HomeMy WebLinkAbout20250530Direct Colburn.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
MITCH COLBURN
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 Mitch Colburn. My business address
5 is 1221 West Idaho Street, Boise, Idaho 83702 . I am
6 employed by Idaho Power as the Vice President of Planning,
7 Engineering and Construction.
8 Q. Please describe your educational background.
9 A. I graduated from the University of Idaho in
10 2006 with a Bachelor of Science degree in Electrical
11 Engineering, Summa Cum Laude. Thereafter, I obtained a
12 Master of Engineering degree in Electrical Engineering from
13 the University of Idaho in 2010 and a Master of Business
14 Administration from Boise State University in 2015 . I am a
15 licensed Professional Engineer in the State of Idaho.
16 Q. Please describe your work experience with
17 Idaho Power.
18 A. I have worked at Idaho Power since 2007 .
19 Prior to my current role, I served as Director of
20 Engineering and Construction, Director of Resource Planning
21 and Operations, Senior Manager of Transmission &
22 Distribution Strategic Projects, Engineering Leader over
23 500-kilovolt ("kV") and Joint Projects . I held several
24 engineering roles prior to these leadership roles .
25 I am responsible for an organization of more than
COLBURN, DI 1
Idaho Power Company
1 275 employees focused on multiple areas : (1) identifying
2 future electric grid infrastructure requirements, (2)
3 resource procurement efforts, (3) operating and maintaining
4 the electric grid, including the wildfire mitigation
5 program and vegetation management, and (4) designing,
6 engineering, and constructing grid infrastructure projects .
7 Q. What is the purpose of your testimony in
8 this matter?
9 A. The purpose of my testimony is to discuss
10 the investments the Company has made in the electrical grid
11 to ensure the provision of safe, reliable service to
12 customers . I will detail specific investments anticipated
13 to be completed in 2025 and included in the Company' s
14 request in this case, demonstrating Idaho Power' s prudent
15 investment in the electrical grid at the transmission and
16 distribution levels .
17 Q. How is your testimony organized?
18 A. My testimony will begin with a discussion of
19 the transmission and distribution-related major projects,
20 or those projects over $2 million ("major projects") ,
21 included in Idaho Power' s request in this case that are
22 necessary for the Company' s continued delivery of safe,
23 reliable electric service . Next, I will discuss the Wood
24 River Valley Reliability Project ("WRV Project") , a
25 combined distribution and transmission project for which
COLBURN, DI 2
Idaho Power Company
1 the Company has received a Certificate of Public
2 Convenience and Necessity ("CPCN") , the distribution
3 portion of those investments which are proposed for
4 recovery in this case. I will also discuss a project
5 necessary for continued support of Idaho Power' s mobile
6 workforce system. Finally, my testimony will review the
7 Company' s planned enhanced 2025 wildfire mitigation efforts
8 that support the associated capital and operation and
9 maintenance expenditures proposed for recovery in this
10 case .
11 I . TRANSMISSION INVESTMENTS
12 Q. Please describe how the Company defines the
13 transmission-related portion of the electrical grid.
14 A. Transmission generally describes the bulk or
15 high voltage components of the electrical grid, including
16 stations and high voltage lines typically utilized to
17 transmit large volumes of electricity closer to load
18 centers . On Idaho Power' s system, transmission equipment is
19 considered to be facilities at or above 138-kV, with an
20 additional sub-transmission component comprised of
21 facilities at 46-kV and 69-kV.
22 Q. How have the transmission-related
23 investments grown since the completion of the limited scope
24 case in 2024 that included incremental capital investments,
25 Case No. IPE-E-24-07 ("2024 Limited Scope Case") ?
COLBURN, DI 3
Idaho Power Company
1 A. Of the $941 . 5 million in infrastructure
2 anticipated to be placed in service in 2025, approximately
3 $201 . 3 million reflects investment in the Company' s
4 transmission system.
5 Q. What drives investment in the transmission
6 system?
7 A. Growth and reliability are the primary
8 drivers of the transmission investments reflected in the
9 Company' s request in this case. Growth-related projects
10 typically include either the construction of new
11 transmission facilities or the expanded capacity of
12 existing facilities . Reliability projects typically include
13 the proactive reconstruction or replacement of aging
14 facilities, additional facilities to increase resiliency,
15 and compliance related projects . My testimony will discuss
16 13 transmission-related major projects expected to be
17 complete in 2025, 11 of which are required to address aging
18 infrastructure, one is growth-related, and one supports
19 security enhancements .
20 Transmission Line Rebuilds and Repairs
21 Q. What is the largest transmission investment
22 necessary to address aging infrastructure expected to be
23 complete in 2025?
24 A. With a cost of approximately $16 . 5 million,
25 the largest transmission investment expected to be complete
COLBURN, DI 4
Idaho Power Company
1 in 2025 and included in Idaho Power' s request in this case
2 is the second phase of the rebuild of a portion of Line
3 423 . In fact, three of the transmission investments
4 necessary to address aging infrastructure are associated
5 with transmission line rebuilds : (1) Line 423, (2) Line
6 412, and (3) Line 902 . Delaying the rebuilds could result
7 in higher maintenance and repair costs should the
8 structures need replacement individually, while also
9 potentially reducing reliability, and are therefore
10 critical to the continued delivery of safe, reliable
11 electric service to customers .
12 Q. Is the rebuild of Line 423 the same project
13 that was included in the Company' s 2024 Limited Scope Case?
14 A. Yes . However, the amounts included in the
15 2024 Limited Scope Case were associated with the first
16 phase of the project, and the portion expected to be
17 complete in 2025 is associated with a second phase of the
18 project. Line 423 is a 138-kV line that runs from Ontario
19 to the Quartz substation, south of Baker City in Oregon.
20 The rebuild project is associated with the Huntington to
21 Quartz 138-kV portion of Line 423 ("Huntington-Quartz
22 line") and is being performed in two sections (1) the
23 approximately 24 miles from the Quartz substation to the
24 Nelson Tap/Ash Grove substation ("phase one") , and (2) the
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Idaho Power Company
1 approximately 16 . 5 miles from the Nelson Tap/Ash Grove
2 substation to the Huntington substation ("phase two") .
3 Q. What drove the need for the rebuild of the
4 Huntington-Quartz portion of Line 423?
5 A. The rebuild of the Huntington-Quartz line
6 was required due to the age of the existing line and
7 resulting reliability issues . When evaluating potential
8 outage sources, it was noted that due to the age of the
9 lines, this section was constructed between 1949 and 1951,
10 shield wires had not been installed and therefore lightning
11 was likely contributing to the performance issues . Thus,
12 the Company engaged POWER Engineers, Inc. ("POWER
13 Engineers") , to perform a study to analyze the entire
14 Ontario to Quartz 138-kV line, and specifically the
15 Huntington to Quartz section to determine if a rebuild on
16 the line would increase reliability.
17 Q. What were the results of the analysis?
18 A. POWER Engineers used a lightning performance
19 software, analyzing three cases, each with two different
20 footing resistance assumptions : (1) the existing wood
21 structure with no shield wires, (2) a new wood structure
22 with two shield wires, and (3) a new steel structure with
23 two shield wires . The results indicated that the overall
24 line performance would be significantly improved with the
25 addition of shield wires and further improvement is
COLBURN, DI 6
Idaho Power Company
1 expected if steel structures were used in combination with
2 the addition of shield wires .
3 Q. Is Idaho Power replacing the existing wood
4 structures with steel structures?
5 A. Yes . The Huntington-Quartz line rebuild will
6 include the replacement of 286 structures from the
7 Huntington substation to the Quartz substation with tubular
8 steel 138-kV structures with shield wire and optical ground
9 wire for fiber optic communications . Due to the age of the
10 existing wood structures, they did not have space for the
11 addition of shield wires . Moreover, because the Huntington-
12 Quartz line was identified as being in a wildfire prone
13 area, the project was prioritized, and grid hardening
14 performed as part of the rebuild. Grid hardening includes
15 the use of steel structures for resiliency against
16 wildfires and improved customer reliability.
