20230601Direct Colburn.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC SERVICE IN THE STATE OF IDAHO AND FOR
ASSOCIATED REGULATORY ACCOUNTING TREATMENT.
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CASE NO. IPC-E-23-11

IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
MITCH COLBURN
COLBURN, DI 1
Idaho Power Company
Q. Please state your name, business address, and 1
present position with Idaho Power Company (“Idaho Power” or 2
“Company”). 3
A. My name is Mitch Colburn. My business address 4
is 1221 West Idaho Street, Boise, Idaho 83702. I am 5
employed by Idaho Power as the Vice President of Planning, 6
Engineering, and Construction. 7
Q. Please describe your educational and 8
professional experience. 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
I have worked at Idaho Power since 2007. Prior to my 17
current role, I served as Director of Engineering and 18
Construction, Director of Resource Planning and Operations, 19
Senior Manager of Transmission & Distribution Strategic 20
Projects, Engineering Leader over 500 kilovolt (“kV”) and 21
Joint Projects. I held several engineering roles prior to 22
these leadership roles. 23
Q. What are your duties as Vice President of 24
Planning, Engineering, and Construction? 25
COLBURN, DI 2
Idaho Power Company
A. I am responsible for an organization of more 1
than 380 employees focused on multiple areas: 2
1) Identifying future electric grid 3
infrastructure requirements, 4
2) Operating and maintaining the electric grid, 5
including the wildfire mitigation program and 6
vegetation management, and 7
3) Designing, engineering, and constructing grid 8
infrastructure projects. 9
Q. What is the purpose of your testimony in this 10
matter? 11
A. The purpose of my testimony is to discuss the 12
investments the Company has made in the electrical grid to 13
ensure the provision of safe, reliable service to 14
customers. My testimony will begin with a discussion of 15
Idaho Power’s recent history of reliability and performance 16
that demonstrates a thoughtful approach to grid 17
construction and maintenance. Next, I will detail specific 18
investments included in the Company’s 2023 test year that 19
demonstrate the Company’s prudent investment in the 20
electrical grid at the transmission and distribution 21
(“T&D”) levels. Finally, my testimony will review the 22
Company’s wildfire mitigation efforts and associated 23
capital and operation and maintenance (“O&M”) expenditures 24
proposed for recovery in this case. 25
COLBURN, DI 3
Idaho Power Company
Q. What exhibits are you sponsoring? 1
A. I am sponsoring Exhibit Nos. 4 and 5. 2
I. Reliability and Performance 3
Q. How is reliability typically measured on the 4
Company’s system? 5
A. As discussed in the Direct Testimony of 6
Company Witness Ms. Lisa Grow, Idaho Power primarily uses 7
four indices to measure reliability of the system. To 8
summarize the information provided by Ms. Grow, these four 9
measurements are: 10
SAIFI: System Average Interruption Frequency Index 11
SAIDI: System Average Interruption Duration Index 12
CEMI: Customers Experiencing Multiple Interruptions 13
MAIFI: Momentary Average Interruption Frequency 14
Index 15
Q. Please provide a brief description of each of 16
these measures. 17
A. SAIFI, SAIDI, and CEMI are indices that 18
measure sustained outages. A sustained outage is defined as 19
customers out of power for five minutes or longer. CEMI is 20
typically referred to as “CEMI-1” through “CEMI-6,” where 21
CEMI-1 indicates the percentage of customers who had one or 22
more outage, CEMI-2 indicates the percentage of customers 23
who had two or more outages, and so on. MAIFI is an index 24
that measures momentary interruptions. Momentary 25
COLBURN, DI 4
Idaho Power Company
interruptions are when customers are out of power for fewer 1
than five minutes. 2
Q. Based on these metrics, has Idaho Power 3
demonstrated prudent and reliable operation of the 4
electrical grid? 5
A. Yes. As detailed in Ms. Grow’s testimony, 6
Idaho Power’s SAIFI metric has improved substantially since 7
2007. On a relative basis, a comparison of Idaho Power’s 8
rolling five-year average SAIFI compared to a peer utility 9
group demonstrates that the Company outperformed its peers 10
in each year since 2017. 11
Q. Has Idaho Power shown similar improvement in 12
MAIFI, SAIDI, and CEMI? 13
A. Yes. Each of these metrics has improved across 14
Idaho Power’s system for the prior 10-year period, as 15
demonstrated in Figures 1 through 3. 16
// 17
// 18
19
20
21
22
23
24
25
COLBURN, DI 5
Idaho Power Company
FIGURE 1 1
SAIDI, 2007 THROUGH 2022 2
3
FIGURE 2 4
MAIFI, 2007 THROUGH 2022 5
6
5.57
3.64
4.22
4.66
2.54
3.88
3.39
2.59
3.59
2.69
3.94
2.18 2.42
3.48
2.74 2.52
0
1
2
3
4
5
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
Year
SAIDI, 2007-2022
2.93 3.13
2.25
2.79
2.54
2.02
2.41 2.25
1.95 2.06 2.25
1.79
0
0.5
1
1.5
2
2.5
3
3.5
Year
MAIFI-E
COLBURN, DI 6
Idaho Power Company
FIGURE 3 1
CEMI 3 AND CEMI 6, 2007 THROUGH 2022 2
3
FIGURE 4 4
SAIFI, 2007 THROUGH 2022 5
6
7
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
In
t
e
r
r
u
p
t
i
o
n
s
Year
CEMI 3 and 6
CEMI3 CEMI6
1.00
1.20
1.40
1.60
1.80
2.00
2.20
2.40
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Idaho Power Annual SAIFI
IPC SAIFI Trend
COLBURN, DI 7
Idaho Power Company
Q. Do these metrics indicate prudent construction 1
and maintenance of the Company’s distribution and 2
transmission systems? 3
A. Yes. Idaho Power’s reliability metrics 4
reflect a thoughtful approach to construction and 5
maintenance of its T&D systems. Since the completion of the 6
Company’s last general rate case (“GRC”) in 2011 in Case 7
No. IPC-E-11-08, the Company has placed in service over 8
$3.3 billion in infrastructure. As I will discuss in my 9
testimony, approximately $1.6 billion of this total 10
reflects prudent investment in the T&D systems. The 11
corresponding improvement in the Company’s reliability 12
metrics over this same period indicates that this 13
investment was prudent to ensure the safe, reliable 14
provision of electric service. 15
II. Transmission Investments 16
Q. Please describe how the Company defines the 17
transmission-related portion of the electrical grid. 18
A. Transmission generally describes the bulk or 19
high voltage components of the electrical grid, including 20
stations and high voltage lines typically utilized to 21
transmit large volumes of electricity closer to load 22
