20250530Direct Adelman.pdf

RECEIVED
May 30, 2025
IDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-25-16
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE )
IN THE STATE OF IDAHO AND )
AUTHORITY TO IMPLEMENT CERTAIN )
MEASURES TO MITIGATE THE IMPACT )
OF REGULATORY LAG. )
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
RYAN N. ADELMAN

1 Q. Please state your name, business address, and
2 present position with Idaho Power Company ("Idaho Power" or
3 "Company") .
4 A. My name is Ryan Adelman. My business address
5 is 1221 West Idaho Street, Boise, Idaho 83702 . I am
6 employed by Idaho Power as the Vice President of Power
7 Supply.
8 Q. Please describe your educational background.
9 A. I graduated in 1996 from the University of
10 Idaho, Moscow, Idaho, receiving a Bachelor of Science
11 Degree in Civil Engineering. I am a registered professional
12 engineer in the state of Idaho. In 2018, I earned a Master
13 of Business Administration through Boise State University' s
14 Executive MBA program. In 2019, I completed the Energy
15 Executive Course through the University of Idaho.
16 Q. Please describe your work experience with
17 Idaho Power.
18 A. From 2004 to 2008, I was employed by Idaho
19 Power as an engineer in Power Production' s Civil
20 Engineering Group. In 2008, I became an Engineering Leader,
21 initially responsible for the Langley Gulch power plant
22 project and later the Power Production Civil Engineering
23 Department. In 2015 I was promoted to Senior Manager of the
24 Projects Department where I managed the Project Management
25 and Cost and Controls group. In 2018, I led the Company' s
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Idaho Power Company

1 Southeast Idaho area as a Regional Manager. In 2019, I was
2 promoted to Vice President of Transmission and Distribution
3 Engineering and Construction, later renamed to Planning,
4 Engineering and Construction. In 2020, I transitioned to my
5 current position, Vice President of Power Supply, where my
6 responsibilities include oversight of Idaho Power' s
7 generation assets, jointly-owned generation assets, load
8 serving operations, merchant activities, and other
9 operational functions of generation resources and support.
10 Q. What is the purpose of your testimony in
11 this matter?
12 A. The purpose of my testimony is to discuss
13 the production plant-related investments the Company has
14 made to ensure Idaho Power can continue to provide safe,
15 reliable electric service to customers, detailing the steam
16 production, hydroelectric production, and other production
17 investments required since conclusion of Idaho Power' s
18 limited scope rate case in 2024, Case No. IPC-E-24-07 .
19 Q. How is your testimony organized?
20 A. My testimony begins with a description of the
21 Company' s major projects associated with Idaho Power' s
22 hydroelectric generation assets expected to be complete in
23 2025 and included in the Company' s request in this case .
24 Next, I discuss the other production assets major projects,
25 or investments associated with the Idaho Power-owned
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Idaho Power Company

1 natural gas facilities . Finally, I conclude with a
2 discussion of the steam production assets major projects,
3 or investments associated with the Company' s jointly-owned
4 power plants, the North Valmy Power Plant ("Valmy") and the
5 Jim Bridger Power Plant ("Bridger") . This discussion begins
6 with the steam production investments associated with
7 natural gas operations expected to be complete in 2025 and
8 included in the Company' s request in this case . Then, I
9 detail the steam production investments associated with
10 coal-fired operations made at Valmy and Bridger since the
11 Company' s last prudence determinations before the Idaho
12 Public Utilities Commission ("Commission") , including a
13 discussion of Idaho Power' s compliance with Order No.
14 34349, issued in Case No. IPC-E-22-05, as modified with
15 Order No. 35774 .
16 Q. What exhibits are you sponsoring?
17 A. I am sponsoring Exhibit Nos . 3 and 4 .
18 I . HYDROELECTRIC FACILITIES INVESTMENTS
19 Q. Please describe Idaho Power' s current
20 hydroelectric generation fleet.
21 A. The backbone of Idaho Power' s current
22 generation fleet consists of the Company' s 17 hydroelectric
23 projects on the Snake River and its tributaries . Together,
24 these projects comprise the Company' s largest generation
25 source at approximately 1, 800 megawatts ("MW") of nameplate
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1 capacity. Idaho Power has made several major investments in
2 its hydro fleet over the past decade, primarily due to
3 aging infrastructure, including the refurbishment of all
4 four turbines at the Brownlee hydrogeneration facility,
5 upgrades and improvements at Shoshone Falls, and
6 refurbishment of the Lower Salmon Falls hydrogeneration
7 facility.
8 Q. What are the major investments in Idaho
9 Power' s hydro generation fleet that are included in the
10 Company' s request in this case and expected to be complete
11 in 2025?
12 A. The following are the major projects
13 associated with the Company' s hydroelectric facilities that
14 are expected to be complete in 2025 : (1) the American Falls
15 Power Plant ("American Falls") Unit 1 turbine replacement
16 and generator refurbishment, (2) remediation of the
17 spillway at the Bliss Power Plant ("Bliss") , (3)
18 replacement of the Clear Lake Power Plant ("Clear Lake")
19 penstock, (4) modernization of the Oxbow Power Plant
20 ("Oxbow") control systems, and (5) threat and vulnerability
21 assessment security investments .
22 American Falls Investments
23 Q. What drove the need for the American Falls
24 Unit 1 turbine replacement and generator refurbishment?
25 A. The Company has implemented an annual
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1 generator condition assessment and testing program for its
2 hydro facilities, based on industry recommended testing
3 methods and testing intervals, to monitor generator
4 conditions of the units . American Falls, the Company' s
5 most upstream hydrogeneration facility on the Snake River,
6 consists of three units providing a combined 92 . 3 MW of
7 nameplate generation capacity. At over 45 years old, the
8 turbines had been requiring extensive weld repair each
9 year and were listed as a high priority for refurbishment .
10 Condition based testing of the generator coils showed
11 significant deterioration indicating the need for
12 replacement. Further, the partial discharge analysis
13 performed on the plant, used to determine the condition of
14 the stator coil insulation, was very high and increasing,
15 demonstrating a surface problem with the potential for
16 coil movement. Finally, an issue was identified with the
17 semiconductive, gradient coating on the generators . As a
18 result, in late 2019, Idaho Power began the multi-year
19 turbine and generator refurbishment project at American
20 Falls .
21 Q. What work did Idaho Power determine was
22 required to maintain the safe, reliable operation of the
23 American Falls facility?
24 A. Due to the aging American Falls
25 infrastructure, the Company established a multi-year
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1 project that will ultimately refurbish the turbines and
2 generators of all three units . The turbine runner
3 replacement and refurbishment of the mechanical components
4 is expected to extend their life 30 to 50 years . The
5 generator work includes new coils, bus rings, and the
6 refurbishment of rotor poles . The work was coordinated
7 with a planned outage for an upgrade of the plant controls
8 to minimize the outage impact and is expected to increase
9 the efficiency of each unit by three to five percent while
10 also reducing long-term maintenance costs .
11 Q. Were there any alternatives to performing the
12 turbine and generator refurbishments at the American Falls
13 facility?
14 A. Yes . Idaho Power considered deferring the
15 project, however the condition of the units was such that
16 further deferral of the generator refurbishments would
17 increase the chance of a failure of any of the coils and a
18 resulting loss of 34 MW of capacity. Moreover, a coil
19 failure while a unit is operating would likely cause
20 additional damage to the generator resulting in an
21 unscheduled outage that is of longer duration and higher
22 cost than a planned outage . In addition, the Company
23 considered the separation of the generator and turbine
24 refurbishments . However, further deferral of the turbine
25 work would result in increased maintenance costs,
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Idaho Power Company

1 including more frequent welding on the runners to repair
2 cavitation damage . This would likely reduce efficiency of
3 the turbines further. Additionally, deferring the turbine
4 refurbishments to a later time would result in long-
5 duration outages for each generating unit and additional
6 costs to disassemble and re-assemble the units at a later
7 point in time .
8 Q. What costs associated with the American Falls
9 turbine and generator refurbishment multi-year project are
10 included in the Company' s 2025 test year?
11 A. Amounts expected to be placed in service
12 during the summer of 2025 are associated with the Unit 1
13 turbine and generator refurbishment, for an estimated cost
14 of approximately $15 . 6 million.
15 Bliss Investments
16 Q. What drove the investments at the Bliss
17 hydroelectric facility that are expected to be made in
18 2025?
19 A. Bliss, the Company' s hydrogeneration facility
20 located on the Snake River at mile 560 . 3, was completed in
21 1950 and consists of a powerhouse and three generators,
22 providing a combined 75 MW of nameplate generating
23 capacity. A 2017 event involving the operation of
24 spillways in California brought renewed attention to
25 potential failure modes associated with concrete chute
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1 spillways and unlined spillways at dams . As a result, the
2 Federal Energy Regulatory Commission ("FERC") required
3 detailed assessments, or a Focused Spillway Assessment, of
4 similar spillways, including the Bliss spillway.
5 Q. What was the result of the Bliss spillway
6 assessment?
7 A. The assessment of the Bliss spillway
8 identified features in need of remediation to mitigate the
9 risks of failure of the spillway, the structure used to
10 control and manage the flow of water at Bliss . More
11 specifically, the Focused Spillway Assessment revealed
12 erosion and undercutting of the Bliss spillway apron that
13 required replacement of some of the spillway structure .
14 Before the work could occur, Idaho Power was required to
15 file for approval with FERC an amendment to the license
16 for Bliss .
17 Q. What work did the Bliss spillway require?
18 A. The work on the Bliss spillway first involved
19 an engineering analysis to determine the necessary
20 features that required replacement and their associated
21 design. Next, permitting and clearances were secured,
22 before construction could take place .
23 Q. What permits and clearances were required?
24 A. Permits or clearances were required from the
25 FERC Division of Hydropower Administration and Compliance,
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Idaho Power Company

1 the FERC Portland Regional Office, the Army Corp of
2 Engineers, US Fish and Wildlife Services, Idaho Department
3 of Water Resources, Idaho Department of Lands, Idaho
4 Department of Environmental Quality, and the Idaho State
5 Historic Preservation Office . Once permits and clearances
6 were received, preparation began for the spillway work. To
7 minimize the impact to operations, construction was
8 performed during the winter months, when stream flows were
9 low and partial dewatering of the river below the spillway
10 could occur.
11 Q. What was required to prepare for the work
12 necessary to remediate the Bliss spillway?
13 A. A crane pad was constructed near the edge of
14 the slope above spillway five followed by the installation
15 of the crane and barge/work platforms in the trail race in
16 preparation for the spillway work. The rock face above
17 spillway five was scaled for safety during construction,
18 and temporary access pathways and a scaffolding system to
19 access the construction area were made .
20 Q. What did demolition entail?
21 A. Demolition required the removal of a training
22 wall concrete cap as well as the removal of the eroded
23 concrete sections of the spillway before construction
24 could commence .
25 Q. What construction was necessary?
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Idaho Power Company

1 A. To prepare for the required underwater work,
2 contractors constructed two sheet pile cofferdams for
3 placement of underwater concrete . Rock anchor bolts were
4 installed to support the framework and after the concrete
5 was placed, underwater divers used cutting equipment to
6 remove the excess formwork from the area.
7 Q. What is the total investment in the Bliss
8 spillway remediation included in Idaho Power' s request in
9 this case?
10 A. The Company is requesting in this case to
11 include approximately $4 . 9 million in investments related
12 to the Bliss spillway remediation, which was completed in
13 February 2025 .
14 Clear Lake Investments
15 Q. Please describe the Clear Lake investments
16 Idaho Power has included in the request in this case .
17 A. With a nameplate generating capacity of 2 . 5
18 MW, Clear Lake is Idaho Power' s smallest power generator.
19 Built in 1937, the plant is adjacent to the Snake River
20 near Buhl, Idaho. Underground springs supply the water
21 used to generate power. The penstock, or long pipe that
22 carries water from the springs to the turbines, was the
23 original penstock and was corroding and degrading,
24 requiring replacement. This project involves the
25 demolition and replacement of approximately 600 linear
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1 feet of steel penstock, which is being performed from
2 September to December. The work will require the plant to
3 be taken off-line . Because construction will also impact
4 the Clear Lake Golf Course, the work is being performed
5 after the summer season to minimize the impact of the
6 work.
7 Q. What is the total investment in Clear Lake
8 included in Idaho Power' s request in this case?
9 A. The Company is requesting in this case to
10 include approximately $3 . 5 million associated with the
11 Clear Lake penstock replacement with work scheduled to be
12 completed in December 2025 .
13 Oxbow Investments
14 Q. Why is modernization of the Oxbow control
15 systems necessary?
16 A. The former Oxbow balance of plant control
17 system consisted of two separate systems, including
18 standalone programable logic controllers and hardwired
19 controls as well as a supervisory control and data
20 acquisition ("SCADA") monitoring system, and comprised all
21 the auxiliary systems in the powerhouse, such as the local
22 service power, the sump controls, the power plant air
23 compressors, fire alarm systems, door alarms, and spill
24 gates . This control equipment was outdated, had
25 reliability problems, and most of the components were no
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Idaho Power Company