17 Q. How does the addition of shield wires improve
18 reliability?
19 A. Shield wires are installed above the
20 conductors for the purpose of channeling lightning strikes
21 to ground, which helps to prevent or minimize damage to
22 power lines and equipment, avoid major outages on the line,
23 and mitigate maintenance and repair costs . Phase two of the
24 rebuild of the Huntington-Quartz line, with a total cost of
25 approximately $16 . 5 million and an anticipated in service
COLBURN, DI 7
Idaho Power Company
1 of July 2025, is necessary to ensure Idaho Power continues
2 providing safe, reliable electric service to its customers .
3 Q. What drove the need for the rebuild of Line
4 412?
5 A. Similar to Line 423, nearly half of the
6 structures and crossarms on the approximately 30-mile Boise
7 Bench to Emmett 138-kV section of Line 412 were built in
8 1947 . Having first been identified in 2016 as a rebuild
9 priority to address reliability issues, the Boise Bench to
10 Emmett 138-kV section of Line 412 was routinely
11 experiencing extensive maintenance repairs, emergency
12 repairs and hillside erosion. Due to its location within
13 the red wildfire risk zone along the Boise foothills, the
14 line was also identified in Table 14 of the Company' s 2025
15 Wildfire Mitigation Plan and needed steel structures for
16 resiliency against wildfires and improved customer
17 reliability. The rebuild of the Boise Bench to Emmett 138-
18 kV section of Line 412 is estimated to be complete in
19 October 2025 for a total cost of approximately $12 . 5
20 million.
21 Q. Is the rebuild of Line 902 the same project
22 that was included in the Company' s 2024 Limited Scope Case?
23 A. Yes . However, the amounts included in the
24 2024 Limited Scope Case were associated with one phase of
25 the project, and the portion expected to be complete in
COLBURN, DI 8
Idaho Power Company
1 2025 is associated with a second phase of the project. Line
2 902 is one of the three 230-kV transmission lines that run
3 from the Boise Bench substation to the Midpoint substation.
4 Line 902 has been connected to and split into many line
5 sections by station additions over the years, and is now
6 comprised of the Midpoint to Justice, Justice to Mountain
7 Air Wind Tap, Mountain Air Wind Tap to Rattlesnake,
8 Rattlesnake to DRAM, and finally DRAM to Boise Bench
9 segments . Line 902 was originally built over 70 years ago,
10 with 478 of the original structures from 1947 in place . The
11 rebuild project will occur in four phases, the second of
12 which is included in the Company' s request in this case,
13 the approximately four-mile Boise Bench substation to DRAM
14 substation section ("Boise Bench to DRAM") .
15 Q. Is the Boise Bench to DRAM portion of Line
16 902 in a wildfire prone area?
17 A. Yes . All four phases of the Line 902 rebuild
18 fall within the wildfire prone areas as identified in Idaho
19 Power' s Wildfire Mitigation Plan, including the Boise Bench
20 to DRAM section. Therefore, all four phases of the line
21 rebuild will utilize steel structures for resiliency
22 against wildfires and to improve customer reliability.
23 Phase two of the work to rebuild the Boise Bench to DRAM
24 section of Line 902 is expected to be complete in October
25 2025 at a total cost of approximately $2 . 7 million.
COLBURN, DI 9
Idaho Power Company
1 Q. What additional transmission investments were
2 necessary to address aging infrastructure?
3 A. The next two transmission investments I am
4 going to discuss that were required to address aging
5 infrastructure were portions of: (1) Line 906 and (2) Line
6 441 . Lines 906 and 441 were identified as needing certain
7 remediations during Idaho Power' s comprehensive maintenance
8 inspection. The Company follows transmission maintenance
9 and inspection practices in accordance with the Western
10 Electricity Coordinating Council and the North American
11 Electric Reliability Corporation ("NERC") requirements to
12 ensure compliance with applicable safety and reliability
13 standards and takes proactive steps to repair or replace
14 transmission line components on an ongoing basis as part of
15 asset management and aging infrastructure assessments .
16 Pursuant to its Transmission Maintenance and Inspection
17 Plan, the Company performs line inspections to identify
18 conditions or defects and inform, prioritize, and schedule
19 maintenance activities . Routine line patrols are conducted
20 annually, and the comprehensive maintenance inspections are
21 generally performed every 10 years and include a detailed
22 inspection of all transmission line components and a pole
23 inspection and ground-line treatment of all wood poles in
24 the line. When inspected, certain poles, cross arms, and
25 insulators on both Lines 906 and 441 were found to be in
COLBURN, DI 10
Idaho Power Company
1 poor condition as a result of this process, and therefore
2 identified as needing to be replaced.
3 Q. Where is Line 906 located?
4 A. Line 906, a 106 mile 230-kV line, is one of
5 the three 230-kV transmission lines that run from the Boise
6 Bench substation to the Midpoint substation. The work on
7 Line 906 is expected to be complete in December 2025 at a
8 total cost of approximately $7 . 8 million.
9 Q. Please describe Line 441 .
10 A. Line 441 is an approximately 42 mile 138-kV
11 line that runs from the Oxbow substation to the McCall
12 substation in rough, high-risk terrain. The line is being
13 repaired in two phases, and because they will both be
14 complete in 2025, Idaho Power' s request in this case is
15 associated with both phases of the project. Both phases are
16 expected to be complete by December 2025 for a total cost
17 of approximately $4 . 2 million .
18 Transmission Stations Equipment Replacement
19 Q. You discussed the transmission line
20 investments necessary to address aging infrastructure . What
21 additional transmission investments are necessary to
22 address aging infrastructure and are expected to be
23 complete in 2025?
24 A. The remaining six transmission major
25 projects necessary to address aging infrastructure are all
COLBURN, DI 11
Idaho Power Company
1 associated with transmission station equipment replacements
2 due to either equipment failures or equipment beyond its
3 expected operating life. Two of the six investments are
4 required prior to the addition of a new 138-kV line, the
5 Ontario to Cairo line. The 138-kV line will bring service
6 from Ontario substation to the Cairo substation. The new
7 line was identified as part of a corrective action plan to
8 resolve a NERC Transmission Planning ("TPL") compliance
9 issue . The NERC TPL are standards that include several key
10 regulations aimed at ensuring the reliability of the bulk
11 power system. Under TPL-001-4, the Company must establish
12 transmission system planning performance requirements to
13 develop a bulk electric system that will operate reliably
14 over a broad spectrum of system conditions and following a
15 wide range of probable contingencies .
16 Q. How was the compliance issue identified?
17 A. As part of the reliability studies, if the
18 Ontario substation experienced a breaker failure that
19 caused two transformers to go offline, the system
20 configuration would result in just one transformer to serve
21 the entire 69-kV system in the area . As load has grown in
22 the area, reliability standards can no longer be met. The
23 Ontario substation and the Cairo substation major projects
24 were planned as the result of the reliability compliance
25 standards .
COLBURN, DI 12
Idaho Power Company
1 Q. Please describe the work being performed to
2 address the reliability issues .
3 A. The solution to the reliability issue was to
4 add a new 138/69-kV source to support the existing 69-kV
5 system. Because the existing Ontario substation was nearing
6 capacity, a new source had to be built at a different
7 substation, the Cairo substation, which is located in the
8 south end of the town of Ontario. The Company is upgrading
9 the line voltage on an existing line, and looping that line
10 into the Cairo substation, which will require four new 69-
11 kV breakers and two new 138-kV breakers to support the
12 connections .
13 Q. What is the total investment in the Cairo
14 and Ontario substations included in Idaho Power' s request
15 in this case?
16 A. Idaho Power has included in its request in
17 this case a total investment of $9 . 3 million for both the
18 Cairo and Ontario substation projects . The Ontario
19 substation work was completed in January 2025 and the Cairo
20 substation work is anticipated to be completed in June
21 2025 .
22 Q. What are the four remaining transmission
23 station investments necessary due to aging infrastructure
24 you have not yet discussed?