centers. On Idaho Power’s system, transmission equipment is 23
considered to be facilities at or above 138 kV, with an 24
COLBURN, DI 8
Idaho Power Company
additional sub-transmission component comprised of 1
facilities at 46 kV and 69 kV. 2
Q. How has transmission-related investment grown 3
since the completion of the 2011 GRC? 4
A. Of the $3.3 billion in infrastructure placed 5
in service over this period, approximately $553 million 6
reflects investment in the Company’s transmission system. 7
Q. What drives investment in the transmission 8
system? 9
A. Growth and reliability are the primary drivers 10
of the transmission investments reflected in the Company’s 11
2023 test year. Growth-related projects typically include 12
either the construction of new transmission facilities or 13
the expanded capacity of existing facilities. Reliability 14
projects typically include the proactive reconstruction or 15
replacement of aging facilities. 16
Q. Please provide examples of growth and 17
reliability needs driving investment in the Company’s 18
transmission system between 2012 and 2022. 19
Q. Based on the growth experienced by Idaho Power 20
over this period, investment has been required to ensure 21
reliability on the Company’s transmission system. Two 22
projects that demonstrate how growth drives transmission 23
investment are the rebuild of the 59-mile transmission line 24
between the King Substation and the Wood River Substation 25
COLBURN, DI 9
Idaho Power Company
in the Wood River Valley (“King-Wood River Rebuild”) and 1
the upgrade of the 6.8-mile transmission line between the 2
Cloverdale Substation and the Hubbard Substation in the 3
Treasure Valley (“Cloverdale Line Rebuild”). 4
Q. What factors led to the King-Wood River 5
Rebuild? 6
A. Growth in the Wood River Valley was causing 7
strain on the regional grid. Specifically, transmission 8
planning studies required1 by the North American Electric 9
Reliability Corporation (“NERC”) and dating back to 2009 10
demonstrated the need for transmission system upgrades to 11
maintain adequate system voltage in the future and avoid 12
needing to shed load for certain system conditions. To 13
comply with NERC standards and to ensure the Company’s 14
reliability metrics provided earlier in my testimony did 15
not degrade, investment in the local area transmission 16
system was necessary. 17
Q. What actions did Idaho Power take to ensure 18
the reliability of its transmission system? 19
A. In response to the identified need, Idaho 20
Power rebuilt the line between the King and Wood River 21
substations, upgrading the capacity of the line. 22
Additionally, for enhanced reliability the Company replaced 23

1 NERC TPL-001 Reliability Standard (Table 1 – Steady State & Stability Performance).
COLBURN, DI 10
Idaho Power Company
the existing wood structures with steel components. This 1
investment was required to ensure that system reliability 2
was maintained while accommodating growth in the area. 3
Q. Did similar factors lead to the Cloverdale 4
Line Rebuild in the Treasure Valley? 5
A. Yes. Similar factors led to the Cloverdale 6
Line Rebuild, further exemplifying how growth drives the 7
need for investment to maintain a robust, reliable 8
transmission system. In 2015, NERC-required transmission 9
planning studies demonstrated the need for a 230-kV 10
connection between the Hubbard and Cloverdale substations, 11
whereas the existing line was 138 kV. The study showed that 12
growth in the area had resulted in expected loads under 13
certain conditions exceeding emergency equipment rating 14
limits. 15
Q. What actions did Idaho Power take to address 16
the reliability needs identified by this study? 17
A. In response to the growth-driven reliability 18
requirements in the area, Idaho Power upgraded the local-19
area capacity by replacing the existing 138-kV line with a 20
230-kV circuit, as well as constructing distribution 21
circuits located on the same structures as the 230-kV 22
transmission line. This upgrade reflected a cost-effective 23
solution to meet the requirements of growing load in the 24
COLBURN, DI 11
Idaho Power Company
Treasure Valley, enhancing and maintaining reliability of 1
the local transmission system. 2
Q. Can you provide an example of transmission 3
investment driven by the Company’s proactive approach to 4
aging infrastructure? 5
A. Yes. The Company’s work on the Midpoint-to-6
Borah 345-kV transmission line demonstrates the need to 7
invest in maturing longer-lived assets to ensure ongoing 8
safe and reliable operation of the grid. 9
Q. Please describe the Midpoint-to-Borah 10
transmission line. 11
A. The Midpoint-to-Borah 345-kV transmission line 12
serves as a major component of the Company’s bulk 13
transmission system. This line was originally constructed 14
in 1948 and operated at 138 kV, and over the next several 15
decades was modified and improved to its current operating 16
capacity of 345kV. Enhancements to the line over this 17
period included an increase in capacity due to the addition 18
of the Jim Bridger Power Plant, which included the addition 19
of a second conductor, conductor re-configuration on the 20
structures, and adding additional insulation to operate at 21
a higher voltage. However, as the transmission line aged, 22
issues began to arise related to ground clearance and 23
leaning structures. 24
COLBURN, DI 12
Idaho Power Company
Q. What action was required to address this aging 1
and important component of the Company’s bulk transmission 2
system? 3
A. The age and importance of this line warranted 4
complete replacement of the structures from the Midpoint 5
Substation to the Borah Substation. The existing wood-pole 6
structures were replaced with steel-pole structures, 7
remedying the potential structural issues by installing 8
resilient, long-life steel poles. 9
Q. Do the projects you have discussed demonstrate 10
a prudent approach to investment in the Company’s 11
transmission system over the last decade, and support the 12
Company’s transmission-related rate base included in this 13
case? 14
A. Yes. Over the last decade Idaho Power has 15
invested over $553 million in its transmission system. As 16
evidenced by the King-Wood River Rebuild and Cloverdale 17
Line Rebuild projects, Idaho Power is constantly evaluating 18
the capacity needs and reliability of its transmission 19
systems, ensuring that the electrical grid is stable and in 20
