cost inputs for the Solar Plus Battery Portfolio include
costs for a 134 MW solar/t34 MW battery project to
s Currently, the ITC is scheduted to begin phasing out over the next twoyears. However, President Biden's infrastructure proposal would extendthe phasedown for an additional 10 years, if approved.
ELLSWORTH, Dr 33
Idaho Power Company
10
1_1
1,2
13
L4
15
1,6
t7
18
1,9
20
2t
22
1 sufficiently replace the peak capacity of Valmy Unit 2
2 during the 2023 through 2025 tj-me period.
3 Q. Please erq>Iain the fixed costs associated with
4 the Battery Portfolio.
5 A. The Battery Portfolio fixed costs are based on
6 the cost of a l-34 MW battery-storage project. Idaho Power
7 used the battery fixed cost component determined for the
8 Solar Plus Battery Portfolio in the modeling of the Battery
9 Portfolio, however no ITC savings were mode1ed. ITC's only
10 occur with a combined solar and battery project. The
l-l- results of the information gathered and Idaho Power's
1-2 determination of the fixed cost input can be found in
13 Exhibit No. 3. Similar to the Solar Plus Battery
1,4 Portfolio, one 134 MW battery storage project is modeled in
15 AURORA for the equivalent replacement of Valmy Unit 2
!5 capacity.
l7 O. How did the Company compute the fixed costs
18 associated with the Demand Response Portfolio?
19 A. The Demand Response Portfolio fixed costs are
20 based on the expansion of Idaho Power's existing demand
21, response programs. The Company estimated the incremental
22 program costs associated with an additional 50 MW of demand
23 response, including estimated increases in 1abor, incentive
24 e)+)enses, and device costs f or the three progirams and grew
25 those linearly up to the l-34 MW of Valmy unit 2 capacity.
ELLSWORTH, DI 34
Idaho Power Company
l- O. Why was the initial estimate of the Demand
2 Response Portfolio fixed costs based on a program e>rpansion
3 of only 50 MW?
4 A. The initial estimate was based on 50 MW
5 because Idaho Power belj-eves an expansion of the three
6 existing demand response programs above 50 MW may not be
7 feasible at this time based on current participation and
8 cost-effectiveness 1eve1s. Further, as was mentioned
9 earlier in my testJ-mony, the ability for demand response
L0 und.er current program parameters to meet peak load capacity
l-1 need is diminishing over time making it increasingly
L2 challenging to maintain existing demand response capacity.
l-3 That said, in order to provide a conservative estimate of
L4 the cost of a hypothetical program expansion equivalent to
15 the generation capacity of Valmy Unit 2, the Company
15 extrapolated the 50 MW e>pansion cost estimate to L34 MW.
!7 The Company will be evaluating the potential for further
18 demand response expansion and associated cost in its 2O2l
L9 IRP.
20 O. Why did the Company evaluate expanding the
21- demand response programs in this study rather than
22 modifying existing programs to increase their ELCC?
23 A. The Company is currently studying potential
24 modifications to the existj-ng demand response programs. The
25 extent of the proposed modifications, and resulting impact
ELLS}'IORTH, DI 35
Idaho Power Company
l- to customer participation, are uncertain at this point, but
2 wilt 1ike1y impact the load and resource balance. The
3 purpose of analyzing an e>q>anded demand response option in
4 this case is to provide a comparison of the cost
5 effectiveness between operating Valmy Unit 2 through 2025
6 and the e>cpansion of demand response, in general.
7 O. Did the fixed costs for the Bridger Portfolio
8 incorporate existing plant values?
9 A. Yes. The fixed costs assumed for the Bridger
l-0 Portfolio include the plant values associated with one
LL Bridger unit that would stil1 need to be recovered once the
L2 unit is retired.
L3 O. What are the total portfolio costs for each of
1-4 the four portfolios modeled as compared to the base
L5 port,folio that included operations of Valmy Unit 2 through
15 2025?
l7 A. Table 3 presents the results of the economic
L8 analysis, det,ailing the total portfolio cosEs of each
L9 scenario modeled as compared t,o the base portfolio.
20 ///
2L ///
22 ///
23 ///
24 ///
2s ///
ELLSWORTH, Dr 36
Idaho Power Company
1 TabLe 3. Eeonomic Analysis Results
seen, the results are portfolio costs in the
approximately $l-5.89-$30.78 million more than the
As can be
2
3
4
5
6
7
8
9
range
base
of
10
portfolio.
O. What conclusions can be drawn from these
results?
A. These results lndicate that the modeled
scenarios are not more economically beneficial to meet
Idaho Power's rel-j-ability needs through 2025 than retaining
11 Valmy Unit 2
VI. RECOMMEIIDATION
a. Please summarize the results of the
reliability and economic impact analyses performed by the
Company.
10 Assumes 134 Mw of demand response program expansion at existing cost-effectiveness levels. Idaho Power is uncertain if this amount of
program expansJ-on at assumed cost effect.iveness 1eve1s is achievable.Further, the ability for demand response under current program
parameters to meet peak load capaciEy need is diminishing over time
making j-t increasingly challenging to maintain existing demand response
capacity.