COLBURN, DI 13
Idaho Power Company
1 A. The four remaining transmission station
2 investments necessary due to aging infrastructure were made
3 at the Blackfoot, American Falls, Kinport, and Weiser
4 substations . First, at the Blackfoot substation, the
5 existing 138-kV transformer was manufactured in 1953 and
6 had exceeded its expected operating life and repair parts
7 had become difficult or costly to procure. Further, the
8 load tap changer on the transformer was requiring more
9 frequent maintenance, indicating the potential for a
10 transformer failure. In addition, the transformer relays
11 had outdated technology, creating reliability concerns . The
12 existing transformer relays were replaced with new
13 protective relays and the existing bus protection relays
14 and lockouts were replaced with new microprocessor-based
15 protection. The Blackfoot substation equipment replacement
16 project was completed in April 2025 and approximately $5 . 4
17 million is included in Idaho Power' s request in this case .
18 Q. What drove the need for the American Falls
19 substation investments?
20 A. The existing transformer protection relays
21 were electromechanical relays which had exceeded their
22 expected reliable operating lives and therefore posed an
23 increasing risk to the system of failure. Further, the
24 relays lacked the remote access, data archiving, and event
25 analysis capability of modern electronic relays .
COLBURN, DI 14
Idaho Power Company
1 Q. What investments were made at the American
2 Falls substation to replace the aging equipment?
3 A. The transformer protection relay packages
4 were replaced, as was the supervisory control and data
5 acquisition ("SCADA") equipment, and the 46-kV breaker,
6 switches, and bus . The American Falls substation equipment
7 replacement project was completed in April 2025 and
8 approximately $3 . 4 million is included in the Company' s
9 request in this case.
10 Q. Please describe the Kinport substation major
11 project anticipated to be complete in 2025 .
12 A. The major project associated with the
13 replacement of aging infrastructure at the Kinport
14 substation involves the replacement of the air-breaks . The
15 existing air-breaks are at the end of the expected life and
16 no further modification or adjustments can be made to the
17 equipment. Due to their age and challenges operating, these
18 air-breaks pose a high risk of failure. The air-breaks are
19 a part of three separate transmission lines that are
20 critical to serving the Pocatello and Blackfoot areas and
21 therefore a failure could cause outages and/or damage other
22 equipment. Idaho Power' s request in this case includes
23 project costs associated with the Kinport substation of
24 approximately $2 . 7 million with anticipated completion in
25 June 2025 .
COLBURN, DI 15
Idaho Power Company
1 Q. What work will be done at the Weiser
2 substation to address aging infrastructure?
3 A. The Weiser substation contained equipment
4 that was manufactured as early as 1965 and was due for
5 replacement due to industry technological changes as well
6 as obsolescence. Due to the increasing risk of equipment
7 failure or mis-operation with associated risks of
8 unnecessary or potential extended outages, the oil circuit
9 breakers were replaced with new gas breakers and the
10 electromechanical relays were replaced with modern digital
11 relays . More modern digital relays also provide fault
12 location and other data utilized for reliability purposes
13 not available from electromechanical relays . The Company
14 has included total project costs associated with the Weiser
15 substation of approximately $2 . 6 million in the request in
16 this case. The project was placed in-service in January
17 2025 .
18 Growth-Related Transmission Investments
19 Q. You indicated there is one transmission-
20 related major project Idaho Power has included in its
21 request in this case associated with growth. Where is the
22 work being performed?
23 A. Due to load growth in the Treasure Valley
24 area, the Company was experiencing limited operations of
25 various resources and transmission paths south of the
COLBURN, DI 16
Idaho Power Company
1 Treasure Valley to serve load during peak conditions . In
2 addition, increased transmission capacity was needed for
3 delivery of resources from the Hemingway substation,
4 including the Hemingway battery storage resources, as well
5 as resources from the 138-kV system, including the Kuna
6 battery storage resources . To accommodate the growth and
7 increased transmission capacity need, in 2025 Idaho Power
8 is constructing two new 230-kV line terminals and one new
9 138-kV line terminal at the Bowmont substation, which is
10 approximately four miles north of Melba, Idaho. The
11 upgrades at the Bowmont substation are anticipated to be
12 complete in December 2025 for a total cost of approximately
13 $4 . 4 million.
14 Q. Are there any additional transmission-related
15 investments included in Idaho Power' s request in this case
16 that you have not yet discussed?
17 A. Yes . One of the major projects for which the
18 Company is requesting approval in this case is associated
19 with threat and security vulnerability assessment
20 investments made at one of Idaho Power' s transmission
21 substations .
22 Threat and Security Vulnerability Assessment Investments
23 Q. Please describe the threat and security
24 vulnerability assessment investments expected to be
25 complete in 2025?
COLBURN, DI 17
Idaho Power Company
1 A. Similar to the threat and security
2 vulnerability assessment investments in Idaho Power' s
3 hydro facilities discussed in the Direct Testimony of Mr.
4 Ryan Adelman, there is one threat and security
5 vulnerability assessment project expected to be completed
6 in 2025 and necessary at the Borah transmission
7 substation. The physical security improvements are being
8 made in accordance with the (1) NERC Reliability Standards
9 specific to Physical Security of the Bulk Electric System
10 and associated Cyber Systems, and (2) Idaho Power' s
11 internal risk assessment process for high and critical
12 rate assets . These enhanced security controls at the
13 substation will better detect, deter, delay, notify,
14 assess, and respond to potential security threat events .
15 Analysis of the Borah transmission substation identified
16 the need for enhanced security controls including the
17 installation of improved security fencing, the upgrade of
18 the closed-circuit television ("CCTV") camera system, as
19 well as other improved security measures .
20 Q. What is the total investment in the Borah
21 transmission substation included in Idaho Power' s request
22 in this case?
23 A. The Company is requesting in this case to
24 include approximately $10 . 5 million associated with the
25 Borah substation threat and security vulnerability
COLBURN, DI 18
Idaho Power Company
1 assessment investments . The work is expected to be
2 completed in June 2025 .
3 Q. Do the transmission-related major projects you
4 discussed demonstrate a prudent approach to investment in
5 the Company' s transmission system and support Idaho Power' s
6 transmission-related rate base included in this case?
7 A. Yes . In just one year, the Company is
8 investing over $201 . 3 million in its transmission system.
9 Idaho Power is constantly evaluating the capacity needs,
10 resiliency, and reliability of its transmission system,
11 ensuring that the electrical grid is stable and in
12 compliance with NERC standards . Further, the Company is
13 dedicated to the safety of its customers and communities as
14 evidenced in the continuously evolving Wildfire Mitigation
15 Plan. Idaho Power works to reduce the risk of wildfire
16 ignition through the implementation of core mitigation
17 approaches, such as grid hardening of the electrical
18 system, as evidenced by the transmission-related
19 investments I discuss in my testimony.
20 II . DISTRIBUTION INVESTMENTS
21 Q. Please describe how the Company defines the
22 distribution-related portion of the electrical grid.
23 A. Distribution refers to equipment at 34 . 5-kV
24 and below, including lower voltage lines, substations, and
25 transformers that are typically utilized to provide
COLBURN, DI 19
Idaho Power Company
1 electricity at the lower voltages required by the majority
2 of end-use customers .
3 Q. How have the distribution-related investments
4 grown since the completion of the 2024 Limited Scope Case?
5 A. Of the $941 . 5 million in infrastructure placed
6 in service over this period, approximately $207 . 1 million
7 reflects investment in the Company' s distribution system.
8 Q. What factors contributed to investment in
9 Idaho Power' s distribution system over this period?
10 A. Growth in the distribution system can be
11 directly tied to the addition of new customers, as every
12 new primary or secondary service level customer, requires
13 some form of additional distribution equipment. In
14 addition, similar to certain components of the Company' s
15 transmission system, Idaho Power has also undertaken a
16 number of key projects to proactively harden its
17 distribution system to maintain and improve reliability in
18 light of aging infrastructure. These investments not only
19 include the proactive replacement of aging infrastructure,
20 but also the improvement of the distribution system through
21 the installation of modern technology. Next, I will discuss
22 the distribution-related major projects expected to be
23 completed in 2025 . I will specifically discuss the largest
24 distribution project the distribution portion of the WRV
25 Project, later in my testimony, providing an overview of
COLBURN, DI 20
Idaho Power Company
1 its long and complex regulatory history. Aside from the WRV
2 Project, there are 10 distribution-related major projects
3 expected to be complete in 2025, five of which are required
4 to address aging infrastructure and five are growth-
5 related.