1 longer supported by the manufacturers . Because of the age
2 of the equipment and the inability to procure spare parts,
3 the equipment needed to be replaced.
4 Q. What work does modernization of the Oxbow
5 controls entail?
6 A. The modernization allowed for combining of the
7 controls and monitoring into one solution, eliminating the
8 need for separate systems . The upgrade included the (1)
9 conversion of hard switches and controls to be programable
10 logic controllers that are human machine interface-based,
11 (2) removal of the existing SCADA system as it is
12 contained within the programable logic controllers, (3)
13 replacement of the human machine interface, (4)
14 replacement of the remote terminal unit, and (5)
15 conversion of the balance of plant controls to be in
16 programable logic controllers .
17 Q. What is the total investment in Oxbow included
18 in Idaho Power' s request in this case?
19 A. The Company is requesting in this case to
20 include approximately $2 . 4 million associated with the
21 Oxbow controls modernization project with work planned to
22 be completed by summer 2025 .
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Idaho Power Company

1 Threat and Security Vulnerability Assessment Investments
2 Q. What are the threat and security vulnerability
3 assessment investments associated with Idaho Power' s hydro
4 fleet expected to be complete in 2025?
5 A. There are three threat and security
6 vulnerability assessment projects expected to be completed
7 in 2025, two at the CJ Strike Power Plant ("CJ Strike")
8 and one at Oxbow. All three projects were the result of
9 on-site analyses performed by both FERC and the Company
10 under the guidelines of the FERC Security Program for
11 Hydropower Projects ("Dam Security Program") . Under the
12 Dam Security Program, FERC works with federal and state
13 agencies, and most recently Homeland Security, to promote
14 dam security by inspecting and evaluating projects with
15 dams with more than 2, 000 acre-feet of water storage .
16 This oversight and a regular inspection are an important
17 component of the Dam Security Program. Additionally, as
18 the threat landscape against critical infrastructure
19 continues to increase, with Idaho Power having an incident
20 at two of the four hydro facilities both of which fell
21 under the purvey of the Dam Security Program in June 2023,
22 physical security capabilities must be enhanced at
23 critical sites . The threat and security vulnerability
24 assessment projects at CJ Strike and Oxbow were associated
25 with enhancements of security controls and designed to
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Idaho Power Company

1 better detect, deter, delay, assess and respond to
2 potential security threat events .
3 Q. What are the security controls enhancements
4 being made at CJ Strike?
5 A. As part of the Dam Security Program, FERC
6 performs security inspections of the hydro facilities,
7 observing detection and assessment features, delay
8 functions, emergency response times, and the integration
9 of security controls to the system and associated risk
10 management . Following the assessment, the recommendation
11 was that Idaho Power address multiple potential threats
12 with the installation of improved security fencing, the
13 upgrade of the closed-circuit television ("CCTV") camera
14 system, as well as other improved security measures . In
15 addition, a boat barrier is being installed.
16 Q. What is the purpose of a boat barrier?
17 A. The primary purpose of a boat barrier is to
18 physically restrain watercraft from approaching too close
19 to dam structures or entering restricted areas . By
20 restricting physical access to dam facilities, a boat
21 barrier will aid in the reduction of potential security
22 threat events .
23 Q. What is the total of the CJ Strike threat and
24 security vulnerability assessment investments Idaho Power
25 has included in the request in this case?
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Idaho Power Company

1 A. The security controls enhancements being made
2 at CJ Strike is the largest of the threat and security
3 vulnerability assessment investments at approximately $7 . 8
4 million. The boat barrier installation at CJ Strike is
5 estimated to be approximately $3 . 8 million. The two CJ
6 Strike projects are expected to be complete in September
7 and December 2025, respectively.
8 Q. What threat and security vulnerability
9 assessment investment is being made at Oxbow?
10 A. The Company will be making similar security
11 controls enhancements at Oxbow. Enhanced security fencing
12 will be installed, the CCTV camera system will be
13 upgraded, and other improved security measures performed.
14 The work is expected to be complete by December 2025 for a
15 total project cost of approximately $4 . 5 million.
16 Q. Do you believe the hydroelectric generation-
17 related major projects you discussed demonstrate a prudent
18 and proactive approach for continued management of the
19 Company' s hydro fleet?
20 A. Yes . Idaho Power continues to complete
21 numerous projects annually at its hydro facilities to
22 ensure they are able to provide safe, clean, and reliable
23 service to customers . The American Falls Unit 1 turbine
24 replacement and generator refurbishment, the Bliss
25 spillway remediation, the Clear Lake penstock replacement,
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Idaho Power Company

1 the Oxbow controls modernization, and the threat and
2 security vulnerability assessment investments are all
3 evidence of the Company' s continued efforts .
4 II . COMPANY-OWNED GAS-FIRED GENERATION FACLITY INVESTMENTS
5 Q. Please describe the Company-owned gas-fired
6 generation facilities .
7 A. Idaho Power is the sole owner of three gas-
8 fired generation facilities : the Danskin and Bennett
9 Mountain simple-cycle power plants located near Mountain
10 Home, Idaho, and the Langley Gulch combined cycle power
11 plant located near New Plymouth, Idaho, which provide
12 approximately 762 MW of combined capacity.
13 Q. What are the major projects associated with
14 the Company-owned gas-fired generation facilities included
15 in Idaho Power' s request in this case and expected to be
16 complete in 2025?
17 A. Only one of the major projects expected to be
18 complete in 2025 is associated with the Company-owned gas-
19 fired generation facilities, the refurbishment of the
20 Danskin Unit 2 parts following the hot gas path inspection.
21 Q. What is a hot gas path inspection?
22 A. A hot gas path inspection is a process to
23 examine the parts of a gas turbine exposed to high
24 temperatures from the hot gases discharged from the
25 combustion process . The process involves lifting the case
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Idaho Power Company

1 for both the combustion and turbine sections of the gas
2 turbine, and removing all the components that make up the
3 combustor, including fuel nozzles, combustion baskets,
4 cross flame tubes, transitions, and other small components
5 like seals and instruments .
6 Once the covers are removed, the turbine section is
7 fully disassembled which involves removing the blade rings,
8 blades, vanes, and inter-stage seals . All removed
9 assemblies are fully disassembled down to the individual
10 components and cleaned and inspected. The assemblies are
11 then reassembled with new components and prepared to be
12 reinstalled into the turbine. The turbine case and the
13 rotor are cleaned and inspected and prepped to receive the
14 rebuilt assemblies . The turbine section and combustor
15 section are then reassembled with all new or rebuilt parts,
16 and ultimately placed back in-service.
17 Q. How often is a hot gas path inspection
18 performed?
19 A. It is recommended that hot gas path
20 inspections are performed on simple cycle combustion
21 turbines approximately every 1, 600 starts, or approximately
22 every three to five years, as recommended by the
23 manufacturer. The last hot gas path inspection on Unit 2
24 occurred in 2021 .
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Idaho Power Company

1 Q. You indicated the project costs included in
2 Idaho Power' s request in this case are associated with the
3 refurbishment of the Danskin Unit 2 parts following the hot
4 gas path inspection. When was the hot gas path inspection
5 performed?
6 A. The hot gas path inspection of Danskin Unit 2
7 was performed in the fall of 2024 . At that time, the parts
8 that were removed were replaced with capital spare parts
9 and the unit placed back in-service. In 2025, the Company
10 will refurbish those parts to have on-hand as capital
11 spares .
12 Q. What parts are anticipated to be refurbished?
13 A. During the combustor inspection, the support
14 housings, baskets, transitions, transition seals, turbine
15 blades, turbine vanes, and seal segments that were removed
16 from the unit will be refurbished. The approximately $2 . 2
17 million included in the Company' s request in this case are
18 costs associated with only the refurbishment of the Danskin
19 Unit 2 parts .
20 III . JOINTLY-OWNED GENERATION PLANT INVESTMENTS
21 Q. Please describe the Bridger and Valmy plants .
22 A. Valmy consists of two units and is located
23 near Winnemucca, Nevada. Unit 1 went into service in 1981
24 and Unit 2 followed in 1985 . Idaho Power owns 50 percent of
25 Valmy. NV Energy is the co-owner of the plant with the
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I remaining 50 percent ownership and operates the Valmy
2 facility. Idaho Power and NV Energy work jointly to make
3 decisions regarding Valmy.
4 The Bridger plant, located near Rock Springs,
5 Wyoming, consists of four generating units . PacifiCorp has
6 two-thirds ownership and is the operator of the facility
7 and Idaho Power owns one-third of Bridger. Unit 1 began
8 commercial operation in 1974, Unit 2 in 1975, Unit 3 in
9 1976 and Unit 4 in 1979 . The Company and PacifiCorp work
10 jointly to make decisions regarding the plant, including
11 required investments and the retirement of the plant.
12 Q. What is Valmy' s current position in Idaho
13 Power' s generation portfolio?
14 A. The Company exited participation in coal-fired
15 operations of Unit 1 on December 31, 2019, as accepted by
16 the Commission in Order No. 33983 as part of Idaho Power' s
17 2017 Integrated Resource Plan ("IRP") . The Preferred
18 Portfolio identified in the 2021 IRP, filed in Case No.
19 IPC-E-21-43, concluded an exit from Valmy Unit 2 in 2025
20 provided a more favorable economic outcome when compared to
21 an earlier exit . Then, the 2023 IRP Preferred Portfolio,
22 acknowledged by the Commission in IPC-E-23-23, ' included the
23 conversion of Valmy Units 1 and 2 from coal to natural gas
24 operations by summer 2026, indicating the conversion is the
1 Order No. 36233.
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Idaho Power Company

1 least-cost, least-risk option necessary to continue
2 providing reliable, economic service to customers into the
3 future .
4 Q. What is Bridger' s current position in Idaho
5 Power' s generation portfolio?
6 A. The Company' s Second Amended 2019 IRP
7 acknowledged in Case No. IPC-E-19-19 identified a preferred
8 portfolio that included early Bridger unit exits in 2022,
9 2026, 2028, and 2030 . Subsequently, the 2021 IRP Preferred
10 Portfolio, filed in Case No . IPC-E-21-43, included the
11 conversion of Units 1 and 2 from coal to natural gas by the
12 summer of 2024, and the exit of coal-fired operations in
13 Units 3 and 4 by year-end 2025 and 2028, respectively.
14 Further, the 2023 IRP acknowledged in Case No. IPE-E-23-23
15 again identified the conversion of Units 1 and 2 from coal
16 to natural gas by the summer of 2024, and also identified
17 the conversion of Units 3 and 4 from coal to natural gas by
18 the summer of 2030 as a cost-effective resource
19 alternative. Bridger Units 1 and 2 began natural-gas
20 operations in 2024 .
21 Q. Has the Commission approved certain ratemaking
22 treatment associated with the coal investments in Valmy and
23 Bridger based on the early exit of coal-fired operations?
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Idaho Power Company

1 A. Yes . In Case Nos . IPC-E-16-242 and IPC-E-21-
2 17,3 Idaho Power received approval of a balancing account
3 mechanism for Valmy and Bridger, respectively, that is
4 designed to smooth revenue requirement impacts associated
5 with the early exit of coal-fired operations, allowing for
6 full recovery of coal-related costs when cessation of coal-
7 fired operations would occur. These mechanisms, which are
8 described in more detail in Company Witness Mr. Matthew T.
9 Larkin' s testimony, more closely align the cost recovery
10 period with the remaining period for which coal-fired
11 operations would occur, resulting in a better matching of
12 cost recovery from customers who benefit from the plant' s
13 operations while mitigating the risk of future customers
14 bearing the costs of coal-related investments that will no
15 longer be providing service.
16 Q. With the conversion of some units to natural
17 gas operations and the resulting differing end-of-life
18 dates of the four Bridger units, was it necessary to
19 separate the coal-related assets from the gas-related
20 assets in Idaho Power' s accounting records?
21 A. Yes . With the conversion of Bridger Units 1
22 and 2 to natural gas operations in 2024, and commencement
23 of the conversion of Valmy Unit 1 to natural gas operations
2 Updated in Case No. IPC-E-19-08. Approved with Order Nos. 33771 and
34349.
3 Order No. 35423.
ADELMAN, DI 21
Idaho Power Company