compliance with NERC standards. As further evidenced by the 21
Midpoint-to-Borah Rebuild, Idaho Power’s investments in the 22
transmission system over the last decade reflect a 23
thoughtful, proactive approach to ensuring bulk system 24
reliability. As evidenced by the improving reliability 25
COLBURN, DI 13
Idaho Power Company
metrics experienced over this same period, these 1
investments were prudently made and in the public interest. 2
III. Distribution Investments 3
Q. Please describe how the Company defines the 4
distribution-related portion of the electrical grid. 5
A. Distribution refers to equipment at 34.5 kV 6
and below, including lower voltage lines, substations, and 7
transformers that are typically utilized to provide 8
electricity at the lower voltages required by the majority 9
of end-use customers. 10
Q. How much has distribution-related investment 11
grown since the completion of the 2011 GRC? 12
A. Of the $3.3 billion in plant placed in service 13
referenced previously in my testimony, approximately $1.0 14
billion is comprised of investments in the distribution 15
system. 16
Q. What factors contributed to investment in 17
Idaho Power’s distribution system over this period? 18
A. Growth in the distribution system can be 19
directly tied to the addition of new customers, as every 20
new customer, regardless of service level, requires some 21
form of additional equipment. In addition, similar to 22
certain components of the Company’s generation and 23
transmission systems, Idaho Power has also undertaken a 24
number of key projects to proactively harden its 25
COLBURN, DI 14
Idaho Power Company
distribution system to maintain and improve reliability in 1
light of aging infrastructure. These investments not only 2
include the proactive replacement of aging infrastructure, 3
but also the improvement of the distribution system through 4
the installation of modern technology. 5
Q. How does growth impact the need for investment 6
on the distribution system? 7
A. Growth impacts the distribution system in 8
several ways. First, the addition of new customers requires 9
new investment – from new service transformers and service 10
drops for every new customer to, once demand reaches 11
certain levels, new substations and lines. Additionally, 12
construction and growth within the Company’s service area 13
also result in the need for investment related to facility 14
relocations for road construction and other civil projects. 15
Q. What were the primary growth-related 16
components of distribution investment made over the last 17
decade? 18
A. Growth-related investment in the Company’s 19
distribution system consisted primarily of meters, 20
transformers, and other distribution infrastructure in each 21
of the Company’s operating regions. In addition to new 22
facilities, Idaho Power spent approximately $25 million 23
related to the relocation of facilities as the result of 24
road projects in the Company’s service area. 25
COLBURN, DI 15
Idaho Power Company
Q. In addition to serving growth, has Idaho Power 1
undertaken any major initiatives to maintain or improve the 2
reliability of its distribution system? 3
A. Yes. There are two notable initiatives Idaho 4
Power has undertaken to improve the reliability of its 5
distribution system: 1) the replacement of direct-buried 6
underground cable and 2) a grid modernization initiative 7
that encompasses multiple projects. 8
Q. Please describe what is meant by “direct-9
buried cable.” 10
A. Direct-buried cable describes underground 11
distribution cable that was directly buried in the soil 12
with no conduit. The use of direct-buried cable was 13
standard practice in the industry and for Idaho Power up 14
until the mid-1990s. 15
Q. What are the benefits of replacing direct-16
buried cable with new cable in conduit? 17
A. Replacing the existing direct-buried cable 18
with new cable in conduit improves reliability and lowers 19
future expenses when the cable needs to be replaced. 20
Q. How does the installation of cable with 21
conduit improve reliability? 22
A. Cable in conduit is better protected from 23
impacts related to direct contact with soil and moisture. 24
COLBURN, DI 16
Idaho Power Company
Consequently, faults are less frequent and cable in conduit 1
is expected to last longer than direct-buried cable. 2
Q. How does the installation of cable in conduit 3
help to lower future expenses when the cable needs to be 4
replaced? 5
A. The installation of conduit allows the Company 6
to replace the cable within the conduit more effectively 7
and cheaply. With conduit in place, the cable can be 8
removed from the conduit and new cable can be installed 9
more efficiently. This will help to eliminate fees and 10
expenses associated with permitting, flagging, landscaping 11
and repaving roads and sidewalks. 12
Q. How far has Idaho Power’s underground cable 13
replacement project progressed? 14
A. The underground cable replacement program 15
began in 2012 with completion forecasted for 2035, 16
targeting the replacement of approximately 350,000 feet of 17
direct-buried cable each year until all 7 million feet of 18
direct-buried cable have been replaced. To date, the 19
Company has completed approximately 4 million feet of cable 20
replacement. 21
Q. Please describe the grid modernization 22
initiative. 23
A. The grid modernization initiative is a set of 24
multi-year projects designed to maintain and improve 25
COLBURN, DI 17
Idaho Power Company
reliability on the Company’s electrical grid. This suite of 1
projects replaces and modernizes equipment nearing its end 2
of life and updates the Company’s distribution system with 3
modern technology to enhance reliability while keeping 4
costs low. 5
Q. What notable projects comprise grid 6
modernization efforts included in the 2023 test year? 7
A. Two notable projects under the Company’s grid 8
modernization initiative are the implementation of a new 9
700-megahertz (“MHz”) Field Area Network (“FAN”) and 10
replacement of an Automated Capacitor Control (“ACC”) 11
system with the development of a new integrated volt-var 12
control (“IVVC”) system. The IVVC system and FAN became 13
operational in 2019 and were built out across Idaho Power’s 14
service area by 2022. 15
Q. What are the FAN and the IVVC system, and how 16
do they interrelate? 17
A. The 700-MHz FAN serves as the communication 18
backbone for the IVVC system. The 700-MHz FAN is utilized 19
to send and receive secure, reliable wireless 20