6 Aging Infrastructure-Related Distribution Investments
7 Q. What is the largest distribution investment
8 necessary to address aging infrastructure expected to be
9 complete in 2025?
10 A. With a cost of approximately $5 . 2 million,
11 the largest distribution investment associated with the
12 replacement of aging infrastructure and included in Idaho
13 Power' s request in this case is the replacement of two
14 transformers at the Julion Clawson substation. The two
15 existing transformers were manufactured in 1967 . The load
16 tap changers, which adjusts output voltage without
17 interrupting the load, on two transformers had been
18 performing inadequately, and therefore impacting
19 reliability. The transformers had been repaired multiple
20 times in the last few years and because of their age it was
21 becoming difficult to obtain parts for repairs of either
22 transformer and troubleshooting and repairing them had
23 become challenging. In addition, the feeders were carrying
24 more load over the years, and it was becoming difficult to
COLBURN, DI 21
Idaho Power Company
1 shift load elsewhere without overloading other equipment,
2 creating reliability concerns .
3 Q. Aside from the reliability issues, were
4 there any additional benefits associated with the
5 transformer replacements?
6 A. Yes . The existing 28 megavolt amperes
7 ("MVA") transformers were upgraded to 44 . 8 MVA transformers
8 which will provide operational flexibility and more
9 capacity to handle higher peak loads . In addition, they are
10 more modern, reliable transformers and therefore easier to
11 maintain and repair. Absent the larger transformers, mobile
12 transformers would need to be brought in to carry the load
13 of the existing transformers during maintenance or when
14 repairs are made. The replacement of the transformers at
15 the Julion Clawson substation is expected to be complete in
16 December 2025 .
17 Q. What additional major projects will the
18 Company be completing in 2025 to proactively harden its
19 distribution system to maintain and improve reliability in
20 light of aging infrastructure?
21 A. Three of the distribution-related major
22 projects associated with aging infrastructure include the
23 upgrade of three distribution stations : the Durkee
24 substation, the Bannock Creek substation and the Caldwell
25 substation. As part of an analysis performed to determine
COLBURN, DI 22
Idaho Power Company
I alternatives to replacing the existing Line 209, a 69—kV
2 line with structures dating back to 1927, it was determined
3 that removal of most of Line 209 and the serving of loads
4 via other sources was the most economical solution. Part of
5 that solution included the rebuilding of the Durkee
6 substation, an existing 69-kV substation, to a 138-kV
7 substation. The new Durkee substation will connect to an
8 existing nearby 138-kV line, allowing for the removal of
9 the aging Line 209 .
10 Q. What does the rebuild of the Durkee
11 substation entail?
12 A. Installation of a new 138-kV air-break
13 switch, power transformer, a dead-end structure, busbars,
14 and conductors will be made at the Durkee substation. Also,
15 a control building, communication equipment, concrete for
16 foundations, and fencing will be added. The work is
17 scheduled to be complete in October 2025 for a total cost
18 of approximately $3 . 6 million .
19 Q. What drove the need for the upgrade of the
20 Bannock Creek distribution station?
21 A. The Bannock Creek distribution station,
22 located in the middle of the Fort Hall Reservation, was
23 constructed in 1962 through 1963 and still contains some of
24 the original equipment. The principal operating equipment,
25 including the oil-filled breakers and relays and switches
COLBURN, DI 23
Idaho Power Company
1 are all the original equipment and the transformer were
2 manufactured in 1969 . The open-backed relays, the auxiliary
3 current transformers, and the control cables were corroded.
4 The concrete foundations, especially the 13-kV bus
5 foundations, are badly decomposed, and the transformer
6 foundation has settled requiring ongoing releveling.
7 Finally, because of their age, the motor-operated air-break
8 switches outside the station fence do not function properly
9 during cold periods . In an effort to improve reliability in
10 light of aging infrastructure, in 2025, Idaho Power will be
11 updating the Bannock Creek station.
12 Q. What upgrades will be made at the Bannock
13 Creek distribution station?
14 A. First, the Company will be converting the
15 power source to 138-kV to improve reliability and reduce
16 long-term maintenance costs on the existing 46-kV line
17 currently serving the station. The yard will be expanded,
18 concrete foundations replaced, and the control building
19 replaced. A nearby 138-kV tap will be extended into the
20 station and new terminal structures installed. The existing
21 transformer will be replaced with a 138/12 . 5-kV transformer
22 being removed from the Linden station. New breakers,
23 controls and switches will complete station renovation. In
24 total, the Bannock Creek distribution station
25 infrastructure improvements are expected to be completed in
COLBURN, DI 24
Idaho Power Company
1 November 2025 for a total cost of approximately $3 . 6
2 million.
3 Q. Why is the Caldwell substation in need of an
4 upgrade?
5 A. Similar to the Bannock Creek distribution
6 station, the Caldwell substation was in need of a new
7 control building because the existing building was too
8 small to house the necessary upgraded equipment. The
9 existing relays have reached the end of their life and have
10 been unreliable over the last few years because the
11 contacts have become tarnished and do not allow the relay
12 to reset properly after being in the lockout state .
13 Further, the electromechanical feeder breaker relays do not
14 have the Hot Line Hold functionality that allows for feeder
15 maintenance, nor do they have fault data recording that is
16 used for protection and reliability analysis .
17 The entire protection and control package will be removed,
18 and the new control building will house new panels for the
19 transformer protection, metering, and controls . Total
20 project costs associated with the upgrades at the Caldwell
21 substation included in the Company' s request in this case
22 are approximately $2 . 6 million. The work was completed in
23 February 2025 .
24
25
COLBURN, DI 25
Idaho Power Company
1 Q. Please describe the final major project
2 necessary for distribution system hardening to maintain and
3 improve reliability.
4 A. The final distribution-related major project
5 necessary to address aging infrastructure is associated
6 with the Siphon substation equipment. Like the Bannock
7 Creek distribution station, the Siphon substation has oil
8 breakers that are no longer supported by the manufacturer
9 and repair parts had become difficult or costly to procure .
10 Having been in service since 1972, the equipment was at
11 risk for failure which could lead to customer outages . With
12 a total project cost of approximately $2 . 0 million, the
13 Siphon substation upgrades include the replacement of the
14 breakers and getaway cables, including the extension of the
15 fence to accommodate the new getaway cables . The upgrades
16 at the Siphon substation are anticipated to be completed in
17 May 2025 .
18 Growth-Related Distribution Investments
19 Q. What is the largest growth-related
20 distribution investment expected to be complete in 2025?
21 A. With a cost of approximately $7 . 3 million,
22 the largest distribution investment associated with growth
23 and included in Idaho Power' s request in this case is
24 associated with work at the Vallivue substation.
25 Projections indicated that the transformer capacity would
COLBURN, DI 26
Idaho Power Company
1 exceed the planning capacity by nearly six percent in the
2 summer of 2025 . The Company had already transferred two
3 separate loads in an attempt to offload the transformer and
4 had no additional adjacent transformer or feeder capacity
5 available. With the average growth rate of over 5 . 6 percent
6 in the urban area for which the Vallivue substation serves,
7 primarily attributable to residential development, it was
8 determined the substation needed to be expanded to allow
9 for more capacity.
10 Q. What additions are planned for the Vallivue
11 substation to accommodate the growth?
12 A. With work expected to be complete in June
13 2025, a new 44 . 8 MVA transformer is being added, new
14 metalclad, the transfer of an existing feeder to the new
15 metalclad, and two new feeders will be added. One feeder
16 will add 1 . 5 miles of second circuit to the existing
17 distribution line and the second feeder will add two miles
18 of second circuit to an existing line. A feeder tie will be
19 added to connect one of the new feeders to an existing
20 feeder. Finally, a control building will be added to house
21 SCADA, communication and high voltage side devices . The
22 Vallivue substation additions are expected to be complete
23 in June 2025 .