1 in 2025, the co-owners have identified and separated the
2 coal-related investments from gas-related investments
3 within the plant accounting records . This allows for
4 application of the varying end-of-life dates between the
5 units for ratemaking purposes . As described in Mr. Larkin' s
6 testimony, the balancing account mechanisms will continue
7 to track levelized revenue requirement amounts associated
8 with coal-related investments for both Valmy and Bridger
9 while the revenue requirement associated with natural gas-
10 related investments is calculated along with all other
11 generation assets as part of this case. In my testimony I
12 will discuss the gas-related investments separate from the
13 coal-related investments included in balancing account
14 mechanisms .
15 Q. As a partial owner in both plants, is Idaho
16 Power involved in the decision-making process related to
17 capital investments at the jointly-owned plants?
18 A. Yes . Although the Company is not the operator
19 of either plant, and therefore does not manage the capital
20 budget, Idaho Power has established guidelines to allow
21 both NV Energy and PacifiCorp to manage the capital budget
22 as needed and directed by the plant manager, without
23 exceeding the yearly budget, or adding large projects
24 without authorization by the Company. These guidelines
25 provide the appropriate level of oversight while allowing
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Idaho Power Company

1 the plant operator to practically manage the plant and any
2 variances that may occur throughout the budget year.
3 Q. Aside from the guidelines, are there any other
4 ways the Company participates in the capital budget
5 process?
6 A. Yes . Individual capital project variances are
7 discussed during ownership meetings and other meetings as
8 directed by the co-owners . In addition, the operator of the
9 plant prepares an authorization request for all capital
10 projects that includes the project title, date, description
11 and purpose of the expenditure, cost and budget
12 information, along with various other information to
13 provide support for the project. NV Energy produces an
14 Authorization for Expenditures for Valmy capital projects
15 while PacifiCorp produces an Appropriation Request for
16 Bridger capital projects .
17 Jointly-Owned Generation Facilities : Natural Gas Operations
18 Investments
19 Q. What are the major projects associated with
20 Idaho Power' s jointly-owned generation plants that are
21 included in the Company' s request in this case and expected
22 to be complete in 2025?
23 A. There are three major projects associated with
24 Idaho Power' s jointly-owned generation assets included in
25 the Company' s request in this case, the (1) costs
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Idaho Power Company

1 associated with the conversion of Valmy Unit 1 to natural
2 gas operations, (2) Valmy Unit 1 generator rewind, and (3)
3 major overhaul of the Valmy Unit 1 turbine.
4 Q. You indicated Idaho Power exited participation
5 in coal-fired operations of Valmy Unit 1 on December 31,
6 2019, but the Company has included the costs associated
7 with the conversion to natural gas operations in this case .
8 Will Idaho Power be participating in operations of Valmy
9 Unit 1 again?
10 A. Yes, if the Commission approves the Company' s
11 request in Case No. IPC-E-25-03, In the Matter of Idaho
12 Power Company's Application for Approval of the North Valmy
13 Power Plant Natural Gas Conversion Agreement with NV
14 Energy, which is currently pending. In that case, the
15 Company has requested approval of the Natural Gas
16 Conversion Agreement between Sierra Pacific Power Company
17 d/b/a NV Energy and Idaho Power associated with Valmy,
18 which would allow for the Company' s participation in
19 natural gas operations of Unit 1 following its conversion
20 by December 30, 2025 . As such, the largest major project
21 associated with Idaho Power' s jointly-owned generation
22 assets included in the Company' s request in this case, at
23 approximately $17 . 2 million, is associated with the
24 conversion of Unit 1 to natural gas operations .
ADELMAN, DI 24
Idaho Power Company

1 Q. Who is performing the work to convert Unit 1
2 to natural gas operations?
3 A. On February 6, 2024, NV Energy issued a
4 Request for Proposals for Engineering, Procurement, and
5 Construction ("EPC") services for the conversion of the
6 Valmy units to natural gas operations . The fair and
7 competitive solicitation process resulted in the awarding
8 of a contract to an EPC contractor, TEI Construction
9 Services Inc. ("TEiC") , with firm-fixed pricing, on
10 November 18, 2024 .
11 Q. What work will be performed to prepare for
12 conversion of Unit 1 to natural gas operations?
13 A. To ensure Unit 1 is operating on natural gas
14 by December 30, 2025, the boilers will be converted from
15 using pulverized coal to using natural gas, while
16 maintaining the specified, heat duty, superheater and
17 reheater steam flows and temperatures . The boiler
18 modifications generally consist of new low nitrogen oxide
19 natural gas burners, with all associated wind-box
20 modifications, ductwork, dampers, and control logics .
21 The coal firing and coal ash handling equipment,
22 particulate emission control equipment and other equipment
23 and components for the boiler, which are not required after
24 conversion, will be removed or abandoned in place to allow
25 space for the installation of the new equipment. The extent
ADELMAN, DI 25
Idaho Power Company

1 of the demolition for the coal burners, boiler
2 penetrations, coal feeder piping, ductwork, and all other
3 components will be determined once work commences . The
4 existing air preheaters will be modified and it is expected
5 that the flue gas ductwork going to the primary air
6 preheaters will need to be blanked off to account for the
7 lack of primary air. The conversion will also require the
8 complete modification of (1) combustion equipment and
9 associated auxiliary equipment, which will be designed and
10 installed to ensure compliance with emission limits, (2)
11 secondary air and flue gas system, and (3) boiler controls .
12 Q. What new installations will occur to allow for
13 natural gas operations of Unit 1?
14 A. To allow for natural gas operations, the
15 addition of a natural gas pressure conditioning and
16 regulating station is required. This encompasses the
17 installation of (1) the low-pressure skid, (2) the piping
18 from the high-pressure skid and heater skid to the low-
19 pressure skid inside the plant, (3) all piping from the
20 low-pressure skid to the burners, and (4) all burners for
21 the Unit 1 boiler, including the double block and bleed
22 valves . This work includes all necessary control valves,
23 engineering for all pressure parts, pipe routing,
24 installation, check out, tuning, and guarantees on steam
25 pressure and temperature, and nitrogen oxide emissions .
ADELMAN, DI 26
Idaho Power Company

1 Q. How will natural gas be supplied to the plant?
2 A. Idaho Power anticipates execution of a
3 transport service agreement for firm transport capacity on
4 the Ruby Pipeline, owned by Tallgrass Energy. The Ruby
5 Pipeline transport capacity will flow east to west, with
6 receipt at the Opal trading hub and delivery at the Pinyon
7 lateral, which is the Valmy interconnect. The Company will
8 be responsible for procuring, scheduling and nominating
9 fuel from Opal to Valmy. Idaho Power will also be able to
10 purchase gas delivered directly to the Pinyon lateral .
11 Q. Will new facilities be required to deliver the
12 natural gas to the plant?
13 A. Yes . Tallgrass Energy will construct a
14 pipeline that connects the plant to the Ruby Pipeline, the
15 Pinyon Lateral, including installation of a gas heater and
16 the high-pressure skid. Gas transportation on the Pinyon
17 pipeline to the plant will be secured via execution of a
18 transport service agreement between NV Energy and
19 Tallgrass . Idaho Power intends to secure transportation on
20 Pinyon to fuel its share of Valmy by executing either a
21 Capacity Release Agreement with the transporter, or an
22 Asset Management Agreement with NV Energy. The costs for
23 the gas service on both Ruby and Pinyon will be recorded as
24 a fuel expense.
ADELMAN, DI 27
Idaho Power Company

1 Q. When will construction of the Valmy-owned
2 natural gas facilities occur?
3 A. Commencement of construction will be
4 coincident to the outage of Unit 1 which is scheduled for
5 September 15, 2025 . The work is scheduled to be complete
6 and Unit 1 online and available for dispatch by December
7 30, 2025 .
8 Q. You indicated two other major projects
9 included in the Company' s request in this case and expected
10 to be complete in 2025 are associated with Valmy Unit 1,
11 the generator rewind and the overhaul of the turbine . Are
12 these projects necessary considering the unit is being
13 converted to natural gas operations?
14 A. Yes . The conversion to natural gas operations
15 does not require a new generator or turbine therefore the
16 existing Unit 1 generator and turbine must continue to be
17 maintained. To minimize future outages, when the unit is
18 taken out of service in the fall of 2025 for conversion to
19 natural gas operations, the plant will perform a generator
20 rewind on Unit 1 and an inspection and major overhaul of
21 the Unit 1 turbine .
22 Q. What does a generator rewind entail?
23 A. The generator rewind involves the disassembly,
24 cleaning, and inspection of the Unit 1 generator followed
25 by a complete rewind of the rotor and stator windings . The
ADELMAN, DI 28
Idaho Power Company

1 cooling for the stator core and rotor is a hydrogen cooled
2 system, which will also be inspected and repaired, as
3 needed. A 2016 inspection revealed that the insulation in
4 the unit had been contaminated, resulting in deterioration
5 of the unit .
6 Q. Was a generator rewind performed following the
7 inspection results?
8 A. No. While the insulation showed deterioration,
9 it was not yet impacting the reliability of the unit and
10 therefore the plant continued to monitor the condition.
11 However, if the generator insulation fails, the unit could
12 be offline for approximately one year in order to complete
13 repairs due to the current lead time on parts . Because Unit
14 1 is being taken offline for conversion to natural gas
15 operations, and to ensure the unit will continue to
16 maintain its high dependability and reliability, the
17 decision was made to perform the rewind now to ensure
18 continued safe, reliable operations of Unit 1 once the unit
19 is back online.
20 Q. What is the Company' s share of the Unit 1
21 generator rewind costs included in Idaho Power' s request in
22 this case?
23 A. The Company' s share of the costs associated
24 with the rewind of the Unit 1 generator is anticipated to
ADELMAN, DI 29
Idaho Power Company

1 be approximately $6 . 2 million with work to be completed in
2 December 2025 .
3 Q. What does the turbine inspection and overhaul
4 entail?
5 A. During the inspection, the turbine rotating
6 blades, stationary blades, valve parts, and steam seals
7 will be inspected from both a borescope and internal
8 inspection. Worn or damaged capital components will be
9 replaced during the outage. The replacement of the turbine
10 parts if worn or damaged ensures the plant maintains its
11 high dependability and reliability.
12 Q. What is Idaho Power' s share of the Unit 1
13 turbine major overhaul costs included in the Company' s
14 request in this case?
15 A. Idaho Power' s share of the costs associated
16 with the overhaul of the Unit 1 turbine are anticipated to
17 be approximately $4 . 4 million with work to be completed in
18 December 2025 .
19 Q. Are there any other investments associated
20 with Idaho Power' s jointly-owned generation plants that you
21 would like to discuss?
22 A. Yes . As discussed in Mr. Larkin' s testimony,
23 as part of the Company' s request to update the levelized
24 revenue requirement amounts associated with the Valmy and
25 Bridger balancing account mechanism, Idaho Power is also
ADELMAN, DI 30
Idaho Power Company

1 requesting a prudence determination of actual Valmy and
2 Bridger coal-related investments made since the last
3 prudence determination occurred.
4 Q. When was the Company' s last request for a
5 prudence determination of Valmy and Bridger coal-related
6 investments?
7 A. As part of the Company' s last general rate
8 case, Case No . IPC-E-23-11, the Commission found that all
9 Valmy and Bridger coal-related investments through December
10 31, 2022, were prudently incurred. Therefore, Idaho Power
11 is requesting a prudence determination on the Valmy and
12 Bridger coal-related investments made during the January 1,
13 2023, through December 31, 2024, time period.
14 Jointly-Owned Generation Facilities : Valmy Coal-Related
15 Investments
16 Q. What is the Company' s share of Valmy coal-
17 related investments for which a prudence determination is
18 requested?
19 A. Exhibit No. 3 presents Idaho Power' s share of
20 the coal-related investments made at Valmy between January
21 1, 2023, and December 31, 2024, detailing 41 different
22 capital projects totaling $4 . 7 million. In addition, for
23 those projects for which Idaho Power' s ownership share is
24 over $200, 000, the Company has included a project
25 description and investment purpose classification as to
ADELMAN, DI 31
Idaho Power Company