communications to and from line devices on Idaho Power’s 21
distribution system. This communication supports the 22
gathering of data and control of distribution system 23
devices within the IVVC. 24
Q. How does the IVVC system benefit customers? 25
COLBURN, DI 18
Idaho Power Company
A. The IVVC system replaced a 22-year-old DOS-1
based system that was nearing its end of life and was 2
unable to provide for direct and coordinated voltage 3
control offered by more modern systems such as the IVVC 4
system. Replacing the ACC with the IVVC provides the 5
Company with the ability to better control devices and 6
gather data in real-time, allowing the Company to improve 7
power quality and voltage levels, optimize efficiency, and 8
provide visibility and control to engineers and operators 9
to better manage the distribution system. 10
At a high level, the IVVC system provides direct 11
feedback on the status of devices through two-way 12
communication, which reduces the need for seasonal 13
inspections, instead allowing for inspections to focus on 14
alarmed devices. This system is also the foundation for a 15
future fault location, isolation, and service restoration 16
(“FLISR”) system. Idaho Power is in the process of 17
installing fault location devices on the distribution 18
system, which is prevalent in the industry. 19
Q. Do these projects demonstrate a prudent 20
approach to investment in the Company’s distribution 21
system over the last decade and support the Company’s 22
distribution-related rate base included in this case? 23
A. Yes. Idaho Power’s thoughtful and proactive 24
approach to investing in its distribution system has 25
COLBURN, DI 19
Idaho Power Company
resulted in improved reliability metrics over the past 1
decade as detailed earlier in my testimony. In addition to 2
investing to accommodate growth within the Company’s 3
service area, Idaho Power invested in initiatives such as 4
underground cable replacement and grid modernization that 5
ensure the distribution system is equipped to provide safe, 6
reliable service to customers now and in the future. 7
IV. Idaho Power’s Wildfire Mitigation Efforts 8
Q. What total system costs did the Company 9
incur related to wildfire mitigation in 2022? 10
A. As outlined below in Table 1 of my 11
testimony, Idaho Power incurred a systemwide total of 12
$26,408,743 in wildfire mitigation-related O&M costs in 13
2022. This amount excludes insurance, which is discussed in 14
the Direct Testimony of Company Witness Mr. Brian Buckham. 15
Regarding capital expenditure, Idaho Power placed 16
in service $12,059,451 in capital projects to support 17
wildfire mitigation in 2021 and 2022. This amount does not 18
include capital depreciation, which is addressed in the 19
Direct Testimony of Company Witness Mr. Matthew Larkin. 20
Capital placed in service for 2021 and 2022 and 21
O&M expenditure for 2022 is detailed in Exhibit No. 4 to my 22
testimony. 23
COLBURN, DI 20
Idaho Power Company
Q. Are the Company’s actual 2022 costs related 1
to wildfire mitigation reflected in the Company’s revenue 2
requirement in this case? 3
A. Yes. The costs identified in my testimony 4
are factored into the Company’s 2023 test year revenue 5
requirement, as addressed in Mr. Larkin’s testimony. 6
Additionally, the treatment and accounting of the 7
Commission’s authorized wildfire deferrals are addressed in 8
the Direct Testimony of Company Witness Ms. Paula Jeppsen. 9
The remainder of my testimony in this section will 10
present the Company’s implementation of its Wildfire 11
Mitigation Plan (“WMP”) and will demonstrate the prudence 12
of the associated costs proposed for recovery in this case. 13
I will focus on costs incurred during 2022, as those costs 14
represent previously deferred amounts proposed for 15
amortization into rates in this case and form the basis for 16
the test year values addressed by Mr. Larkin. 17
Q. Why did Idaho Power develop a WMP? 18
A. Idaho Power is dedicated to safely delivering 19
reliable, affordable energy to its customers. In pursuit of 20
that mission, the Company developed a WMP in response to 21
the increase in frequency and intensity of wildfires seen 22
across the western United States (“US”) in recent years. 23
Q. To what extent has wildfire activity increased 24
in the West? 25
COLBURN, DI 21
Idaho Power Company
A. Since the 1980s, wildfire activity in the US, 1
as measured by acres burned, has more than tripled and, 2
according to the National Interagency Fire Center, western 3
states account for upwards of 95 percent of the acres 4
burned in recent years.2 Since 1983, the 10 years with the 5
largest acreage burned have all occurred in the period of 6
2004 through 2022.3 7
FIGURE 5 8
TOTAL US ACRES BURNED (1983-2002) 9
10
Q. What has contributed to the growth of western 11
wildfires in recent years? 12

2 Based on the National Interagency Fire Center historical year-end fire statistics by state. https://www.nifc.gov/fire-information/statistics
3 Based on the National Interagency Fire Center total wildland fires and acres (1983-2022). https://www.nifc.gov/fire-information/statistics https://www.nifc.gov/fire-information/statistics/wildfires
0
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
US Acres Burned
COLBURN, DI 22
Idaho Power Company
A. A variety of factors have contributed to a 1
greater number of destructive wildfires, including climate 2
change, increased human encroachment in wildland areas, 3
historical land management practices, and changes in 4
wildland and forest health, among other factors. 5
Q. How has Idaho Power been affected by the 6
increase of wildfires in the West? 7
A. While Idaho Power has not experienced 8
catastrophic wildfires within its service area at the same 9
level experienced in other western states, such as 10
California and Oregon, millions of acres of rangeland and 11
southern Idaho forests have burned in the last 30 years.4 12
In 2022, Idaho had fewer wildfires and acres burned 13
during wildfire season than the previous 20-year average.5 14
However, 436,733 acres burned in Idaho during the 2022 fire 15
season, a larger amount than the combined acres burned in 16
Arizona, Colorado, Montana, Nevada, Utah, and Wyoming in 17
2022.6 18
Q. What impacts could Idaho Power face because of 19
wildfire? 20

4 Rocky Barker, 70% of S. Idaho's Forests Burned in the Last 30 Years.
Think That Will Change? Think Again., Idaho Statesman, Oct 4, 2020.