24 Q. What other distribution stations require
25 investments that are driven by growth?
COLBURN, DI 27
Idaho Power Company
1 A. Idaho Power' s request in this case includes
2 four additional distribution substations where investments
3 are being made to accommodate growth: the Artesian
4 substation, the Lansing substation, the Stoddard substation
5 and the Halfway substation. Similar to the Vallivue
6 substation, the transformer at the Artesian substation was
7 exceeded the planning capacity in the summer of 2024 and
8 growth in the area was approximately one percent annually.
9 Because there is no available adjacent transformer or
10 feeder capacity to offload the existing transformer, a
11 second transformer will be added at the Artesian
12 substation. Along with the installation of a second 46-kV
13 transformer, a capacitor bank will be installed to
14 complement the new transformer, providing reactive power to
15 improve voltage stability, and the existing feeder relays
16 that are over 60 years old will be replaced. Yard
17 improvements will be made to accommodate the expansion and
18 a new pre-manufactured control building installed. The work
19 is expected to be complete in December 2025 with total
20 project costs of $6 . 7 million.
21 Q. What investments will be made at the Lansing
22 substation to accommodate growth?
23 A. The feeder at the Lansing substation was
24 forecasted to exceed the planning capacity in the summer of
25 2025 . Residential growth in this developing rural area is
COLBURN, DI 28
Idaho Power Company
1 over six percent annually and with no available adjacent
2 feeder capacity to offload the Lansing substation feeder,
3 additions were planned. A second metalclad will be
4 installed along with two new feeder getaways, distribution
5 circuits and lines that carry power out of the substation.
6 To accommodate the additions, distribution lines coming
7 into the station will be rebuilt and a second circuit will
8 be added to one of the existing distribution lines . The
9 Lansing substation investments are estimated to be
10 approximately $5 . 3 million with work to be completed in
11 December 2025 .
12 Q. Was the Stoddard substation also signaling
13 transformer or feeder capacity in excess of the planning
14 capacity criteria?
15 A. Yes . Like the Lansing substation, the feeder
16 at the Stoddard substation was forecasted to exceed the
17 planning capacity in the summer of 2025 and residential and
18 commercial load in the area was growing over nine percent
19 annually. Multiple load transfers had been made in an
20 attempt to defer substation additions but there were no
21 more options available. A new 138-kV transformer will be
22 added to the substation along with a second metalclad with
23 two additional getaways . Two new distribution lines will be
24 installed, their connection requiring a reconfiguration of
25 an existing distribution line and the transferring of
COLBURN, DI 29
Idaho Power Company
1 existing load on a separate line to the new Stoddard
2 distribution line. Finally, a tie switch will be added to
3 balance load between two existing Stoddard distribution
4 lines and a second load transfer will occur to offload a
5 separate existing Stoddard distribution line .
6 Q. What is the total cost of the Stoddard
7 substation additions necessary to accommodate growth?
8 A. The investments necessary at the Stoddard
9 substation, which are identified as two different major
10 projects in the Company' s request in this case, separated
11 between stations and distribution line costs, are estimated
12 to be approximately $6 . 7 million. The distribution line
13 work is anticipated to be complete in June 2025 and the
14 stations work is expected to be completed by December 2025 .
15 Q. What investments are required at the Halfway
16 substation?
17 A. The Halfway substation is expected to exceed
18 the planning capacity in the winter of 2025-2026 . With an
19 average growth trend of 1 . 6 percent annually, and no
20 available adjacent feeder capacity to offload the feeder,
21 it was determined the transformer needed to be replaced
22 with a larger 14 MVA transformer. The station will be
23 expanded, and along with the new transformer, the following
24 equipment will be added: three new bus supports, new
25 disconnects and fuses, a new distribution structure, and
COLBURN, DI 30
Idaho Power Company
1 new control boxes . With total project costs estimated to be
2 approximately $3 . 1 million, the Halfway substation upgrades
3 are planned to be completed in October 2025 .
4 Q. Do the distribution-related major projects you
5 discussed demonstrate a prudent approach to investment in
6 the Company' s distribution system and support Idaho Power' s
7 distribution-related rate base included in this case?
8 A. Yes . In just one year, the Company is
9 investing $207 . 1 million in its distribution system. Idaho
10 Power' s thoughtful and proactive approach to investing in
11 its distribution system has resulted in improved
12 reliability metrics over the past decade as detailed in Mr.
13 Adam Richins testimony. In addition, the Company is
14 investing to accommodate growth within the Idaho Power' s
15 service area, ensuring the distribution system is equipped
16 to provide safe, reliable service to customers now and in
17 the future .
18 III . WOOD RIVER VALLEY RELIABILITY PROJECT
19 Q. Please describe the WRV Project.
20 A. Idaho Power' s WRV Project includes a
21 combination of electric distribution, transmission, and
22 substation work, in which the Company will bury or rebuild
23 existing distribution lines as well as construct a new
24 overhead and underground transmission line between the Wood
25 River substation in Hailey and the Ketchum substation in
COLBURN, DI 31
Idaho Power Company
I northeastern Ketchum. The new transmission line and related
2 facilities will provide a redundant source of energy into
3 the northern portion of the Wood River Valley, including
4 the communities of Ketchum and Sun Valley and portions of
5 Blaine County (collectively referred to as the "North
6 Valley") .
7 Q. What drove the need for the WRV Project?
8 A. The North Valley contains the resort
9 communities of Ketchum and Sun Valley as well as the Sun
10 Valley ski resort. Currently, the North Valley is served by
11 the Wood River and Ketchum substations, which are connected
12 to the Company' s transmission system by a single-source,
13 12 . 4 mile, 138-kV radial line that was built in 1962 with
14 wooden poles . If the line experiences sustained outages,
15 the outages may be lengthy because access to repair the
16 line is impeded by residential development, rough terrain,
17 and aged construction roads in many areas . Further, the
18 mountainous terrain limits vehicle access, impedes
19 equipment set-up, and contributes to avalanche threats .
20 Ultimately, the need to construct the WRV Project was to:
21 (1) increase reliability to the area by providing a
22 redundant source of energy, and (2) reconstruct the
23 existing and aging 138-kV radial transmission line without
24 long-term disruption of service to the North Valley.
25
COLBURN, DI 32
Idaho Power Company
1 Q. Does the Company have standard business
2 practices it follows for determining when construction of a
3 redundant transmission line is needed?
4 A. Yes . Idaho Power generally initiates and
5 constructs a second transmission source and transformer
6 when a substation peak load is projected to exceed 40
7 megawatts ("MW") . With peak loads of about 60 MW at the
8 Ketchum and Elkhorn substations', coupled with the winter
9 tourism population in the North Valley, the need for a
10 second transmission line was strongly supported. Multiple
11 transmission sources are standard practices that Idaho
12 Power implements to reduce the likelihood of sustained
13 outages . Additionally, the Company installs distribution
14 circuit tie switches, where adjacent circuits are
15 available, to reduce the duration of sustained outages on
16 the radially sourced distribution system.
17 Q. Were there any alternatives to the redundant
18 transmission line component of the WRV project?
19 A. No. Reconstruction of the existing line, which
20 was required whether a redundant transmission line was
21 constructed or not, was not feasible absent long-term
22 outages without building either a redundant transmission
23 line or a temporary line that would be removed after
1 The Elkhorn substation is located between the Ketchum and Wood River
substations, via a tap connection on the existing Wood River to Ketchum line.
COLBURN, DI 33
Idaho Power Company
1 construction because of the extreme disruption of service
2 required by the reconstruction.
3 WRV Project Background
4 Q. Prior to commencing work, did Idaho Power
5 perform any community outreach and invite public
6 participation regarding the plan for the WRV Project?