1 whether the investment was for environmental compliance,
2 safety, and/or reliability. Of the nine projects for which
3 a detailed project description and investment purpose
4 classification was provided, three were required for
5 environmental compliance, three were for continued reliable
6 plant operations, and three were for a combination of
7 either reliability, environmental compliance, or safety.
8 Valmy Environmental Compliance Investments
9 Q. What were the three coal-related investments
10 necessary for environmental compliance?
11 A. The largest of the coal-related investments,
12 at $1 . 1 million, made at Valmy during the January 1, 2023,
13 through December 31, 2024, time period was for
14 environmental compliance: the replacement of the ten
15 baghouse bags associated with Unit 2 . Two additional
16 investments were made for environmental compliance
17 including the bottom ash sludge return system update and
18 installation of a stack mercury monitor on Unit 2 .
19 Q. What are baghouse bags used for?
20 A. The baghouse system controls and mitigates
21 pollutant emissions and is required for environmental
22 compliance. The baghouse contains bags that are suspended
23 inside a casing, with fans blowing the dirty air through
24 the filters, capturing the particulate matter and solids
25 while pushing clean air through an outlet. A minimum of
ADELMAN, DI 32
Idaho Power Company

1 nine out of ten baghouse compartments are required to be in
2 service to reach full load. Over time, the baghouse bags
3 become fouled and deteriorate. Throughput, residual acid,
4 and moisture content in the flu gas can affect the rate of
5 deterioration of the bag materials .
6 Q. How long do the baghouse bags typically last?
7 A. Baghouse bags are routinely inspected and
8 sampled to help in determining the remaining life of the
9 bags but must be sent to an independent lab for a more
10 thorough bag life analysis . A 2021 report indicated that
11 with the forecasted run time, the bags were expected to
12 last beyond cessation of coal-fired operations in 2025 .
13 However, in 2022, due to opacity issues that cause the unit
14 to trip, the bags were sent off again for testing. It was
15 determined the bag replacement was necessary to maintain
16 opacity within environmental permit limits without having
17 to derate for repairs .
18 Q. What did the bottom ash sludge return system
19 update project entail?
20 A. The bottom ash system, which supports both
21 Valmy units, produces a large volume waste stream of water
22 that flows to the evaporation ponds . The evaporation pond
23 surface area available to evaporate water was reduced by 33
24 percent when two ponds were taken out of service with the
25 anticipated retirement of Unit 1 and the reduced operation
ADELMAN, DI 33
Idaho Power Company

1 of Unit 2 . However, because of the change in the forecast
2 and increased operation, the evaporation pond levels
3 increased. Rather than re-lining an additional evaporation
4 pond to provide increased surface area for evaporation of
5 the wastewater, it was determined that removing the solid
6 carryover from the dewatering bins to the settling and
7 surge tanks, allowing the bottom ash system water to be
8 reused in the plant, was more cost-effective .
9 Q. Was the bottom ash sludge return system
10 necessary considering cessation of coal-fired operations is
11 going to occur in 2025?
12 A. Yes . The water flow to the evaporation ponds
13 had to be reduced to keep the pond freeboard within permit
14 limits . In addition, if no action was taken, the plant
15 would risk forced derates or outages to stay within permit
16 limits . At a cost of approximately $385, 000, the bottom ash
17 sludge project was necessary to maintain the reliability of
18 the plant.
19 Q. What drove the need for the installation of a
20 stack mercury monitor?
21 A. Unit 2 utilizes sorbent traps as the
22 compliance measure for mercury emissions . The traps were
23 normally changed weekly and the information manually
24 entered into a software program that calculated and
25 reported the mercury pounds emissions level . The mercury
ADELMAN, DI 34
Idaho Power Company

1 emissions for both units are combined, and a 30-day average
2 is reported. If mercury emissions were trending upward, the
3 traps were analyzed more frequently but would result in a
4 one-week lag in mercury emission reporting. As a result of
5 an error in the manual compilation and input of mercury
6 emissions data, the plant believed it had an excess mercury
7 emission event, which could have resulted in several days
8 of excess emissions . Although no violations occurred, to
9 eliminate the risk of mercury excess emissions through the
10 use of only mercury sorbent traps, a stack mercury monitor
11 was installed.
12 Q. What does a stack mercury monitor do?
13 A. The stack mercury monitor provides an
14 additional monitoring system, providing a more real time
15 indication of mercury emissions . In addition, installation
16 of the monitor improves the response time to increase the
17 frequency of mercury trap analysis and/or the blending of
18 lower mercury coal to reduce mercury emissions . Idaho
19 Power' s share of the stack mercury monitor investment is
20 approximately $249, 000 .
21 Valmy Reliability Investments
22 Q. What were the three Valmy coal-related
23 investments necessary for reliability?
24 A. The three coal-related investments made at
25 Valmy during the January 1, 2023, through December 31,
ADELMAN, DI 35
Idaho Power Company

1 2024, time period for reliability purposes, totaling
2 approximately $1 . 0 million, were for the replacement of the
3 boiler penthouse insulation, restoration of a pulverizer
4 gearbox for use as a capital spare, and the replacement of
5 10 coal conveyor belts at Valmy.
6 Q. What drove the need for the replacement of the
7 insulation in the boiler penthouse?
8 A. The Unit 2 boiler penthouse insulation had
9 been damaged due to casing leaks that allowed water in from
10 the roof as well as ash from the floor. The continued
11 degradation of the insulation resulted in portions of the
12 roof section falling away from the support structure .
13 Repairs were made to slow the progression of the damage,
14 but the damage was to the point where the integrity of the
15 penthouse casing was a concern.
16 Q. Were there any alternatives to the replacement
17 of the insulation?
18 A. No. Absent the replacement, the plant may have
19 experienced forced outages, resulting in a loss of
20 reliability. In addition, damage or failure of the internal
21 high pressure steam components is a safety concern due to
22 the proximity of plant employees . With a cost of
23 approximately $450, 000, the replacement of the Unit 2
24 boiler penthouse insulation was necessary to maintain the
25 reliability of the unit.
ADELMAN, DI 36
Idaho Power Company

1 Q. How does a pulverizer gearbox support the
2 reliability of Unit 2?
3 A. Four pulverizers are needed to reach full load
4 status of Unit 2 therefore when a pulverizer fails,
5 derating of the unit occurs . In 2021, the capital spare
6 pulverizer gearbox was installed on the unit and following
7 inspection of the failed gearbox that was removed, it was
8 determined it was restorable. At approximately $302, 000,
9 this project includes the restoration of the pulverizer
10 gearbox; having a spare is crucial to maintaining the
11 reliability of Unit 2 should one of the gearboxes fail .
12 Q. Why was it necessary to replace the coal
13 conveyor belts?
14 A. Two separate vendors performed conveyor belt
15 inspections and the reports indicated 10 of the 11 conveyor
16 belts needed replacement due to the increase in the
17 forecast for the remaining period of coal-fired operations .
18 With a lead time of over six months for conveyor belt
19 materials, it was necessary to replace the belts to ensure
20 that redundant conveyors are available to maintain a
21 reliable coal supply to the plant. Idaho Power' s share of
22 the investment in the conveyor belts was approximately
23 $266, 000 .
ADELMAN, DI 37
Idaho Power Company

1 Valmy Other Coal-Related Investments
2 Q. Please describe the three projects that were
3 for a combination of either reliability, environmental
4 compliance, or safety.
5 A. The largest of the three investments was for a
6 combination of environmental compliance and safety and
7 included the replacement of the coal piping for Unit 2 . The
8 plant had been experiencing considerable erosion in the
9 coal piping that runs between the pulverizers and the
10 burners . The erosion results in coal leaks which become
11 both an environmental issue and fire hazard. Following
12 testing, it was determined there were four coal pipes that
13 needed elbow replacement. Replacement of the coal piping,
14 for a total cost to Idaho Power of approximately $281, 000,
15 ensures compliance with the Occupational Safety and Health
16 Administration Combustible Dust initiative for safe
17 operation of Unit 2 and provides greater reliability by
18 decreasing downtime for repairs .
19 The next two investments were for a combination of
20 environmental compliance and reliability. The first was the
21 replacement of the Unit 2 pulverizer classifier and the
22 second included the costs associated with the replacement
23 of two gearboxes and two flex shafts in the scrubber spray
24 machine.
ADELMAN, DI 38
Idaho Power Company

1 Q. What is the purpose of the pulverizer
2 classifier?
3 A. The pulverizer classifier controls the
4 fineness of the pulverized coal for efficient combustion.
5 The classifier on one of the four Unit 2 pulverizers was
6 found to be damaged during the annual inspection. Without
7 the pulverizer, Unit 2 would be derated. In addition, Unit
8 2 must be able to operate at or near full load to maintain
9 certification or compliance with annual environmental
10 testing, safety valve testing and the State of Nevada
11 Boiler Operating Permits . The Company' s share of the
12 pulverizer classifier replacement is approximately
13 $225, 000 .
14 Q. What does a scrubber spray machine do?
15 A. The scrubber spray machines remove sulfur
16 dioxide from the flue gases with atomizer wheels that a
17 gearbox drives at 12, 000 revolutions per minute. The high-
18 speed components require precision balancing and tight
19 tolerance on gear clearances . All of the spray machines
20 were replaced in 2015 but three failed in 2022 . This
21 project, at approximately $222, 000, replaced two gearboxes
22 and two flex shaft scrubber spray machines that were
23 anticipated to fail and were not repairable . The scrubber
24 spray machines are necessary to ensure the plant' s
25 reliability as well as compliance with both the Title V
ADELMAN, DI 39
Idaho Power Company

1 Sulfur Dioxide ("SO2") removal and sulfur emissions as well
2 as the Mercury and Air Toxics Standards SO2 emissions
3 requirements .
4 Q. Were all the Valmy coal-related projects
5 comprising the $4 . 7 million in investments that occurred
6 between January 1, 2023, and December 31, 2024, necessary
7 for either environmental compliance, the safe and economic
8 operation of the plant, or for reliability purposes?
9 A. Yes .
10 Jointly-Owned Generation Facilities : Bridger Coal-Related
11 Investments
12 Q. What is the Company' s share of Bridger coal-
13 related investments for which a prudence determination is
14 requested?
15 A. Exhibit No. 4 presents Idaho Power' s share of
16 the coal-related investments made at Bridger between
17 January 1, 2023, and December 31, 2024, detailing 201
18 different capital projects totaling $32 . 1 million. In
19 addition, for those projects for which Idaho Power' s
20 ownership share is over $200, 000, the Company has included
21 a project description and investment purpose classification
22 as to whether the investment was for environmental
23 compliance, safety, and/or reliability. Of the 11 projects
24 for which a detailed project description and investment
25 purpose classification was provided, four were required for
ADELMAN, DI 40
Idaho Power Company

1 environmental compliance, five were for continued reliable
2 plant operations, and two were for a combination of either
3 reliability and environmental compliance.
4 Bridger Environmental Compliance Investments
5 Q. What were the four coal-related investments
6 necessary for environmental compliance?
7 A. Similar to Valmy, the largest of the coal-
8 related investments, at $20 . 1 million, made at Bridger
9 during the January 1, 2023, through December 31, 2024, time
10 period was for environmental compliance: the construction
11 of an alternative coal combustion residual ("CCR") disposal
12 site . The three additional investments made for
13 environmental compliance were specific to the selective
14 catalytic reduction ("SCR") system on Unit 3 and included:
15 the replacement of the catalyst, the installation of soot
16 blowers, and installation of a new large particle ash
17 screen.
18 Q. What drove the need for an alternative CCR
19 disposal site?
20 A. Bridger' s CCR waste pond, the flue gas
21 desulfurization ("FGD") pond 2 was nearing capacity and not
22 anticipated to meet the Environmental Protection Agency' s
23 final rule regarding disposal of CCR. The rule requires
24 compliance with specific design, operation, and closure
25 criteria for existing and new CCR impoundments, with
ADELMAN, DI 41
Idaho Power Company