5 Based on the National Interagency Fire Center historical year-end fire statistics by state. https://www.nifc.gov/fire-information/statistics
6 National Interagency Coordination Center Wildland Fire Summary and
Statistics Annual Report, 2022. https://www.predictiveservices.nifc.gov/intelligence/2022_statssumm/annual_report_2022.pdf
COLBURN, DI 23
Idaho Power Company
A. Wildfire can create myriad and costly 1
environmental, social, and economic impacts. The magnitude 2
and duration of these impacts depends on a fire’s size, 3
severity, and location. Generally, though, wildfire impacts 4
are considered in terms of lives threatened, structures or 5
homes lost or damaged, and damage to natural resources. 6
Specific to Idaho Power, wildfires have the 7
potential to damage or destroy the Company’s facilities, 8
impact personnel, and cause significant harm to Idaho 9
Power’s customers and the communities in which the Company 10
serves. 11
Q. How has Idaho Power responded to growing 12
wildfire risk? 13
A. As a result of growing and more frequent 14
wildfires in the West, Idaho Power began a proactive effort 15
in 2019 to develop a guiding wildfire mitigation document — 16
the WMP — that would use robust risk analysis to identify 17
areas within the Company’s service area exposed to higher 18
levels of wildfire risk. As an action plan for Company 19
operations, the WMP includes best practices for mitigating 20
wildfire risk that guide operational, personnel, and 21
communication practices before, during, and after wildfire 22
season. 23
Q. What are the objectives of the WMP? 24
COLBURN, DI 24
Idaho Power Company
A. Idaho Power developed the WMP to accomplish 1
two critical objectives: (1) reduce wildfire risk 2
associated with Idaho Power's T&D facilities and associated 3
field operations and (2) improve the resiliency of the 4
Company's T&D system impacted by wildfire events. 5
Q. How many WMPs has the Company developed? 6
A. In December 2022, the Company published its 7
2023 WMP (Exhibit No. 5), the Company’s fifth version of 8
the WMP since 2021. 9
Q. Please describe the prior versions of the WMP. 10
A. Version 1 of the WMP was filed with the 11
Commission in January 2021 in Idaho Power’s initial 12
wildfire-related cost deferral Application in Case No. IPC-13
E-21-02. Version 2, dated December 21, 2021, included an 14
expanded cost-benefit analysis discussion, WMP progress and 15
updates, and an introduction to the Company’s newly 16
developed Public Safety Power Shutoff (“PSPS”) program. 17
Version 3, dated June 28, 2022, included information added 18
to comply with the Public Utility Commission of Oregon’s 19
conditions of approval of the Company’s 2022 WMP. Version 20
4, filed with the Company’s cost deferral Application in 21
Case No. IPC-E-22-27, added Idaho and Oregon specific 22
information and state-specific forecasts of incremental 23
mitigation expenditure. Version 5, the current WMP for the 24
2023 fire season, includes a new executive summary, a 25
COLBURN, DI 25
Idaho Power Company
review of the 2022 fire season with lessons learned, a 1
forecast of condition for the upcoming fire season, and 2
provides a detailed discussion of 2023 fire season 3
mitigation measures. 4
Q. How will the WMP change from year to year? 5
A. Each year, the Company strives to improve upon 6
previous versions by incorporating new learnings, methods, 7
and feedback from stakeholders, customers, communities, 8
fire experts, and the Company’s regulators. Going forward, 9
the Company will file its annual WMP with the Commission, 10
as specified in Order No. 35717.7 Moving forward and to 11
reduce confusion, the Company will endeavor to avoid 12
multiple versions of the WMP and, instead, release one plan 13
in advance of each fire season. 14
Q. Please summarize the key elements of the WMP 15
that help meet the Company’s wildfire mitigation 16
objectives. 17
A. Idaho Power’s WMP includes comprehensive and 18
multi-faceted strategies that are effective at reducing 19
wildfire risk. Key elements of the plan include: 20
• Risk analysis and mapping: Utilizing a risk-based 21
approach for decision making and quantifying wildfire risk 22
throughout the Company’s service area. 23

7 Case No. IPC-E-22-27, Order No. 35717, pp. 8-9 (Mar 23, 2023).
COLBURN, DI 26
Idaho Power Company
• Situational awareness: Informing Company 1
operations and practices by incorporating new methods of 2
visual, geographical, and contextual awareness of the 3
environments in which Idaho Power operates, specifically 4
during wildfire season. 5
• Mitigation activities: Expanding and/or enhancing 6
many of the same programs that the Company has carried out 7
over the course of its operating history to mitigate 8
wildfire risk, decrease the likelihood of ignition events, 9
and protect infrastructure from wildfire regardless of 10
where it starts. 11
• Communication: Communicating with and educating 12
customers and the public about wildfire and outage 13
preparedness. 14
• Monitoring and tracking performance: Routine 15
analysis of wildfire mitigation activities to gauge their 16
effectiveness and build continuous improvement and risk 17
reduction over time. 18
Q. How does Idaho Power ensure its WMP is 19
informed by industry best practices? 20
A. Idaho Power recognizes the importance of 21
engaging with federal, state, and local governments as an 22
integral part of deciding on and implementing wildfire 23
mitigation measures. The WMP documents specific activities 24
and forums to engage with key stakeholders to share 25
COLBURN, DI 27
Idaho Power Company
information, gain feedback, and incorporate lessons 1
learned. 2
Much of Idaho Power’s service area extends over land 3
managed by the US Bureau of Land Management (“BLM”) and the 4
US Forest Service. As such, the Company engaged with these 5
agencies in the development of the WMP and continues to 6
hold meetings and workshops with them to share information 7
and identify geographic areas and specific mitigation 8
activities that are mutually beneficial. 9
Idaho Power is also a member of the Idaho Fire 10
Board, which was initiated by the US Forest Service. 11
Membership is voluntary and currently includes the Forest 12
Service, BLM, the Federal Emergency Management Agency, 13
Idaho State Lands Department, Idaho Department of 14
Insurance, Idaho Military Division, City of Lewiston, the 15
Nature Conservancy of Idaho, and Idaho Power. This group, 16
like the efforts listed above, is also focused on sharing 17
Idaho wildfire knowledge and best practices for wildfire 18
mitigation. 19
Q. Did Idaho Power consult with other utilities 20
to develop and inform its WMP? 21
A. Yes. Peer utility engagement was crucial in 22
developing the WMP to ensure the Company’s efforts are 23
consistent with best practices and aligned with its peers 24
in the region. To inform the initial development of the 25
COLBURN, DI 28
Idaho Power Company
WMP, Idaho Power participated in multiple workshops with 1
San Diego Gas and Electric, Southern California Edison, 2
Pacific Gas and Electric, Sacramento Municipal Utility 3
District, and PacifiCorp. The Company continues to engage 4
with these utilities to learn about California’s evolving 5
practices. 6
In the Pacific Northwest, many utilities work 7
collaboratively to understand and ensure commonality of 8
their respective wildfire plans, while also accounting for 9
the variation in each utility’s unique service area. These 10