7 A. Yes . In 1995, the Company first undertook an
8 extensive public involvement process regarding the proposed
9 construction of the WRV Project. At the conclusion of the
10 process, Idaho Power carefully evaluated the input received
11 from the area' s public officials and citizens . The general
12 response at that time was that, despite the unavoidable
13 risk of an outage to the existing transmission line, the
14 proposed new transmission line should not be built. The
15 reasons for the public opposition included the difficulty
16 of finding an acceptable route for the transmission line,
17 aesthetic impacts, perceived health and safety concerns,
18 and the requirement that local funding of incremental costs
19 of placing part or all the line underground would be
20 required. The project was put on hold indefinitely and
21 Idaho Power' s previous Certificate of Public Convenience
22 and Necessity to construct the line was cancelled. 2
2 In the Matter of the Application of Idaho Power Company for an Amended
Certificate of Public Convenience and Necessity No. 272, Case No. IPC-
E-95-06, Order No. 26107 and cancelled Certificate No. 272 (Aug. 1995) ;
Case No. U-1006-89, Order No. 11315 and Certificate No. 272 (Feb.
1974) .
COLBURN, DI 34
Idaho Power Company
1 Subsequently, in 2004, Idaho Power initiated several
2 Community Advisory Committees ("CAC") and undertook a
3 comprehensive, cooperative transmission planning exercise
4 with the communities and leaders across its service
5 territory. These committees were created to provide a
6 cooperative effort between the Company and the communities
7 it serves in developing an outline for prioritized
8 improvements and additions to Idaho Power' s transmission
9 and substation infrastructure. One of those, the Wood River
10 CAC, was convened in 2007 and developed the Wood River
11 Valley Electrical Plan ("WREP") , a comprehensive plan for
12 future transmission facilities in the Wood River Valley.
13 Q. Did the WREP include some form of the WRV
14 Project?
15 A. Yes . The WREP included construction of the
16 redundant 138-kV transmission line between the Wood River
17 and Ketchum substations . The WREP was updated in 2011 after
18 additional deliberations and extensive public outreach, and
19 in 2012 the CAC reconvened to provide additional input for
20 planned open house events . In 2014, both the City of
21 Ketchum and the Ketchum Energy Advisory Committee were
22 invited to join the CAC, which reaffirmed the need for a
23 second energy path into the North Valley. While most of the
24 parties generally agreed upon the purpose and need for the
25 redundant transmission line, the consensus opinion was that
COLBURN, DI 35
Idaho Power Company
1 a feasible route could only be obtained and permitted if at
2 least a portion of the line was underground. However, the
3 parties were unable to reach agreement about the funding
4 and payment of any incremental cost difference between an
5 overhead, or least-cost alternative, and an underground, or
6 higher-cost build.
7 Q. Did Idaho Power provide an option for
8 undergrounding a portion of the WRV Project such that no
9 incremental cost recovery from the local jurisdictions
10 would be required?
11 A. Yes . The proposed line route and facilities
12 included a 138-kV overhead transmission line from the Wood
13 River substation, north along Highway 75, to an underground
14 transmission transition point near Elkhorn Road, and then
15 underground to the Ketchum substation. These proposed
16 facilities would follow the same path as the existing
17 distribution lines, replacing them and minimizing the
18 aesthetic impact. The route was economically equivalent to
19 the Company' s standard construction configuration and
20 therefore would not require any additional incremental cost
21 recovery from the local jurisdictions .
22 CPCN for the WRV Project
23 Q. You indicated Idaho Power had previously filed
24 a request for a CPCN for a new transmission line to serve
25 the North Valley area but withdrew the request. Did the
COLBURN, DI 36
Idaho Power Company
1 Company file a subsequent request for a CPCN following
2 community consensus on a feasible route that included Idaho
3 Power' s proposed solution that would not require
4 incremental cost recovery from local jurisdictions?
5 A. Yes . On November 8, 2016, the Company filed
6 Case No. IPC-E-16-28, requesting the Commission find that
7 the new 138-kV transmission line and related facilities to
8 provide redundant service from the Wood River substation
9 into the Ketchum substation was needed, and further
10 requesting the Commission grant a CPCN for construction of
11 the line as proposed and agreed upon by the local
12 jurisdictions . The Commission issued Order No. 33872 on
13 September 15, 2017, granting Idaho Power' s request for a
14 CPCN for a second 138-kV line, approving the requested
15 route of overhead transmission from the Wood River
16 substation to the transition point near Elkhorn Road, then
17 underground transmission to the Ketchum substation.
18 Q. At the time the CPCN was issued, had the
19 Company received the local permits necessary for
20 construction of the new 138-kV line?
21 A. No. Prior to the CPCN proceeding, Idaho Power
22 submitted an application for a Conditional Use Permit
23 ("CUP") to the Blaine County Board of Commissioners
24 ("County Board") , which was ultimately denied. Subsequent
25 to the issuance of the CPCN, the Company filed a new CUP
COLBURN, DI 37
Idaho Power Company
1 with the County Board to seek out a mutually acceptable
2 route configuration that was consistent with the CPCN route
3 and acceptable to Blaine County, with the opportunity to
4 mutually agree to certain micro-siting of facilities, and
5 for the County Board to request additional undergrounding
6 should it identify a method to fund the additional
7 incremental cost of such undergrounding.
8 Idaho Power then carried out extensive public
9 involvement and local permitting efforts relating to the
10 transmission line project and, although lengthy, ultimately
11 came to an agreement with the County Board on a line route
12 configuration, as well as a surcharge mechanism to fund the
13 incremental cost of additional undergrounding by Idaho
14 Power' s customers in Blaine County.
15 Final WRV Project Route Configuration
16 Q. What changes were made to the line route
17 configuration that required the establishment of a
18 surcharge mechanism?
19 A. Following filing of the new CUP application in
20 November 2017, Idaho Power worked with the Blaine County
21 Planning and Zoning ("P&Z") Commission, with engagement
22 from the County Board, and lengthy public hearing
23 processes, conducting extensive analysis of the micro-
24 siting options identified by the P&Z Commission. The CUP
25 application was approved on January 15, 2019, though no
COLBURN, DI 38
Idaho Power Company
1 specific route for the line was approved. While several
2 parties appealed this decision, the County Board ultimately
3 affirmed the P&Z Commission' s CUP grant on appeal, with the
4 condition that "the entire transmission line be
5 undergrounded from the Wood River Substation north to the
6 City of Ketchum.3 However, recognizing it could be difficult
7 to secure the required funding to bury the entire
8 transmission line, the decision left open the possible
9 consideration of "an overhead transmission line in this
10 area. "4
11 Securing funding to underground substantial portions
12 of the line did prove difficult, although the County Board
13 explored a variety of options, including passing a bond or
14 government grants . The County Board, with consultation from
15 the P&Z Commission, prioritized portions of the line and
16 facilities for undergrounding. To cover the cost of the
17 incremental undergrounding, the County Board asked Idaho
18 Power to develop a surcharge mechanism that would be placed
19 on Blaine County customers' electric bills .
20 Ultimately the new line configuration, referred to
21 as the Owl Rock Road Route, was agreed upon by all parties
22 involved in the P&Z and CAC efforts, and included the
23 burial of: (1) an additional 1 . 4 miles of transmission,
3 County Board's June 2019 Decision on Appeal.
4 Id.
COLBURN, DI 39
Idaho Power Company
1 located to the south from Elkhorn Road to near Owl Rock
2 Road, and (2) the existing distribution line for
3 approximately 8 miles along the planned route along
4 Buttercup Road to Highway 75 . The transmission line would
5 include overhead construction from the Wood River
6 substation to the underground transition point at Owl Rock
7 Road. Additionally, rather than place the existing
8 distribution lines as under-build on the new overhead
9 transmission structures, the existing distribution lines
10 along the route would be buried. This will both reduce the
11 height of the transmission poles and reduce the number of
12 lines in the air as the transmission line will have three
13 energized wires while the existing distribution line has
14 between three and six energized wires and one neutral wire .