1 prescriptive dates and timelines for compliance with ground
2 water quality, siting (location restrictions) , and closure
3 dates . Because the FGD pond 2 was unlined, CCR rules
4 required cessation of the receipt of CCRs . Therefore, in
5 order to meet the CCR rule obligations for closure of the
6 existing CCR impoundments, a new CCR impoundment was
7 required to be constructed to allow for continued coal-
8 fueled operation of Units 3 and 4 . As a result, the FGD
9 pond 3 was constructed.
10 Q. Where was the new pond built?
11 A. The FGD pond 3 was constructed in an old
12 evaporation pond. The existing evaporation pond was
13 repurposed to an FGD/mixed use terminal pond, predominantly
14 on existing plant property, but required the purchase of
15 adjacent land from the Bureau of Land Management to
16 facilitate the full construction and operation of the FGD
17 pond. Due to the age of the piping materials, the project
18 included the replacement of some of the existing FGD waste
19 effluent piping. Finally, a bird deterrent system was added
20 to protect migratory birds . The addition of the FGD pond 3,
21 which is designed in compliance with the CCR rule,4 will
22 allow the site to be developed with an industrial pollution
23 control volume of approximately 3, 887 acre-feet at high
24 level, or about 245 acres of surface area.
4 40 CFR Part 257.
ADELMAN, DI 42
Idaho Power Company

1 Q. Were there any additional agencies for which
2 the new FGD pond would comply?
3 A. Yes . The FGD pond complies with environmental
4 permit conditions imposed by the Wyoming Department of
5 Environmental Quality ("WDEQ") Water Quality Division, WDEQ
6 Air Quality Division, State Engineer' s Office, and the
7 federal Bureau of Land Management.
8 Q. Bridger Units 1 and 2 were converted to
9 natural gas operations in 2024 . Did that change the need
10 for the new CCR disposal site?
11 A. No. The cessation of coal-fired operations of
12 Units 1 and 2 was considered when estimating the need for
13 the new FGD pond. In fact, the FGD pond 3 will also serve
14 as a terminal holding point for effluent water from the
15 cooling cycle, and for evaporation, associated with the
16 natural gas operation of Units 1 and 2 . The addition of the
17 FGD pond 3 was necessary for environmental compliance of
18 Bridger.
19 Q. Why were investments in the SCR systems
20 required?
21 A. The SCR technology, which was commissioned on
22 Unit 3 in 2015, is a proven and effective method to reduce
23 nitrogen oxide ("NOx") emissions from coal-fired power
24 plants . Prior to being released to the atmosphere, ammonia
25 is injected into the exhaust flue gas and is passed through
ADELMAN, DI 43
Idaho Power Company

1 a series of catalyst where the NOx reacts with the catalyst
2 and ammonia and is converted to nitrogen and water. The
3 catalyst is a key component of the SCR and catalyst
4 activity, or its ability to reduce NOx, diminishes with
5 service life, and fly-ash pluggage. In addition, other
6 elements found in flue gas can poison or block active
7 catalytic sites in the catalyst rendering it ineffective .
8 As a result, catalysts must be replaced periodically for
9 Unit 3 to comply with the Air Quality Permit with the WDEQ.
10 In 2023, at a cost of $1 . 6 million to Idaho Power, a
11 replacement catalyst for the Unit 3 SCR was installed.
12 Q. What additional investments in the SCR systems
13 were required?
14 A. In addition to the catalyst, new sootblowers
15 were installed and repairs were made to the large particle
16 ash screen on the Unit 3 SCR system. Sootblowers were
17 installed on the first layer of the catalyst as the first
18 layer is typically most susceptible to fly ash buildup. As
19 ash accumulates in the catalyst it blocks off catalyst
20 material from being available for the NOx reaction to take
21 place . Because not all ash can effectively be vacuumed or
22 removed by other means, it can lead to the permanent
23 "poisoning" of the catalyst, reducing the catalyst' s
24 overall potential . To ensure the service life of the
25 catalyst was maximized, 16 sootblowers were added to the
ADELMAN, DI 44
Idaho Power Company

1 Unit 3 SCR system, increasing the effectiveness of the
2 catalyst . The Company' s share of the additional sootblowers
3 is approximately $552, 000 .
4 The large particle ash screen helps ensure optimal
5 catalyst performance and service life by preventing large
6 fly ash pieces from blocking flue gas flow through the
7 catalyst . The catalyst guarantee states that the ash
8 accumulations shall be less than 10 percent of the open
9 free area and plugging affects the catalyst performance .
10 However, over time the fly ash erodes the large particle
11 ash screen and it must be replaced. Left alone, the ash
12 accumulation could lead to a forced outage of the unit.
13 Therefore, in 2023, at a cost of approximately $280, 000,
14 the large particle ash screen was replaced on the Unit 3
15 SCR system.
16 Bridger Reliability Investments
17 Q. What were the five Bridger coal-related
18 investments necessary for reliability?
19 A. There were five coal-related investments made
20 at Bridger during the January 1, 2023, through December 31,
21 2024, time period for reliability purposes, totaling
22 approximately $1 . 9 million: (1) a new heating system in the
23 southend of the powerblock building, (2) installation of
24 four retractable sootblowers on Unit 3, (3) installation of
25 four retractable sootblowers on Unit 4, (4) replacement of
ADELMAN, DI 45
Idaho Power Company

I the first stage buckets on the high-pressure turbine, and
2 (5) replacement of pumps, valves and gearboxes .
3 Q. What drove the need for the new heating system
4 in the Southend of the powerblock building?
5 A. Bridger Units 1, 2 and 3 share a building with
6 Unit 4 narrowly connected at the first and third floor. All
7 four units initially had heating coils at 10th elevation
8 which would heat recirculated air and draw outside air. The
9 coils were damaged due to freezing and the system was
10 abandoned. The two buildings from thereafter relied on
11 convective and radiative heat transfer from exhausted heat
12 of the equipment in the rooms . The shared units' building
13 maintained adequate heat, however because the Unit 4
14 building was separate from the others, a heating system was
15 installed in 2018 to keep the equipment from freezing.
16 Convective and radiative heat transfer from
17 equipment had been relied upon for the Units 1, 2, and 3
18 building for getting through the Wyoming winters . The plant
19 was however experiencing continued problems of equipment
20 freezing if one of the units was shut down. Further, the
21 building maintains negative pressure during winters because
22 of this heating approach which can negatively impact other
23 HVAC equipment in the building. Finally, because the
24 building also contains chemical treatment equipment that
25 supports critical process chemistry of Units 1, 2 and 3, as
ADELMAN, DI 46
Idaho Power Company

1 well as domestic water chemistry for the plant, it was
2 critical for the remaining building to maintain heat and
3 avoid the freezing of chemical treatment equipment.
4 Q. What work was required to address the
5 inadequate heat in the southend of the powerblock building?
6 A. This project necessitated the replacement of
7 heating coils on Unit 1 and 2, refurbishing of the chemical
8 treatment equipment air handler and restoration of the main
9 HVAC to limited capacity, providing support for maintaining
10 temperatures above 45 degrees Fahrenheit, and continued
11 reliable operations of the units . Idaho Power' s share of
12 the project costs is approximately $670, 000 .
13 Q. You indicated four retractable sootblowers
14 were installed on both Unit 3 and Unit 4 . How do these
15 differ from the sootblowers installed on the Unit 3 SCR
16 system?
17 A. While they serve a similar purpose, the
18 retractable sootblowers installed on both Units 3 and 4
19 were installed in the boiler at the front of the pendant
20 reheater assemblies, the heat exchanger, and the front of
21 the final superheater assembly, which reduces corrosion
22 from sulfur content and abrasion by sand. The sootblowers
23 will serve to keep the waterwalls and platen assemblies
24 clean which is necessary to maintain the reliability of the
25 boiler.
ADELMAN, DI 47
Idaho Power Company

1 Q. Do the retractable sootblowers replace
2 sootblowers that had been installed previously?
3 A. No. Because of the closure of the underground
4 mine, Bridger Coal Company is delivering fuel that contains
5 higher sodium, calcium and iron contents of the coal, which
6 are projected to continue to increase. These constituents
7 contribute to ash plugging the pendent assemblies and the
8 fouling and plugging of the boiler, resulting in load
9 reductions and forced outages . Testing performed in 2018
10 and 2020 showed that additional retractable sootblowers
11 will aid in the reduction of the ash and slag accumulation.
12 The Unit 4 retractable sootblowers were installed in 2023
13 for a project cost of approximately $325, 000 and the Unit 3
14 retractable sootblowers were installed in 2024 for a
15 project cost to Idaho Power of approximately $430, 000 .
16 Q. How does the replacement of the first stage
17 buckets on the high-pressure turbine impact reliability?
18 A. During the 2015 annual overhaul of Unit 3, a
19 steam path audit was performed that identified solid
20 particle erosion on the first stage turbine blades, the
21 first set of turbine blades that high-pressure steam
22 encounters . A bucket failure is costly and requires 21 days
23 minimum for repair and with the next major overhaul not
24 scheduled to occur until 2031, it was necessary to replace
25 the first stage buckets in 2023 to continue the safe,
ADELMAN, DI 48
Idaho Power Company

1 reliable operations of Unit 3 . Idaho Power' s share of the
2 project costs are approximately $235, 000 .
3 Q. What is the last project necessary to maintain
4 reliable operations at Bridger?
5 A. The last reliability-related investment is
6 associated with the annual blanket projects for pumps,
7 valves and motors . This blanket project was intended to
8 capture capital issues that arise, typically mechanical
9 equipment failures that were unplanned and therefore not
10 individually identified and budgeted. In 2022, multiple
11 major repairs occurred resulting in the need for additional
12 funds . The major repairs that contributed to the additional
13 funding included a required rebuild of a central air
14 compressor, the main steam hanger riser clamp repairs on
15 Unit 2 and the repair of a leak in the cooling tower riser.
16 Q. If the work was performed in 2022, why did the
17 project costs close in 2023?
18 A. As part of the budgeting process, funds are
19 set aside for the unplanned equipment failures but because
20 of the extensive repairs required in 2022 and additions of
21 projects late in the year, some of the project costs
22 extended into 2023 . Several projects had delays for
23 materials and/or services, including the central air
24 compressor rebuild. The delivery of materials required for
25 the rebuild of the compressor took longer than expected,
ADELMAN, DI 49
Idaho Power Company

1 extending a portion of the costs into 2023 . Idaho Power' s
2 share of these additional costs associated with the blanket
3 pumps, valves and motors projects is approximately
4 $212, 000 .
5 Bridger Other Coal-Related Investments
6 Q. Please describe the two projects that were for
7 a combination of reliability and environmental compliance .
8 A. The largest of the investments necessary for a
9 combination of reliability and environmental compliance was
10 associated with the rehabilitation of the firing equipment
11 on Unit 3 to ensure proper combustion and reduce emissions .
12 The burner tilt system of the Unit 3 boiler is subject to
13 erosion and thermal stress . High rates of erosion had been
14 seen by the coal nozzle tips such that much of the nozzle
15 had eroded away. If a piece of the nozzle were to break
16 free, the sharp edges could cause a tube leak as it falls
17 into the boiler. In addition, by nature of their design,
18 the burners suffer thermal warping and fatigue as immense
19 heat is generated by the fireball . Over time, this heat
20 will warp the air and coal tips . Once the tips have reached
21 this point, combustion quality degrades . When combustion
22 degrades, NOx and carbon monoxide emissions increase, and
23 heat rate rises . Replacement of the Unit 3 burner tilt
24 system components, for a cost of approximately $651, 000,
25 ensure optimum boiler firing and reduced fuel costs,
ADELMAN, DI 50
Idaho Power Company

1 maximizes heat input to the boiler, and helps keep
2 emissions at required levels .
3 Q. What is the second Bridger investment
4 necessary to ensure reliability and environmental
5 compliance?
6 A. At a cost to Idaho Power of approximately
7 $248, 000, the water wagon was rebuilt. Water wagons are
8 used onsite daily for fugitive dust control to fulfill
9 environmental regulations . While typically used at the ash
10 landfill and throughout the plant site for dust control
11 activities, in the event of a large fire, water wagons can
12 be utilized to support emergency responders in firefighting
13 efforts . Due to the age of one of the water wagons, a
14 frame-up rebuild was required to maintain fleet reliability
15 at Bridger.
16 IV. CONCLUSION
17 Q. Please summarize your testimony.
18 A. The Company' s investments in its production
19 plant assets, including steam-, hydroelectric-, and other-
20 production investments, since conclusion of Idaho Power' s
21 2024 Limited Scope Case are critical to ensuring Idaho
22 Power can continue to provide safe, reliable electric
23 service to customers . In addition, the Company has been
24 required to make coal-related investments at Valmy and
25 Bridger. Between January 1, 2023, and December 31, 2024,
ADELMAN, DI 51
Idaho Power Company