ELLSWORTH, DI 37
Idaho Power Company
L2
13
L4
l-5
Modeled Scenarios -Adjustments from the Second Amended 2019
IRP Preferred Portfolio
Resulte as
Compared Eo 2025
Valmy Unit 2 Exit
2025 Valmy 2 Exit $-
2022 Valmy 2
with Solar +
Exit Capacity Replaced
Battery (2023)$28.09 million
2022 Valmy 2 Exit - Capacity Replaced
with Battery (2023)$30.78 million
2022 Valmy 2 Exit - Capacity Replaced
with Expanded Demand Responselo (2023)$23.7 0 million
2022 Valmy 2 Exit - Capaclty Replacedwlth Delayed Bridger Exit (2022 - 2025)
$1s.89 million
1 A. The Company conducted focused, near-term
2 system reliability and economic analyses on the timing of a
3 Valmy Unit 2 exit between 2022 and 2025. The goal of the
4 analyses was to use current operating budgets and up-to-
5 date economics to inform a Va1my exit decision that will
5 minimize costs for customers and maintain system
7 reliability. After refining the load and resource balance
I and performing an LOLE analysis, it is clear that Idaho
9 Power is unable to meet, reliability requirements if
10 participation in coal-fired operations of Valmy Unit 2
11 ceases in 2022 without procuring an alternate source of
L2 peak capacity. The Company identified four alEernatives to
13 delaying a Unit 2 exit of Valmy until 2025 and performed an
1-4 economic analysis on the resulting portfolio costs. The
L5 results indicate that operating Valmy Unit 2 through 2025
16 costs approxJ-mately $15.89 million less on a net present
17 value basis than the least-cost feasible alternative.
18 O. Is it the Company's recofirmendation that
t9 participation of coal-fired operations in Valmy Unit 2
20 continue during the 2023 through 2025 time period?
2l A. Yes. However, once results of the RFP are
22 received, and portfolio costs associated with any feasible
23 market purchases are determined, the Company will
24 supplement its filing in this case.
ELLSWORTH, Dr 38
Idaho Power Company
l- O. Will Idaho Power continue to evaluate a Valmy
2 Unit 2 exit prior Lo 2025?
3 A. Yes. The Company will continue to evaluate an
4 early exit of Unit 2 as part of the 2021- IRP. The timing
5 of the 2021 IRP appropriately a1i-gns with Idaho Power's
5 notification requirement to IiIV Energy beyond the September
7 2021 deadline should the results indicate an exit at year-
8 end 2023 or 2024 is least-cost and continues to meet
9 reliability requirements.
10 vII. CONCLUSTON
l_1 O. Please summarize your testimony.
A. As the Company committed in the Second Amended
201,9 IRP, Idaho Power performed near-term economic and
reliability impact analyses to determine the appropriate
exit date from Valmy Unit 2. Pending the results of the
market RFP, the current results of the resource alternative
analyses support an exit from operations of Valmy Unit 2 in
2025. Therefore, the Company requests Commission
acknowledgement that, based on information known at this
time, the appropriate exit date from Valmy Unit 2 is
December 31, 2025. A Commission order issued no later than
September 29, 202:--, will a11ow Idaho Power adequate time to
notify IW Energy should the Commission dj-rect Idaho Power
to pursue an earlier exit date of Valmy Unit 2.
A. Does this complete your Eestimony?
L2
13
1,4
15
L6
L7
18
1,9
20
21,
22
23
24
Er,r,swoRTH, DI 3 9
Idaho Power Company
25
1 DECLARAIIION OF JARED L. EIJIJSWORTH
2 I, ,Jared L. Ellsworth, declare under penalty of
3 perjury under the laws of the state of Idaho:
4 1-. My name is .fared L. Ellswort,h. I am
5 employed by Idaho Power Company as the Transmission,
6 Distribution & Resource Planning Director for the Planning,
7 Engineering & Construction Department.
I 2. On behalf of Idaho Power, f present this
9 pre-filed direct testimony and Exhibit Nos. 1-3 in this
10 matter.
11 3. To the best of my knowledge, my pre-filed
L2 direct testimony and exhibits are trrre and accurate.
l-3 I hereby declare that the above statement is true to
L4 the best of my knowledge and belief, and that I understand
15 it is made for use as evidence before the Idaho Public
1-5 Utilities Commission and is subject to penalty for perjury.
17 SIGNED this 30th day of April 2021-, ?t Boise, Idaho.
L8
19 Sigmed:
20
ELLSWORTH, DI 4I
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-21-12
IDAHO POWER GOMPANY
ELLSWORTH, DI
TESTIMONY
EXHIBIT NO. 1
Mid c
IDAHO POWER'S TRANSMISSION SYSTEM
\PecrrCoRP
Bonneville
BtL,rool
Ch ar.li.dldFc(.tl
.1.rrtn
ll ..il
hilffCm
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aitt{ ^t,*rilii.!rqt
Mid C via I
Bonneville
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lir'
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E*nonf.r#-l* .-\
t'('E tt(:rtil1Fitl YEor.rncrtrlF.Jait
t
It 6
'4
&nH&o.rdg.r.it
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lda
8ii.itila
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r. r ,r!|r I e{ frtlld'iir l{,tl:t.j
t l':7r UtE nt
-1J,
lda
ldaho to Sierra
YNVEnergy
littsra
itatl
Southern Hubs
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-21-12
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
EXHIBIT NO. 2
TRANSMISSION SERVICE REQUESTS
Mid c \PACIFICORP
Bonnevillerd!. a0rr$!r.rr0r
EtfiB.tlaoia'Fq.t
f qast
Mid C via Monta
Bonneville
\rutlNb
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t{'
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\
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2
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-21-12
IDAHO POWER COMPANY
ELLSWORTH, DI
TEST!MONY
EXHIBIT NO. 3
BATTERY STORAGE FIXED COST DETERMINATI
Ove rn ight
Capital Cost
(s/kw)
Fixed O&M
Sou rce (S/kw-month)
Va
2019 rRP
NREL ATB 2O2O
Avg Developer Cost 2O2L
Regional Benchmark
L,973
1,,LL8 - 1,463
0.78
2.33 - 3.05
L, L00 N/A
1,000 - L,828 2.30 - 4.L2
1 Preliminary cost. Subject to change during development of the 2021 IRP