15 Q. Did the County Board approve the CUP for the
16 Owl Rock Road Route?
17 A. Yes . On December 22, 2020, Idaho Power filed
18 an application to the County Board for CUP approval of the
19 Owl Rock Road Route funded by a surcharge mechanism to be
20 placed on Blaine County customers' electric bills . The
21 County Board approved the CUP for the Owl Rock Road Route
22 on March 9, 2021 . Under this CUP, the County Board modified
23 the "all underground" condition for the WRV Project and
24 replaced the language with a condition that the CUP was
25 contingent on partial undergrounding as decided on with the
COLBURN, DI 40
Idaho Power Company
1 Owl Rock Road Route. This final CUP from the County Board
2 gave Idaho Power authority to move forward with an
3 application with the Commission for approval of a modified
4 line route CPCN based on the Owl Rock Road Route, as well
5 as authority to develop a surcharge that would be used to
6 collect the incremental costs of undergrounding from Blaine
7 County customers .
8 Q. Please describe the intent of the surcharge
9 mechanism.
10 A. As I discussed earlier in my testimony, to
11 recover the incremental costs of undergrounding the section
12 of transmission and distribution lines prioritized by the
13 County Board, the Company was asked by the County Board to
14 develop a monthly surcharge to be applied to Idaho Power' s
15 Blaine County customers' bills over an estimated 20-year
16 period.
17 Q. Did the Company receive approval from the
18 Commission for the changes to the line route configuration
19 and resulting surcharge mechanism?
20 A. Yes . On June 28, 2022, in Case No . IPC-E-21-
21 25, the Commission issued Order No. 35452, finding the
22 modified line configuration for the WRV Project and
23 implementation of a surcharge mechanism were fair, just,
24 and reasonable.5 The Commission issued an amended CPCN to
5 Case No. IPC-E-21-25, Order No. 35452 at 16 (June 28, 2022) .
COLBURN, DI 41
Idaho Power Company
1 reflect the new line route configuration on August 2, 2022 .
2 Figure 1 below is the Owl Rock Road Route, identifying the
3 transmission line and line segments to be buried.
4 FIGURE 1
5 WRV PROJECT
i'
.1
Jv-
1
i
-Lbnny fnnunif.an L.i.
6
7 WRV Project Costs
8 Q. What is the status of the WRV Project?
9 A. In the fall of 2023, work began on the
10 distribution line portion of the WRV Project and continued
11 until the weather prohibited progress . Construction resumed
12 again in the spring of 2024, paused again when weather
COLBURN, DI 42
Idaho Power Company
1 prohibited progress, and resumed in 2025 . Work is
2 anticipated to be complete on the distribution line portion
3 by November 2025 .
4 Q. The distribution undergrounding is a portion
5 of the broader WRV Project. What work is being completed in
6 November 2025?
7 A. Work on the WRV Project began with the
8 undergrounding of approximately eight miles of the existing
9 distribution line along Buttercup Road and Highway 75, to
10 allow the future transmission line to be built with shorter
11 transmission poles to meet county height requirements . To
12 prepare for undergrounding of the distribution line, crews
13 first excavated a duct bank and made multiple bores along
14 the eight-mile route. Next, the distribution line is
15 installed in the duct bank and equipment is installed to
16 connect existing customers .
17 Q. Has Idaho Power included the costs associated
18 with the distribution line portion of the WRV Project,
19 which is anticipated to be completed in November 2025, in
20 the Company' s request in this case?
21 A. Yes . However, the Company has reduced the
22 total project costs by the estimated incremental
23 undergrounding costs of distribution, as those costs will
24 be recovered from Idaho Power' s Blaine County customers
25 only through the surcharge mechanism upon completion of
COLBURN, DI 43
Idaho Power Company
1 both the distribution and transmission portions of the
2 project .
3 Q. You indicated the Company reduced the WRV
4 Project costs associated with the distribution line
5 included in Idaho Power' s request in this case by an
6 estimate of the incremental undergrounding costs . Why was
7 an estimate used as opposed to actual costs?
8 A. Order No. 35452 acknowledged the Company' s
9 methodology for computing the estimated incremental
10 grounding costs . Because the distribution line
11 configuration Idaho Power would have constructed under a
12 standard construction configuration was not built, the
13 Company cannot identify the precise costs it would have
14 incurred under the hypothetical scenario. That is, the
15 request for proposals issued for the work to be performed
16 or materials to be procured was based on a different
17 distribution line configuration and therefore Idaho Power
18 cannot compute with certainty the portion of the costs that
19 would have been incurred under a different distribution
20 line configuration.
21 Q. How did Idaho Power develop the incremental
22 cost estimate?
23 A. To estimate the incremental costs associated
24 with the modified distribution line configuration, the
25 Company built a cost estimate associated with a comparable
COLBURN, DI 44
Idaho Power Company
1 overhead distribution line rebuild with a standard
2 construction configuration which entails replacement of all
3 distribution line equipment, including overhead wires and
4 pole mounted equipment, except for most of the distribution
5 poles . Costs were added to reflect: (1) the overhead
6 distribution work being performed on an energized system,
7 (2) the replacement of a portion of the existing wood poles
8 with taller, steel poles as required by the line design,
9 and (3) the addition of distribution intersect poles that
10 would have been required for the distribution under-build.
11 Finally, Allowance for Funds Used During Construction,
12 overheads, and a contingency were applied to the total
13 project costs as is standard when developing a project cost
14 estimate.
15 Q. What are the WRV Project costs included in the
16 Company' s request in this case?
17 A. Net WRV Project cost of $11 . 8 million are
18 included for recovery in this case from all customers,
19 which reflects estimated project costs less the amount that
20 will be recovered through the separate WRV Project
21 surcharge .
22 Q. In Case No. IPC-E-24-07, Idaho Power included
23 in its request costs associated with the distribution line
24 portion of the WRV Project. Is this the same portion of the
25 project the Company is requesting recovery of in this case?
COLBURN, DI 45
Idaho Power Company
1 A. Yes . However, while initially proposed to be
2 included in Idaho Power' s request in Case No. IPC-E-24-07,
3 when it became clear that, due to circumstances outside of
4 the Company' s control, the distribution portion of the line
5 would not be fully completed in December 2024 as previously
6 expected, in rebuttal testimony, Idaho Power proposed to
7 remove the amounts from the request. With the work nearing
8 completion, the Company has again included the costs
9 associated with the distribution line portion of the WRV
10 project in this case.
11 IV. MOBILE WORKFORCE SYSTEM INVESTMENT
12 Q. Please describe the investment necessary for
13 support of Idaho Power' s mobile workforce system.
14 A. The Company' s mobile workforce system enables
15 the electronic dispatching of work to crews and electronic
16 acknowledgement of the completion of orders, allowing for
17 the real-time processing of customer-request or outage
18 driven work through mobile devices . Idaho Power currently
19 uses the CGI Technologies and Solutions Inc. ("CGI")
20 PragmaCAD and PragmaLINE solutions to serve the mobile
21 workforce system. However, beginning in 2023, the current
22 CGI server and data base would no longer be supported and
23 no enhancements were available. Absent the mobile workforce
24 system, the Company would revert back to the inefficient
25 processing of orders manually via phone or paper. The
COLBURN, DI 46
Idaho Power Company
1 existing software however was coupled with the Company' s
2 Outage Management System, which was scheduled to be
3 migrated to the single vendor platform as part of the grid
4 modernization efforts and would require decoupling as part
5 of the migration. As a result, the software solution for
6 the mobile workforce system was planned for implementation
7 coincident with the migration of the Outage Management
8 System.
9 Q. What work does the PragmaCAD migration
10 require?
11 A. In addition to the software migration, the
12 decoupling of the PragmaCAD system from the Outage
13 Management System requires the building of PragmaCAD-
14 specific databases and servers . This approximately 15-month
15 process includes the migration, design, and configuration
16 followed by testing, verification, training and deployment.
17 Total project costs associated with the software migration
18 included in Idaho Power' s request are approximately $2 . 8
19 million and the project was completed in April 2025 .
20 Q. Does the PragmaCAD migration demonstrate a
21 prudent approach to investment in the Company' s system?