1 there were 41 different coal-related investments made at
2 Valmy totaling $4 . 7 million, and 201 different coal-related
3 investments made at Bridger totaling $32 . 1 million, all of
4 which were required for either environmental compliance,
5 safety, and/or reliability.
6 Q. Does this conclude your direct testimony in
7 this case?
8 A. Yes, it does .
9
10
ADELMAN, DI 52
Idaho Power Company

1 DECLARATION OF RYAN N. ADELMAN
2 I, Ryan N. Adelman, declare under penalty of perjury
3 under the laws of the state of Idaho:
4 1 . My name is Ryan N. Adelman. I am employed by
5 Idaho Power Company as the Vice President of Power Supply.
6 2 . On behalf of Idaho Power, I present this
7 pre-filed direct testimony and Exhibit Nos . 3 and 4 in this
8 matter.
9 3 . To the best of my knowledge, my pre-filed
10 direct testimony and exhibits are 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 30th day of May 2025, at Boise, Idaho.
16
A
17 Signed:
18 Ryan Adelman
ADELMAN, DI 53
Idaho Power Company

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-16
IDAHO POWER COMPANY
ADELMAN , DI
TESTIMONY
EXHIBIT NO. 3

VALMY COAL-RELATED PLANT ADDITIONS:Jan 1,2023-Dec 31,2024
Project Work Order Description V2 VC Grand Total Purpose Project Description/justification
Baghouse bags become fouled and deteriorate over time.Throughput,residual acid,and moisture content in the flu
Environmental gas effect the rate of deterioration of the bag materials.It is anticipated that bag replacement will be necessaryto
maintain opacity within environmental permit limits without having to derate for repairs.Bags are routinely
respected and sampled to help in determining the remaining life of the bags.
27604616 VALMY 10091593 V2 BAGHOUSE BAG REPLACEMENT 1,061,727 1,061,727
Unit 2 boiler penthouse insulation had experienced significant damage due to a variety of factors,including damage
from ash and water leaks,increased expansion/contraction due to the plants operating profile change of cycling and
Reliability aging materials.The insulation needed to be replaced to be able to maintain the integrity of the penthouse casing,
protection of the internal components from excessive thermal stress,restore safety of the employee work area,as
well as preserve the reliability that would suffer in the event of damage/failure due to the internal high pressure
steam components.
27577134 VALMY 98485330 V2 BOILER PENTHOUSE INSULATION 449,710 449,710
The bottom ash system produces a large volume waste stream of water that flow to the evaporation ponds.The
evaporation pond surface area available to evaporate water was reduced by 33%when pond D and pond E were
taken out of service with the anticipated retirement of Unit 1 and half the load operation of Unit 2.The increase in
Environmental load forecast is causing the evaporation pond levels to increase.The water flow to the evaporation ponds needs to
be reduced to keep the pond freeboard within permit limits.This project removed solid carryover from the
it watering bins to the settling and surge tanks in order to allow bottom ash system water to be used for seal water
rather than the service water.
27616580 VALMY 10132540 V2 BOTTOM ASH SLUDGE RETURN SYSTEM UPDATE 394,554 394,554
Four pulverizers are needed on Unit 2 to reach full load status.The availability of a spare pulverizer gearbox
Reliability Increases reliability because of the long lead times for a replacement.The Unit 2 capital spare pulverizer gearbox
was installed on the 2C pulverizer in 2021.Inspection of the failed gearbox determined it was restorable.Having a
spare gearbox will minimize derating of the unit in the event of another gearbox failure.
27604615 VALMY 10087444 V2 CAPITAL SPARE PULVERIZER GEARBOX 302,044 302,044
The plant was experiencing considerable erosion in the coal piping between the pulverizers and the burners.The
erosion resulted in coal leaks which are both a fire hazard as well as an environmental issue.Thickness testing
Environmental/Safety showed the need to replace elbows on Al,A4,Dl,&D2 coal conduits.Compliance with the OSHA Combustible Dust
initiative will help ensure the ability to safely operate Unit 2 as well as provide greater plant reliability by decreasing
pulverizer down time for repairs.
27636503 VALMY 10058357 V2 COAL PIPING REPLACEMENT 281,447 281,447
Two separate vendors performed conveyor belt inspections and their reports showed the need to replace 10
conveyor belts.Conveyor 5B was replaced in 2021 and is the only conveyor that is not recommended for
Reliability replacement.Increased load forecast for 2023-2025 is making it necessaryto replace the conveyor belts.Conveyor
belt material lead times can be over 6 months.The belts were replaced to ensure that redundant conveyors are
available to maintain a reliable coal supply to the plants.
27634445 VALMY 10268198 VC COAL CONVEYOR REPLACEMENT 265,940 265,940
Unit 2 utilizes sorbent traps as the compliance measure for mercury(Hg)emissions.The mercury traps are normally
changed weekly and the information manually entered into a software program that calculates and reports the
mercury pounds per trillion BTU emission level.If mercury emissions are trending upward,the traps can be analyzed
more frequently.This can result in up to a one week lag in mercury emission reporting.Valmy mercury emissions are
Environmental a 30 day averaging plan for both units combined.The plant believed they had an excess mercury emission event
when mercury trap data was entered In error,which would have resulted in several days of excess emissions.
Installation new of stack mercury monitors and configuration of programming to calculate the mercury emissions
provides more real time indication of mercury emissions.The stack mercury monitors provide an additional
monitoring system as well as improve the response time to increase the frequency of mercury trap analysis and/or
blending of lower mercury coal.
27638554 VALMY 10279319 V2 STACK MERCURY MONITOR 249,335 249,335
Unit 2 Pulverizer A Classifier was found to be damaged during the annual inspection.Replacement of the classifier
was necessary to ensure the reliable operation of the pulverizer and properly control the fineness of the pulverized
Environmental/Reliability coal for efficient combustion.All four pulverizers are required to reach full load.Without the 2A Pulverizer available,
the unit is limited to approximately 230 M W.In addition to ensuring that the unit is dispatchable for full load during
the year,annual environmental testing,safety valve testing and State of Nevada Boiler Operating Permits all require
the unit to operate at or near full load to maintain certification/compliance.
27659537 VALMY 10429158 V2 PULVERIZER A CLASSIFIER REPLACEMENT 225,353 225,353
The scrubber spray machine gearbox drives atomizer wheels at 12,000 rpm for sulfur dioxide removal.The high
speed components require precision balancing and tight tolerance on gear clearances.This project replaced two
Environmental/Reliability gearbox and two flex shafts that were no longer be repairable.All of the spray machines were replaced in 2015
and es 3 failed in 2022.The spray machine gearbox is necessaryto ensure the plant's reliability and environmental
compliance forthe summer peak season,for both the Title V S02 removal and sulfur emissions as well as the MATS
502 emissions.
27640942 VALMY 10229194 V2 SCRUBBER SPRAY MACHINE GEARBOX AND FLEXSHA 221,581 221,581
27626838 VALMY 10192220 V2 MAIN TURBINE BEARING#2 REPLACEMENT 159,632 159,632
27.7640 VALMY 10450965 V2 PULVERIZER A 600 HP ELECTRIC MOTOR REPLACE 150,La. 150,La.
27582989 VALMY 98489340 V2 PULVERIZER CAPITAL SPARE RO 122,308 122,308
Exhibit No.3
Case No. IPC-E-25-16
R.Adelman, IPC
Page 1 of 2

27630393 VALMY98486618VC OVATION HMI AND SERVER UPDATE 10% 104,160 104,160
27646741 VALMY 10363610VC ASH LANDFILL GROUNDWATER MONITORING WELLS 102,405 102,405
27609108 VALMY 10108935 V2 BOILER FEED PUMP,REFURBISH 95,656 95,656
27630311 VALMY 10229696 V2 SCRUBBER ATOMIZER WHEELS REPLACE MENT 93,348 93,348
27632427 VALMY 10241630V2 DEM IN ERALIZED WATER PIPING REPLACE ME NT 91,210 91,210
27616572 VALMY 10133847V2SCRUBBER SPRAY MACHINE 12 GEARBOX REPLACEM 91,128 91,128
27653130 VALMY 10417287V2SCRUBBER ATOMIZER WHEELS,REPLACE 90,797 90,797
27604612 VALMY 10087092 V2 SCRUBBER REPLACEMENT OF HVAC UNITS 70,918 70,918
27603201 VALMY 10074750 V2 TURBINE CONTROL VALVE POSITIONER REPLACEME 48,620 48,620
27626848 VALMY 10189266 VC FIRE HYDRANT REPLACEMENT 47,291 47,291
27619775 VALMY 10152592 VC RECLAIM HOPPER GRIZZLY SCREEN SECTION REP 36,643 36,643
27630314 VALMY 10229698 VC EDI MODULES,REPLACE 2 32.2% 32,944 32,944
27619675 VALMY 10152568 V2 CAPITAL SPARE BOTTOM ASH CLINKER CRUSHER 29,730 29,730
27613403 VALMY 10121585 V2 LIME TRANSFER BLOWER 2B REPLACEMENT 28,136 28,136
27619674 VALMY 10152570 VC ANNEX OFFICE BUILDING FLOOR REPLACEMENT 25,035 25,035
27634445 VALMY 10268198 VC COAL CONVEYOR REPLACEMENT 23,665 23,665
27634444 VALMY 10268193 VC RO MEMBRANE REPLACEMENT 32.2% 18,644 18,644
27626849 VALMY 10174217 V2 STACK GARAGE ROLL-UP DOOR REPLACEMENT 15,033 15,033
27568635 VALMY 98476439 VC FPS DIESEL FIRE PUMP A ENGINE REBUILD 13,547 13,547
27574748 VALMY 98483985 V2 OVATION HMI AND SERVER UPDATE 13,116 13,116
27646743 VALMY 10363608 V2 FLYASH SILO FLUIDIZING BLOWER REPLACEMENT 10,425 10,425
27596244 VALMY 98494647 VC PRODUCTION WELL 13&14 REPLACEMENT VA 7,775 7,775
27624392 VALMY 10166448 VC WEST EDI UPPER MODULE REPLACEMENT 32.2% 7,285 7,285
27626845 VALMLY 10165994 B2P OT BACKUP SERVERS NORTH 32.2% 6,016 6,016
27624391 IVALMV 10162564 V2 PRIMARY SUPERHEAT VENT VALVE REPLACEMENT 5,1771 1 5,177
27640946 VALMV 10316084 V2 SCRUBBER HALON SYSTEM REPLACEMENT 4,893 1 1 4,893
27574748 VALMY 98483985 V2 OVATION HMI AND SERVER UPDATE i 3,15 i 3,653
27616580 VALMY 10132540 V2 BOTTOM ASH SLUDGE RETURN SYSTEM UPDATE 469 469
27596247 VALMY 98494653 V02 SCRUBBER SPRAY MACHINE GEARBOX REPLACEMEN 141 1 14
Various CORRECTIONS ASSOCIATED WITH INVESTMENTS PRIOR T02023 (259,590) (1,376) (260,966)
GRANDTOTAL 4,040,602 689,974 4,730,576
Exhibit No.3
Case No. IPC-E-25-16
R.Adelman, IPC
Page 2 of 2