utilities include Idaho Power, Avista Utilities, Portland 11
General Electric, Rocky Mountain Power, Pacific Power, 12
Chelan County Public Utility District, Puget Sound Energy, 13
NV Energy, Bonneville Power Administration, and 14
NorthWestern Energy. 15
Q. Does Idaho Power participate in any other 16
collaborative efforts to inform and evolve its WMP? 17
A. Yes. Idaho Power is a member of both the 18
Edison Electric Institute (“EEI”) and the Western Electric 19
Institute, both of which host workshops and conferences to 20
help members discuss and compare their wildfire plans and 21
mitigation efforts. 22
Additionally, Idaho Power’s President and Chief 23
Executive Officer Lisa Grow is an active member of EEI’s 24
Electricity Subsector Coordinating Council Wildfire Working 25
COLBURN, DI 29
Idaho Power Company
Group. This working group partners with the US Department 1
of Energy and other government agencies to collectively 2
minimize wildfire threats and potential impacts nationwide. 3
These industry collaboratives continue to prove 4
valuable for sharing wildfire mitigation best practices and 5
discussing new and existing technology related to wildfire 6
mitigation. 7
Wildfire Risk Analysis & Selection of Mitigation Practices 8
Q. Was a risk-based approach used to determine 9
the type and level of wildfire mitigation needed for Idaho 10
Power’s service area? 11
A. Yes. The Company followed a risk-based 12
approach in identifying, analyzing, and selecting wildfire 13
mitigation measures. The Company has integrated the 14
practices and principles detailed in the International 15
Standard ISO 31000, Risk Management Guidelines, to manage 16
wildfire risk and meet the goals and objectives of the WMP. 17
Wildfire risk mitigation is an enterprise-wide 18
effort, and risk reduction practices are integrated into 19
normal business activities and decision making across the 20
Company - from field personnel to executive officers. 21
Q. Please describe the Company’s wildfire-based 22
risk framework. 23
COLBURN, DI 30
Idaho Power Company
A. The Company takes a structured and effective 1
approach to managing wildfire-related risk that includes 2
the following: 3
• Identify risk – Recognize new and evolving 4
threats and associated risk; 5
• Analyze – Understand new and evolving risk, 6
including likelihood and consequence and any existing 7
controls; 8
• Evaluate – Determine whether risk levels can be 9
accepted or should have additional controls in place; 10
• Mitigate – Select appropriate risk treatment; 11
• Monitor – Continually check and review to 12
determine effectiveness of mitigation practices and 13
protocols; and 14
• Communicate and consult- Communicate, educate, 15
and engage with stakeholders, customers, communities, and 16
regulators about the Company’s risk-based wildfire 17
mitigation work. 18
Q. What methodology was used to quantify 19
wildfire risk? 20
A. Idaho Power leveraged an external consultant 21
— Reax Engineering — that specializes in assessing and 22
quantifying wildfire risk to determine where wildfire risk 23
is elevated within the Company’s service area. The 24
consultant used a risk-based methodology that incorporates 25
COLBURN, DI 31
Idaho Power Company
weather modeling, wildfire spread modeling, and Monte Carlo 1
simulations, among other modeling techniques. 2
This approach to modeling wildfire risk is not 3
unique to Idaho Power. The California Public Utilities 4
Commission("CPUC”) used the same modeling approach — and 5
the same consultant — as part of its development of the 6
CPUC Fire Threat Map. Other utilities in Oregon, Idaho, 7
Nevada, and Utah have utilized similar modeling approaches 8
to identify and quantify wildfire risk. 9
Q. What calculation does the Company use to 10
determine elevated risk areas? 11
A. The Company’s wildfire consultant modeled 12
wildfire risk considering a wildfire event's probability 13
multiplied by its potential negative consequences or 14
impacts, should that event occur. Expressed as a formula: 15
Wildfire Risk = Fire Probability x Consequence 16
The first term, Fire Probability, is based on fire 17
volume (i.e., spatial integral of fire area and flame 18
length) because rapidly spreading fires are more likely to 19
escape initial containment efforts and become extended 20
fires rather than slowly developing fires. The second term, 21
Consequence, reflects the number of structures (i.e., 22
homes, businesses, and other man-made structures) that 23
could be impacted by a wildfire. 24
COLBURN, DI 32
Idaho Power Company
Q. How does this equation translate to elevated 1
risk areas? 2
A. Using the formula noted above, areas of 3
highest wildfire risk will be those in which both Fire 4
Probability and Consequence are elevated. Conversely, 5
combinations of low Fire Probability and elevated 6
Consequence (or elevated Fire Probability but low 7
Consequence) will not typically be areas with highest risk. 8
Detailed discussion of the risk formula, including 9
modeling and model inputs, is provided in Exhibit No. 5. 10
Q. What are the results of the wildfire risk 11
modeling? 12
A. Using the above methodology and risk formula, 13
Idaho Power and its consultant identified specific 14
geographic areas across its service area and transmission 15
corridors. The Company then sorted these areas into tiers —16
Yellow Risk Zones, reflecting increased risk, and Red Risk 17
Zones, reflecting highest risk. Red Risk Zones — such as 18
those in the Boise foothills and around Payette Lake in 19
McCall — were determined to have the greatest wildfire risk 20
based on the combination of Fire Probability and 21
Consequence, while Yellow Risk Zones have elevated risk but 22
may have reduced Fire Probability and/or Consequence 23
relative to Red Risk Zones. 24
COLBURN, DI 33
Idaho Power Company
These risk zones are the foundation of Idaho Power’s 1
wildfire risk mitigation strategies and are used to 2
prioritize targeted investments, vegetation management 3
work, inspection activities, and situational awareness. 4
Q. How much of the Company’s service area is in 5
elevated wildfire risk zones? 6
A. Approximately 7 percent of the Company’s 7
overhead distribution and 11 percent of transmission lines 8
are located within wildfire risk zones. These geographical 9
areas include approximately 47,000 customers. 10
Q. Does the Company visualize its elevated risk 11
areas? 12
A. Yes. Based on the wildfire risk analysis, 13
Idaho Power developed a risk map, shown below, that 14
reflects the two tiers of increased wildfire risk within 15
the Company’s service area. The map — provided on Idaho 16
Power’s website — is available publicly and accessible to 17
Public Safety Partners to educate and inform them about the 18
Company’s elevated risk areas. 19
20
21
22
23
24
25
COLBURN, DI 34
Idaho Power Company
FIGURE 6 1
IDAHO POWER WILDFIRE RISK MAP 2
3
4
5 Q. How have these wildfire risk zones informed 6
the Company’s wildfire mitigation projects? 7
A. The Company’s wildfire mitigation activities 8
are specifically targeted at reducing wildfire risk in 9
elevated risk areas, with Red Risk Zones given priority due 10
to the increased level of risk associated with higher fire 11
probability and potential impact to structures. 12
Q. What types of mitigation activities is the 13
Company pursuing? 14
A. Based on the risk identified in the 15
Company’s risk assessment, Idaho Power developed and 16