22 A. Yes . The decoupling of the PragmaCAD from the
23 Outage Management System and subsequent migration of the
24 PragmaCAD software was necessary to support the mobile
25 workforce and the Company' s continued delivery of safe,
COLBURN, DI 47
Idaho Power Company
1 reliable electricity to customers .
2 V. IDAHO POWER' S WILDFIRE MITIGATION EFFORTS
3 Q. How does the Company work to mitigate wildfire
4 risks?
5 A. Idaho Power deploys a variety of wildfire risk
6 mitigation activities through its Wildfire Mitigation Plan
7 ("WMP") , which was developed in response to the increase in
8 frequency and intensity of wildfires seen across the
9 western United States in recent years . In 2019, the Company
10 first developed the WMP to identify areas within the Idaho
11 Power' s service area exposed to higher levels of wildfire
12 risk. As an action plan for Company operations, the WMP
13 includes best practices for mitigating wildfire risk that
14 guide operational, personnel, and communication practices
15 before, during, and after wildfire season.
16 Q. What is contributing to the growth of western
17 wildfires in recent years?
18 A. A variety of factors have contributed to a
19 greater number of destructive wildfires, including climate
20 change, increased human encroachment in wildland areas,
21 historical land management practices, and changes in
22 wildland and forest health, among other factors . In 2024,
23 Idaho saw its most active fire season in recent history.
24 The National Interagency Fire Center ("NIFC") recorded 252
25 wildfire starts and 1, 509, 455 acres burned in or near Idaho
COLBURN, DI 48
Idaho Power Company
1 Power' s service area during the 2024 season6 with 996, 7627
2 acres of the total acreage referenced above burned in the
3 State of Idaho. While the number of fire starts was
4 slightly above the 30-year average of 235, the number of
5 acres burned in or near Idaho Power' s service area almost
6 doubled the 30-year average of 860, 725 .8 Development of the
7 2025 WMP came on the heels of this active 2024 fire season
8 and, drawing from its experiences, Idaho Power conducted a
9 comprehensive evaluation of its entire wildfire program
10 including activities, tools, and personnel, and identified
11 several critical measures to strengthen and enhance its
12 existing efforts . These items fall into four categories :
13 Quantifying Wildland Fire Risk, Situational Awareness,
14 Wildfire Program & Personnel, and Enhanced Vegetation
15 Management.
16 Q. What are the Company' s plans to strengthen the
17 quantification of wildland fire risk?
18 A. Assessing and monitoring wildfire risk is the
19 cornerstone of Idaho Power' s wildfire mitigation efforts .
20 Beginning in 2025, the Company is transitioning to a
21 wildfire risk modeling platform that will give Idaho Power
22 more granular insight into wildfire risk across the
6 Idaho Power's 2025 Wildfire Mitigation Plan, pg. 13.
7 National Interagency Coordination Center - Wildland Fire Summary and
Statistics Annual Report 2024, pg. 44.
8 Idaho Power's 2025 Wildfire Mitigation Plan, pg. 13.
COLBURN, DI 49
Idaho Power Company
1 Company' s service area, allow Idaho Power to incorporate
2 weather modeling into risk assessments, and help the
3 Company produce updated risk maps of its service area and
4 transmission corridors . Idaho Power will also expand its
5 fire spread simulation modeling to gain deeper insight into
6 fire behavior and the potential consequence of wildfire
7 ignitions within the Company' s service area. Additionally,
8 Idaho Power will be investing in a variety of tools and
9 databases to help the Company assess the efficacy of its
10 wildfire mitigation efforts . Idaho Power anticipates the
11 costs of advanced wildfire risk modeling tools to enhance
12 wildfire mitigation efforts to be approximately $2 million
13 in 2025 .
14 Q. How will Idaho Power improve its situational
15 awareness associated with wildfire risk?
16 A. Situational awareness plays a vital role in
17 the Company' s ability to adequately prepare for and operate
18 during times of heightened wildfire risk. Each wildfire
19 season, through its own experience as well as those of
20 other utilities, Idaho Power learns more about how to
21 enhance situation awareness through a variety of means . For
22 the upcoming fire season, the Company has identified four
23 areas for expanded situational awareness efforts : (1)
24 contracting for the evaluation and validation of the data
25 collected through the Idaho Power-specific weather tool,
COLBURN, DI 50
Idaho Power Company
1 (2) pursuit of a waiver from the Federal Aviation
2 Commission to operate drones beyond the visual line of
3 sight, (3) commence an aerial drone inspection pilot
4 project, and (4) expand the contract for standby helicopter
5 service. At an estimated annual cost of approximately
6 $900, 000, these enhanced situational awareness efforts will
7 aid in the preparation for, and operation during, the
8 wildfire season.
9 Q. What improvements will Idaho Power be making
10 to strengthen and enhance its wildfire mitigation program
11 and personnel?
12 A. One of the key lessons learned from the past
13 year is that wildfire work is truly a year-round effort
14 that requires dedicated staff to prepare for, manage, and
15 learn from each wildfire season. To strengthen Idaho
16 Power' s wildfire mitigation efforts, the Company will hire
17 additional personnel to support critical functions
18 essential for reducing wildfire risk and enhancing system
19 safety. The total cost of the new positions in 2025 is
20 estimated to be approximately $1 . 1 million.
21 Q. How will Idaho Power enhance its vegetation
22 management efforts?
23 A. Vegetation management is both imperative to
24 the Company' s wildfire mitigation efforts and a source of
25 significant challenge. The availability of qualified labor
COLBURN, DI 51
Idaho Power Company
1 has diminished while demand for vegetation management
2 services has grown across the Western United States . To
3 help address these challenges, Idaho Power has hired a
4 three-person internal vegetation management crew to help
5 reduce ongoing pruning costs, improve production levels,
6 and mitigate rising expenses associated with contracted
7 services . Additionally, the Company will continue to invest
8 in Enhanced Vegetation Management practice in wildfire risk
9 zones . Vegetation management continues to represent the
10 largest single cost category in Idaho Power' s wildfire
11 mitigation activities, with an estimated incremental cost
12 of $19 .2 million in 2025 .
13 Q. Do you believe the Company' s wildfire
14 mitigation efforts demonstrate a prudent and proactive
15 approach to mitigating wildfire risk?
16 A. Yes . Idaho Power' s WMP presents holistic and
17 prudent strategies to improve safety, reliability while
18 balancing affordability for customers and the communities
19 the Company serves . Idaho Power continues its grid
20 hardening efforts to protect against wildfires and other
21 natural emergencies . In addition, to reduce wildfire risk,
22 the Company is expanding situational awareness
23 capabilities, further enhancing vegetation management
24 programs and upgrading risk modeling practices .
COLBURN, DI 52
Idaho Power Company
I VI . CONCLUSION
2 Q. Please summarize your testimony.
3 A. As evidenced by the continued growth in
4 transmission and distribution investments, the Company
5 continues its thoughtful and prudent approach to
6 construction and maintenance of its transmission and
7 distribution systems to ensure Idaho Power maintains a safe
8 and reliable system, while also making great strides to
9 mitigate wildfire risk.
10 Q. Does this conclude your direct testimony in
11 this case?
12 A. Yes, it does .
13
COLBURN, DI 53
Idaho Power Company
1 DECLARATION OF MITCH COLBURN
2 I, Mitch Colburn, declare under penalty of perjury
3 under the laws of the state of Idaho:
4 1 . My name is Mitch Colburn. I am employed by
5 Idaho Power Company as the Vice President of Planning,
6 Engineering and Construction.
7 2 . On behalf of Idaho Power, I present this
8 pre-filed direct testimony in this matter.
9 3 . To the best of my knowledge, my pre-filed
10 direct testimony is true and accurate.
11 I hereby declare that the above statement is true to
12 the best of my knowledge and belief, and that I understand
13 it is made for use as evidence before the Idaho Public
14 Utilities Commission and is subject to penalty for perjury.
15 SIGNED this 30th day of May 2025, at Boise, Idaho.
16
17 Signed:
18 MITCH COLBURN
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COLBURN, DI 54
Idaho Power Company