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-16
IDAHO POWER COMPANY
ADELMAN , DI
TESTIMONY
EXHIBIT NO. 4

BRIDGER COAL-RELATED PLANT ADDITIONS: Jan 1,2023-Dec 31,2024
Project Descr Grand Total Purpose Project Description/Justification
Environmental Development of an alternative coal combustion residual("CCR")disposal site at Bridger in anticipation of the required closure of Flue
27491667 BRIDGER 2017C100 CCR JB FGD POND 4 STAGE 1 20,106,459 Gas Desulfurization("FGD")Pond 2.
Selective catalytic reduction("SCR")technology is a proven and effective method to reduce nitrogen oxide("NOx")emissions from coal-
fired power plants.Prior to being released to the atmosphere,ammonia is injected into the exhaust flue gas and is passed through a
series of catalyst where the NOx reacts with catalyst and ammonia and is converted to nitrogen and water.Service life of this catalyst is
Environmental dependent on its environment.Other elements found in flue gas can poison or block active catalytic sites in the catalyst rendering it
ineffective.Catalyst must be replaced periodically for Unit 3 to comply with the Air Quality Permit with the Wyoming Department of
Environmental Quality.This investment was associated with the purchase and installation of a replacement catalyst for the Unit 3 SCR.
27609020 BRIDGER 2022C042 U3 SCR CATALYST REPLACEMENT 23 1,620,298
The project included the replacement of A-line Coils on Unit 1 and 2 with refurbishment of existing HVAC systems of both units and
Reliability chemical treatment equipment.The southend ofthe powerblock building lacked adequate heating and needed the new system
27619799 BRIDGER 2022/C/062/BLDGHEAT UO SOUTHEND BUILDING HEATING 22/ 670,402 installed.
27619801 BRIDGER 2022/C/073/U3BURNER U3 BURNERS MAJOR 22/23 651,264 Reliability/Environmental Rehabilitation ofthe firing equipment on Unit 3 during the 2023 overhaul to insure proper combustion and reduced emissions.
Environmental
Purchase and installation of 16 soot blowers into the Unit 3 SCR system.The additional soot blowers will increase the life and reliability 27619800 BRIDGER 2022/C/063/U35CRSB U3 SCR SOOTBLOWERS 23 551,721 ofthe catalyst.
Purchase,installation and start up of four retractable soot blowers on Unit 3 to increase the sootblowing capability in the upper section
27621617 BRIDGER 2022/C/069 U3 INSTALL 4 RETRACT STLBLS/FGT/PENT 22/2 429,465 Reliability ofthe boiler.
Purchase,installation and start up of four retractable soot blowers on Unit 4 to increase the sootblowing capability in the upper section
Reliability 27591401 BRIDGER 2021/C/035 U4 INSTALL 4 RETRACT SOOTBLOWERS 21/22 324,838 ofthe boiler.
Environmental Installation of new SCR large particle ash screens on Unit 3 to maintain the optimal catalyst performance and service life.The large
27621620 BRIDGER 2022/C/072 U3 LPA SCREEN REPLACEMENT 22/23 279,576 particle ash screens wear out overtime and needed replacement.
Reliability/Environmental This project performed a complete frame-up rebuild on one water wagon to maintain fleet reliability.
27624131 BRIDGER 2022C051 UO REBUILD WATER WAGON(B)22 248,410
Reliability Replacement ofthe first stage buckets on the high-pressure turbine due to deficiencies found during the last major overhaul ofthe Unit
27625835 BRIDGER 2022C078 U3 TURBINE 1ST STAGE BUCKET RPLCMT 22/23 234,475 3 turbine.
These funds are for the pumps,valves and gearboxes blanket project.Multiple major repairs occurred in 2022 resulting in the need for
Reliability more funds for 2023.Major repairs included a required rebuild of a central air compressor,the Unit 2 main steam hanger riser clamp
27602389 BRIDGER 2022C016 UO BLANKET-PUMPS,VALVES,GEARBOXES 22 211,609 repairs and the Unit 2 cooling tower riser leak repair.
27617873 BRIDGER 2022C058 U2 23 BCP REBUILD 22 198,769
27571835 BRIDGER 20200098 UO REPLACE 7200 VAC COMMON BUS RELAYS 21 189,674
27624152 BRIDGER 2023C009 U3 LPA SCR COLLECTION/TRANSFER CNVYR 23 178,831
27624135 BRIDGER 2022C071 U3 ECONOMIZER OUTLET TURNING VANE 22/23 173,931
27625850 BRIDGER 2023CO22 U3 NUVA FEEDER PIPING REPLACEMENT 23 172,101
27628020 BRIDGER 2023C036 U3 PRECIPITATOR RAPPING SYSTEM RPRS 23 165,476
27628012 BRIDGER 2023CO25 U3 PRECIPITATOR DUCT WORK 23 154,657
27625853 BRIDGER 2023CO27 U3 STACK BREECH COATING 23 153,929
27625851 BRIDGER 2023CO24 U3 SCRUBBER DUCTWORK 23 140,104
27604633 BRIDGER 2022C013 U3 SCR CATALYST HOIST 22 138,041
27625834 BRIDGER 2022C077 U3 TURBINE 7TH STAGE BUCKET RPLCMT 22/23 122,922
27630258 BRIDGER 2023C017 U3 APH SECTOR PLATES 23 122,190
27619798 BRIDGER 2022/C/061/CYBER UO POWER WATER CYBER SECURITY UPGRA 118,275
27625842 BRIDGER 2023C019 U3 APH SEAL REPLACEMENT 23 115,837
27648655 BRIDGER 2023C072 UO ELIMINATE COAL FEED TO U1/U2 114,775
27621621 BRIDGER 2023/C/014 U2 BCP MOTOR REWINDS COOLERS 23 113,822
27640713 BRIDGER 2023C045 UO NVR SECURITY MONITORING SYS UPGRADE 23 113,269
27624141 BRIDGER 2022C080 U3 RPLC EXISTING MILL AIR FLOW HRDWR 22 111,934
27652880 BRIDGER 2024C001 UO BLANKET-PUMPS,VALVES,GEARBOXES 24 109,316
27541813 BRIDGER 2019C091 U4 SCR CATALYST REPLACEMENT 20 107,565
27613523 BRIDGER 2022C045 UO REBUILD FRAME UP D-JOT DOZER 22 106,894
27628013 BRIDGER 2023C031 U3 COAL PIPE REPLACEMENT 23 106,322
27636310 BRIDGER 2023CO23 UO BLANKET SWITCHGEAR UPGRADES 23 103,769
27625841 BRIDGER 2023C013 U3 DCS MINOR 23 102,199
27613526 BRIDGER 2022C048 U3 EX-2100E CONTROL UPGRADE 22/23 101,942
27627999 BRIDGER 2022C079 U3 BLANKET-MILLS,PULVERIZER VERTICAL SHAF 101,045
27634389 IBRIDGER 2023C046 UO REPLACE COAL HANDLING FIRE SYSTEM 23 100,589
27632273 IBRIDGER 2023C030 U3 BLANKET-UNDERGROUND UPS/HYDRANTS 23 100,554
xiI o.4
Case No.IPC-E-25-16
R.Adelman,IPC
Page 1 of 4

27625836 BRIDGER 2022CO82 U3 TURBINE 8TH STAGE BUCKET RPLCMT 22/23 100,409
27643080 BRIDGER CITC2017C294 UO JIM BRIDGER ROUTER SWITCH TELE TOM 99,819
27604647 BRIDGER 2022CO22 U3 BLANKET UPGRADE 7.2 KV MAGNABLAST BREAKE 97,888
27628021 BRIDGER 2023CO37 U3 SCR STATIC MIXERS&DUCTWORK 23 97,356
27630264 BRIDGER 2023CO41 U3 TRANSITION CHUTE REFRACTORY 23 93,444
27665217 BRIDGER 2024CO31 UO CONVEYOR BELTS 24 90,934
27640710 BRIDGER 2023CO55 UO REPLACE SEWER LINE 23 89,053
27625874 BRIDGER 2023CO35 U3 PA DUCT INSPECT AND REPAIR 23 87,102
27650856 BRIDGER 2023CO14 U3 BCP MOTOR REWINDS COOLERS 23 85,989
27602393 BRIDGER 2022CO34 U2 REPLACE EXISTING MILL AIR FLOW PROBES 22 85,541
27625849 BRIDGER 2023CO20 U3 RPLC REAR WATERWALL HANGER TUBES 23 85,288
27624150 BRIDGER 2023C006 U3 PRECIP DAMPER LIMITORQUE REPLACE 23 81,867
27636311 BRIDGER 2023/C/049 UO CONVEYOR BELTS 23 74,783
27615668 BRIDGER 2022CO59 UO BLANKET-UNDERGROUND IPS/HYDRANTS 22 70,188
27624145 BRIDGER 2023CO05 U3 SDCC REPLACE CHAIN 23 69,129
27566687 BRIDGER 20200087 UO MILL DISCHARGE VALVE REPLACE 20 67,586
27625838 BRIDGER 2023CO04 U3 SDCC LINER/SHELL REPAIRS 23 67,238
27630249 BRIDGER 2023CO02 U3 SDCC INSTALL LINER AT CHAIN GUARD 23 67,149
27615667 BRIDGER 2022CO58 U112 BCP REBUILD 22 66,464
27659519 BRIDGER 2024C011 UO BLANKET-ELECTRICAL/INSTRUMENTATION 24 64,826
27615670 BRIDGER 2022CO66 U3 REPLACE EX-2100 HMI COMPUTERS 23 60,189
27607146 BRIDGER 2022CO43 U2 VIBRATION MNTRG SYS END WINDINGS 22 58,004
27621618 BRIDGER 2022/C/070 UO CH LINER PLATES 22/23 57,728
27625872 BRIDGER 2023CO29 U2 BLANKET-PLANT LIGHTING IMPROVEMENTS 23 54,618
27665222 BRIDGER 2024CO21 UO RPLC SMALL SECONDARY CRUSHER ROTOR 91&92 53,351
27640708 BRIDGER 2023CO51 UO REPLACE AIR DRYER DESICCANT 23 52,518
27650853 BRIDGER 2023CO68 UO CTB TANK CROSS TIE TO WASTE LIQUOR TANK 52,151
27566689 BRIDGER 202000SS UO MILL DISCHARGE VALVE REPLACE 21 50,997
27632267 BRIDGER 2023CO40 U3 HP TURBINE PACKING 23 49,164
27607050 BRIDGER 2022CO26 UO BLANKET LCC SWITCHGEAR&XFMR UPGRADES 2 49,141
27624133 BRIDGER 2022CO64 U4 SDCC REPLACE CHAIN 22 48,182
27628015 BRIDGER 2023CO33 U3 VIBRATION MNTRG SYS END WINDINGS 23 47,767
27624139 BRIDGER 2022CO76 UO PM10 AMBIENT DUST MONITORS 47,691
27638309 BRIDGER 2023CO48 U3 REPLACE#32 PA FAN BEAMS 23 47,407
27657462 BRIDGER 2023/C/052 UO SPARE ACID PUMP 23/24 46,294
27652883 BRIDGER 2024CO09 UO DCS NETWORK ROUTERS 24 45,738
27630252 BRIDGER 2023CO12 UO COALYARD NETWORK HARDWARE UPGRADES 23 44,988
27630269 BRIDGER 2023CO42 U3 ABSORBERS PARTIAL INLET RECOAT 23 44,409
27640711 BRIDGER 2023CO56 UO REPLACE MONORAIL FASTENERS 23 42,226
27617948 BRIDGER 2022CO53 UO REPLACE 02 DI RESINS 22 40,502
27619797 BRIDGER 2022/C/057/01STACID U001 SOFTENER ACID INJECTION 22 39,629
27632276 BRIDGER 2023CO23 U3 BLANKET SWITCHGEAR UPGRADES 23 38,353
27632281 BRIDGER 2023CO07 U3 BLANKET-PUMPS,VALVES,GEARBOXES 23 37,892
27632268 BRIDGER 2023CO26 U3 REPLACE INVERTER&CHARGER 23 35,616
27630261 BRIDGER 2023CO21 U3 REPLACE DOGBONE EXPANSION JOINTS 23 35,250
27632279 BRIDGER 2023CO18 U3 APH RACK AND PINION 23 34,750
27667392 BRIDGER 2024CO34 UO REPLACE CATHODIC PROTECTION ANODE BED 24 34,326
27630251 BRIDGER 2023CO07 U4 BLANKET-PUMPS,VALVES,GEARBOXES 23 34,089
27632274 BRIDGER 2023CO30 UO BLANKET-UNDERGROUND IPS/HYDRANTS 23 33,065
27627985 BRIDGER 2022/C/016 U4 BLANKET-PUMPS,VALVES,GEARBOXES 32,589
27640710 BRIDGER 2023CO55 UO REPLACE SEWER LINE 23 32,376
27628009 BRIDGER 2023COOS UO BLANKET-SMALLTOOLS 23 31,959
27646446 BRIDGER 2023CO60 UO BLANKET-REPLACE SUPPORT EQUIPMENT 23 31,015
27628017 BRIDGER 2023CO34 U3 STACK LOWER EXPANSION JOINT RPLMT 23 30,889
27630270 BRIDGER 2023CO44 U3 DROP 9 WATER DAMAGE REPAIRS 23 30,515
27619800 BRIDGER 2022/C/063/U3SCRSB U3 SCR SOOTBLOWERS 23 30,018
27624137 BRIDGER 2022CO75 UO LAB PANEL INSTRUMENTATION 22 29,850
27634391 BRIDGER 2023CO07 UO BLANKET-PUMPS,VALVES,GEARBOXES 23 28,941
27665221 BRIDGER 2024CO30 UO REPLACE 03 CAC ROTOR 24 28,882
27628005 BRIDGER 2023C007 U2 BLANKET-PUMPS,VALVES,GEARBOXES 23 24,626
27667390 BRIDGER 2024C011 U3 BLANKET-ELECTRICAL/INSTRUMENTATION 24 24,184
27624156 BRIDGER 2023CO01 U4 COMBUSTION OPTIMIZER 23 23,801
27630252 BRIDGER 2023CO12 UO COALYARD NETWORK HARDWARE UPGRADES 23 23,589
27615665 BRIDGER 2022CO54 UO RPLC LARGE SECONDARY CRUSHER ROTOR 22 23,482
27619954 BRIDGER 2022/C/016/U3SLSP31 U3 31 SPENT LIQUOR SUMP PUMP 22 23,242
27630251 BRIDGER 2023CO07 U4 BLANKET-PUMPS,VALVES,GEARBOXES 23 22,712
27624144 BRIDGER 2023CO03 U3 SDCC REPLACE DEWATERING SLOPE 23 21,832
Exhibit No.4
Case No.IPC-E-25-16
R.Adelman,IPC
Page 2 of 4