COLBURN, DI 35
Idaho Power Company
grouped its wildfire mitigation work into the following 1
categories: A) quantifying wildland fire risk; B) 2
situational awareness; C) mitigation associated with field 3
personnel practices; D) mitigation activities within Idaho 4
Power’s T&D programs; E) enhanced vegetation management; F) 5
communication; and G) information technology. Idaho Power’s 6
specific activities in these categories, as well as actual 7
2022 O&M and capital expenditures, are described in the 8
sections below. 9
Wildfire Mitigation O&M Expense 10
Q. Please describe Idaho Power’s system O&M 11
expenses for wildfire mitigation in 2022. 12
A. The table below summarizes Idaho Power’s total 13
systemwide O&M expenses by wildfire mitigation category for 14
2022: 15
TABLE 1 16
WILDFIRE MITIGATION O&M IN 2022 17
Wildfire Mitigation Category Program Activity 2022 Actuals
Wildland Fire Risk Analysis and Map Updates
Situational Awareness
Weather Forecasting - System
Development, Support, and
Mitigation - Field Personnel Practices
Tools/Equipment
COLBURN, DI 36
Idaho Power Company
Mitigation -
Distribution Programs
O&M Component of Capital Work
$898,966
Annual O&M T&D Patrol Maintenance Repairs
Environmental Management
Practices
T&D Thermography Inspection Mitigation & Personnel
Transmission Wood Pole Fire
Resistant Wraps - Red Risk
Resistant Wraps - Yellow Risk
Enhanced Vegetation Management
Transition to/Maintain 3-Year Vegetation Management Cycle
$25,151,422
Enhanced Practices for
Distribution Red & Yellow Risk Zones (Pre-Season
Patrols/Mitigation, Pole
Communications
Wildfire/Wildfire Mitigation Communications -
Education/Communication -
Advertisements, Bill
Information Technology
Communication/Alert Tool
development (System set up, outage maps, critical
1
O&M: Quantifying Wildfire Risk 2
Q. Why did the Company choose to use a consultant 3
to quantify wildfire risk in its service area? 4
COLBURN, DI 37
Idaho Power Company
A. The Company selected Reax Engineering for its 1
recognized expertise in wildfire risk modeling and fire 2
science. Hiring an outside consultant helped ensure Idaho 3
Power’s risk analysis would be developed in a manner 4
consistent with and comparable to peer utilities. 5
Q. Was it prudent for the Company to hire an 6
external consultant to develop the wildfire risk analysis? 7
A. Yes. Hiring an external consultant was a 8
prudent Company decision for two reasons. First, it was 9
more cost effective than hiring additional internal 10
resources with specialized experience in wildland fire 11
behavioral modeling. Second, hiring a nationally recognized 12
consultant provides confidence that the Company’s risk 13
areas — the basis for all its wildfire mitigation work—were 14
determined using the best and latest wildfire modeling 15
techniques. 16
Q. How much did the Company spend to quantify 17
wildfire risk in 2022? 18
A. The Company’s wildfire risk analysis was first 19
conducted in 2020. Every two years the Company intends to 20
work with Reax Engineering to refine the risk analysis, 21
adjust as warranted, and update its risk maps. In 2022, the 22
Company spent $4,125 on external consultant activities to 23
update and refine its wildfire risk map. 24
// 25
COLBURN, DI 38
Idaho Power Company
O&M: Situational Awareness 1
Q. What efforts and activities did the Company 2
conduct in 2022 to enhance situational awareness during 3
wildfire season? 4
A. The Company’s situational awareness activities 5
in 2022 included refining its weather forecasting tools, 6
installing weather stations, training new personnel to 7
assist in the development and analysis of fire-season 8
weather forecasts, and initial efforts to install wildfire 9
detection cameras. Each of these activities is described in 10
more detail below. 11
Q. How much did Idaho Power’s situational 12
awareness efforts cost in 2022? 13
A. The Company spent $156,201 on situational 14
awareness in 2022. 15
Q. What is the Fire Potential Index (“FPI”) and 16
how does it reduce wildfire risk? 17
A. An essential component of Idaho Power’s fire 18
season work involves enhancing situational awareness by 19
forecasting the FPI. This tool, which forecasts a wildfire 20
risk level on a daily basis during fire season, supports 21
operational decision-making to reduce wildfire threats and 22
risks. For example, on days with a high FPI, automatic 23
reclosing device settings are adjusted and field personnel 24
modify work activities in Red Risk Zones. 25
COLBURN, DI 39
Idaho Power Company
The FPI tool accounts for weather, prevalence of 1
fuel (i.e., trees, shrubs, grasses), and topography, and 2
converts that data into an easily understood forecast of 3
the short-term fire threat for different geographic regions 4
in Idaho Power’s service area. Additionally, the tool is 5
used to help determine when a PSPS may be necessary in 6
Idaho Power’s service area. 7
The benefits of developing the FPI and enhancing the 8
Company’s meteorological forecasting capabilities is 9
greater situational awareness of Idaho Power’s system 10
during critical peak summer months. 11
Q. How has Idaho Power enhanced its ability to 12
forecast weather and fire conditions during wildfire 13
season? 14
A. The Company has expanded and enhanced 15
situational awareness by incorporating a new weather 16
forecasting system that leverages an ensemble of weather 17
models to improve accuracy and reduce forecast-to-forecast 18
variability. The ensemble approach also provides a measure 19
of certainty to better inform up-to-the-minute decision-20
making for the FPI and PSPS events. As such, the new system 21
provides greater confidence in severe weather conditions 22
and will allow Idaho Power to provide early PSPS 23
notification to Public Safety Partners, operators of 24
critical facilities, and affected customers. Additional 25
COLBURN, DI 40
Idaho Power Company
personnel were leveraged to assist in the development and 1
launch of this ensemble tool. 2
O&M: Field Personnel Practices 3
Q. Please describe the Company’s wildfire 4
mitigation efforts related to field personnel and 5
associated spending in 2022. 6
A. In 2022, the Company trained its personnel in 7
fire season conditions, practices, and operational 8
modifications. The Company equipped its field crews with 9
fire prevention tools and leveraged field observers to 10
assess on-the-ground conditions. 11
In total, the Company spent $10,720 on mitigation 12
efforts related to field personnel in 2022. 13
Q. Why are field personnel practices vital to 14
wildfire risk reduction? 15
A. Idaho Power’s field personnel and contractors 16
work across the Company’s service area, including in 17
elevated risk areas. During wildfire season, the basic 18
work, routines, preparatory activities, and preparedness of 19
employees and contractors is paramount to minimizing the 20
risk of ignition events. 21
Q. What field practices did Idaho Power establish 22
for its employees and contractors during wildfire season? 23
A. Idaho Power developed a Wildland Fire 24
Preparedness and Prevention Plan to provide guidance to 25
COLBURN, DI 41
Idaho Power Company
Idaho Power employees and contractors specifically for 1
operating during wildfire season. The plan includes 2
information regarding fire season tools and equipment 3
available on the job site; daily situational awareness 4
relative to areas with heightened fire conditions; expected 5
actions and mechanisms for reducing on-the-job wildfire 6