27595046 BRIDGER 2021C042 U2 BURNERS MAJOR 22 21,037
27634391 BRIDGER 2023C007 UO BLANKET-PUMPS,VALVES,GEARBOXES 23 20,546
27650854 BRIDGER 2023C073 UO PURCHASE SCAFFOLD MATERIALS 23 18,807
27667393 BRIDGER 2024C037 UO REPLACE RO MEMBRANES 24 18,530
27632281 BRIDGER 2023C007 U3 BLANKET-PUMPS,VALVES,GEARBOXES 23 17,573
27643073 BRIDGER 2023C050 UO PURCHASE FIREFIGHTING EQUIPMENT 23 17,107
27640704 BRIDGER 2023C039 U3 SDCC TAKE-UP IDLER REPLACEMENT 23 16,364
27646447 BRIDGER 2023C070 UO REPLACE RO MEMBRANES 23 15,701
27553272 BRIDGER 20200002 U4 UPGRADE COOLING TOWER VFDS 20 15,362
27624128 BRIDGER 2022C046 UO REPLACE RO MEMBRANES 22 15,151
27624136 BRIDGER 2022C074 UO REPLACE 92 CRUSHER ISOLATION GATE 22 14,889
27659521 BRIDGER 2024C019 UO REPLACE EDFP CONTROLLER 24 14,827
27638305 BRIDGER 2023C007 Ul BLANKET-PUMPS,VALVES,GEARBOXES 23 13,355
27630254 BRIDGER 2023C016 U3 BLANKET-ELECTRICAL/INSTRUMENTATION 2 11,450
27643079 BRIDGER 2023C063 UO REPLACE LOADOUT CONV CHUTE 23 11,271
27624134 BRIDGER 2022/C/068 U3 LPA SCREEN REPLACEMENTS 22 11,210
27568632 BRIDGER 2018C125 UO RADIO COMMUNICATIONS TOWER 10,951
27619796 BRIDGER 2022/C/056/GRAVFILT UO REPLACE GRAVITY FILTER MEDIA 10,630
27575652 BRIDGER 2021C003 BLANKET-PUMPS,VALVES,GEARBOXES 21 10,246
27604649 BRIDGER 2021C046 UO REPLACE TRUCK SCALE 21/22 9,684
27646448 BRIDGER 2023C071 UO BLANKET-OFFICE EQUIPMENT 23 9,377
27630262 BRIDGER 2023C038 U3 SDCC TRANSFER CHUTES 23 8,944
27640707 BRIDGER 2023C047 UO REPLACE DOMESTIC WATER MODULES 23 8,834
27600043 BRIDGER 2022C019 U2 7200 LCC RELAY ARC FLASH UPGRADE 22 8,724
27632283 BRIDGER 2022C081 Ul BLANKET-REPLACE MILL PYRITE HOPPERS 22 7,742
27617944 BRIDGER 2022C065 UO MOBILE RADIO IMPRVMNTS CORP TELECM 22 7,291
27665219 BRIDGER 2024CO29 U4 BLANKET-BUILDING HVAC 24 6,766
27636309 BRIDGER 2023C016 U4 BLANKET-ELECTRICAL/INSTRUMENTATION 2 4,768
27648653 BRIDGER 2023C069 UO COAL LAB EQUIPMENT 23 4,687
27638306 BRIDGER 2023C010 U3 NETWORK HARDWARE UPGRADE 23 4,085
27643079 BRIDGER 2023C063 UO REPLACE LOADOUT CONV CHUTE 23 4,049
27589474 BRIDGER CITC2020C306 UO CORPORATE ROUTER/SWITCH TOM 20/21 3,976
27657464 BRIDGER 2024/C/016 UO REPLACE WAREHOUSE DOOR 24 3,931
27632276 BRIDGER 2023CO23 U3 BLANKET SWITCHGEAR UPGRADES 23 3,663
27567781 PAC-SPONSORED JOOA:JIM BRIDGER 1OH360 RPL CAPACITORS AND PT 2,978
27595042 BRIDGER 2021C038 UO REPLACE OFFICE FLOORING Ul SHIFTERS 2,792
27553276 BRIDGER 202000ll U4 SCRUBBER DUCTWORK 20 2,787
27531240 BRIDGER 2019C071 U3 ECONOMIZER HOPPER COVERS 19 2,585
27615665 BRIDGER 2022C054 UO RPLC LARGE SECONDARY CRUSHER ROTOR 22 2,436
27646446 BRIDGER 2023C060 UO BLANKET-REPLACE SUPPORT EQUIPMENT 23 2,395
27671070 BRIDGER 2024C042 UO PURCHASE ULTRASONIC THICKNESS METER 2 2,283
27619801 BRIDGER 2022/C/073/U3BURNER U3 BURNERS MAJOR 22/23 2,153
27529756 BRIDGER 2019C075 U3 LPA SCREEN REPLACEMENT 19 1,832
27600045 BRIDGER 2022CO20 UO BLANKET-SMALLTOOLS 22 1,677
27583201 BRIDGER 2021CO21 UO BCP MOTOR REWINDS&COOLERS 21 1,458
27523295 BRIDGER 2018C049 BLANKET-MILLS,PULVERIZER VERTICAL SHA 1,171
27628009 BRIDGER 2023C00S UO BLANKET-SMALLTOOLS 23 1,169
27624139 BRIDGER 2022C076 UO PM10 AMBIENT DUST MONITORS 853
27671069 BRIDGER 2024C039 UO PURCHASE CHAIN HOIST 24 850
27527164 BRIDGER 2019C057 BLANKET-REPLACE SUPPORT EQUIPMENT 19 727
27521483 BRIDGER 2019C010 U4#42 ABS COATING PHASE 2&AWNING INST 719
27521501 BRIDGER 2018C123 ASPHALT WORK 2018 705
27527154 BRIDGER 2019/C/014 U3 STACK BREECH COATING 19 705
27513380 BRIDGER 2018C076 BLANKET-REPLACE SUPPORT EQUIPMENT 18 668
27517680 BRIDGER 2018C117 INSTALL EFFLUENT TO MINE WATER PIPING 608
27568632 BRIDGER 2018C125 UO RADIO COMMUNICATIONS TOWER 569
27646444 BRIDGER 2023C00S U3 BLANKET-SMALL TOOLS 23 546
27569735 BRIDGER 2020C102 REPAVE PLANT ROADS 20 476
27624137 BRIDGER 2022C075 UO LAB PANEL INSTRUMENTATION 22 471
27547302 BRIDGER 2019C102 PLANT SCAFFOLD PURCHASE 19 415
27523298 BRIDGER 2018C120 LIGHT EQUIPMENT SHOP CHANNEL 372
27493693 BRIDGER 2017C110 U4 BOILER OPTIMIZATION SYSTEM 17 359
27597962 BRIDGER 2022CO21 UO ADD LOOP 3440-C CHANNEL BANK 22 348
27524331 BRIDGER 2018C111 POWERFILM FEED SYSTEM 18 305
27530128 BRIDGER 2019C064 U3 WATERWALL COUTANT SLOPE INTERFACE 19 287
27561651 BRIDGER 20200090 UO WASTE LIQUOR TANK COATING 276
27533266 BRIDGER 2019C061 U3 REPLACE 260V BATTERIES 19 248
Exhibit No.4
Case No.IPC-E-25-16
R.Adelman,IPC
Page 3 of 4

27551450 BRIDGER 20200056 U4 ACOUSTIC LEAK DETECTION SYSTEM 20 238
27602390 BRIDGER 2022CO29 UO BLANKET-OFFICE EQUIPMENT 22 213
27483918 BRIDGER 2017C065 BLANKET-OFFICE EQUIPMENT 212
27543727 BRIDGER 2019C086 REPLACE 91 LIME SILO DUST COLLECTOR 19 210
27529749 BRIDGER 2019C041 U3 PRECIPITATOR HVAC REPLACEMENT 19 175
27529757 BRIDGER 2019C067 U3 PA DUCT INSPECT AND REPAIR 19 137
27521499 BRIDGER 2018C072 U3 SCR PLATFORM MODIFICATIONS 135
27529755 BRIDGER 2019C059 U3 COAL PIPE REPLACEMENT 19 119
27557171 BRIDGER 20200079 TREATED WATER TANK COATING 20 93
27600045 BRIDGER 2022CO20 UO BLANKET-SMALLTOOLS 22 89
27551452 BRIDGER 20200057 U4 RETRACTS&WATER INJECTION PENETRATIO 65
27507248 BRIDGER 2018C066 UO NETWORK HARDWARE UPGRADE 18 46
27624152 BRIDGER 2023C009 U3 LPA SCR COLLECTION/TRANSFER CNVYR 23 44
27624135 BRIDGER 2022C071 U3 ECONOMIZER OUTLETTURNING VANE 22/23 39
27621620 BRIDGER 2022/C/072 U3 LPA SCREEN REPLACEMENT 22/23 38
27628013 BRIDGER 2023C031 U3 COAL PIPE REPLACEMENT 23 38
27628021 BRIDGER 2023C037 U3 SCR STATIC MIXERS&DUCTWORK 23 38
27473620 BRIDGER 2016C114 U3 SDCC REPLACE CHAIN 16 26
27624145 BRIDGER 2023C005 U3 SDCC REPLACE CHAIN 23 22
27625838 BRIDGER 2023C004 U3 SDCC LINER/SHELL REPAIRS 23 22
27630249 BRIDGER 2023C002 U3 SDCC INSTALL LINER AT CHAIN GUARD 23 22
27630258 BRIDGER 2023C017 U3 APH SECTOR PLATES 23 20
27624141 BRIDGER 2022C0SO U3 RPLC EXISTING MILL AIR FLOW HRDWR 22 19
27524340 BRIDGER 2018C131 U3 MAIN TURBINE OVERSPEED UPGRADE. 18
27441775 BRIDGER 2015C081 CCR JB LANDFILL/FGD2 PROG MG&STUDIES 10
27602391 BRIDGER 2022C030 U2 REPLACE ECON OUTLET TURNING VANES 22 4
27566689 BRIDGER 202000SS UO MILL DISCHARGE VALVE REPLACE 21 3
27597941 BRIDGER 2021C048 U001 CLARIFIER COATING REPAIRS 21 2
Various CORRECTIONS ASSOCIATED WITH INVESTMENTS PRIOR TO 2023 (698,949)
GRAND TOTAL 32,142,736
Exhibit No.4
Case No.IPC-E-25-16
R.Adelman,IPC
Page 4 of 4