risk as well as reporting requirements in the event of an 7
ignition; and training and compliance requirements. 8
All Idaho Power crews, and certain field personnel 9
and contractors, performing work on or near Company 10
facilities are required to operate in accordance with the 11
provisions of the Wildland Fire Preparedness and Prevention 12
Plan and expected to conduct themselves in a fire-safe 13
manner. They are also equipped for potential wildfire 14
events by carrying specific tools, including, but not 15
limited to, shovels, Pulaskis, and water for initial 16
suppression. 17
Q. What is the role of field observers during 18
wildfire season? 19
A. In its benchmarking with other utilities, 20
Idaho Power found that most utilities use field observers 21
in some capacity as part of the de-energization decision-22
making process. The Company currently has 24 trained field 23
observers made up of Line Operations Technicians, 24
Distribution Designers, Patrolmen, and other technician 25
COLBURN, DI 42
Idaho Power Company
roles. In 2022, a PSPS event in Pocatello, Idaho was not 1
executed due to reports from field observers that rain had 2
preceded high winds. This information was not immediately 3
evident through weather stations nor available radar at the 4
time. This situation highlighted the importance of having 5
field observers equipped with mobile weather kits to inform 6
de-energization decision making. 7
O&M: Mitigation Efforts in the Company’s T&D Programs 8
Q. Please summarize Idaho Power’s mitigation 9
activities within its T&D programs and associated O&M 10
spending in 2022. 11
A. Executing the Company’s WMP relies on 12
leveraging its asset management programs to maintain safe 13
and reliable operation of T&D facilities. Specific to 14
wildfire mitigation, these efforts include: performing 15
visual and infrared thermography inspections, performing 16
maintenance based on the findings of those inspections, and 17
utilizing innovative and cost-effective approaches to 18
reduce wildfire risk, such as wrapping wood poles with a 19
fire-resistant mesh and evaluating the cost effectiveness 20
of covered conductor for potential future implementation. 21
In 2022, the Company spent $898,966 on T&D program-22
related wildfire mitigation efforts. 23
Q. What are the notable wildfire mitigation 24
expenses associated with Idaho Power’s T&D programs? 25
COLBURN, DI 43
Idaho Power Company
A. The largest wildfire mitigation expense in the 1
Company’s T&D mitigation programs is the installation of 2
fire-resistant mesh wraps. In 2022, Idaho Power spent 3
$364,075 — or 40 percent of the total system actuals in the 4
T&D mitigation category — on fire-resistant mesh wraps. The 5
mesh, which is applied to wood transmission poles in Red 6
and Yellow Risk Zones, is an effective and widely used tool 7
to increase the resilience of the pole and improve 8
reliability for customers. 9
Q. What other T&D program activities did the 10
Company pursue in 2022 to reduce wildfire risk? 11
A. In addition to the installation of fire-12
resistant mesh wraps, the Company conducted work associated 13
with a new Program Manager function, conducted more annual 14
inspections of its facilities in elevated risk zones, 15
expanded the use of infrared thermography inspections in 16
Red Risk Zones, launched a covered conductor pilot program, 17
and performed a variety of capital projects for which there 18
was an O&M component. Specific capital projects are 19
described in detail in the section below. 20
Q. Please describe the value and purpose of 21
thermography inspections with respect to wildfire 22
mitigation. 23
A. Infrared thermography inspections are 24
conducted using hand-held and drone-mounted cameras with 25
COLBURN, DI 44
Idaho Power Company
thermal-sensing technology and can help identify defects 1
associated with the overheating of equipment, connections, 2
splices, or conductors. 3
Thermography inspections are uniquely valuable in 4
that they can uncover problems undetectable to the naked 5
eye. From the Company’s perspective, there is not a viable 6
alternative to this practice. The technology enables more 7
proactive identification of potential issues than would 8
otherwise be possible. 9
In 2022, the Company used additional personnel to 10
evaluate the annual use of thermography inspections in Red 11
Risk Zones, as opposed to the Company’s historical approach 12
of periodic use of the technology across its system. 13
Q. Please explain the purpose of the covered 14
conductor pilot program. 15
A. In 2022, Idaho Power began a pilot of covered 16
conductor that will run through 2024 to explore the 17
benefits, tooling requirements for field personnel, and 18
design parameters associated with this potential mitigation 19
practice. While covered conductor may reduce the risk of 20
wildfire, the Company will analyze any other potential 21
concerns or co-benefits, including improved reliability 22
outside of wildfire season, other safety considerations, 23
and reduced outage restoration costs. Upon completion of 24
the pilot, the Company will determine whether installation 25
COLBURN, DI 45
Idaho Power Company
of covered conductor is a cost-effective risk mitigation 1
practice. 2
O&M: Enhanced Vegetation Management 3
Q. What is vegetation management? 4
A. Vegetation management is the practice of 5
trimming or pruning vegetation away from the Company’s 6
facilities to reduce the likelihood of vegetation coming 7
into contact with T&D lines and causing damage or an 8
outage. 9
Idaho Power has more than 400,000 trees within its 10
system that are inspected and pruned on an ongoing basis. 11
The lines are inspected periodically, and trees and 12
vegetation are cleared from the line while other trees are 13
removed entirely. 14
Q. Why is vegetation management a key part of 15
the Company’s wildfire mitigation efforts? 16
A. In terms of time, expense, and overall risk 17
reduction, enhanced vegetation management is the most 18
critical aspect of executing Idaho Power’s WMP. If 19
vegetation comes in contact with energized powerlines there 20
is potential that it could result in an outage or ignition. 21
Historical outage data from across Idaho Power’s service 22
area shows that vegetation contact is one of the most 23
likely sources of faults and possible ignition on the power 24
system. 25
COLBURN, DI 46
Idaho Power Company
Q. What strategies has the Company employed to 1
reduce wildfire risk associated with vegetation? 2
A. Idaho Power employs an enhanced vegetation 3
management strategy in wildfire risk zones that includes 4
transitioning to a sustainable three-year pruning cycle for 5
all distribution circuits and transmission lines in valley 6
locations. In addition to achieving a three-year pruning 7
cycle, the Company conducts mid-cycle patrols and pruning 8
in the second year of the cycle to address “cycle buster” 9
trees and annual “hotspot” patrols to address any new 10
hazard trees or unexpected vegetative growth that poses an 11
immediate threat of contact with energized facilities. 12
Additionally, the Company strives to complete audits 13
for all pruning work performed in wildfire risk zones, 14
regardless of reason for the pruning. The audits confirm 15
that pruning cuts meet the specification and that the 16
proper clearance (i.e., the distance between vegetation and 17
the Company’s T&D lines) was obtained. 18
Q. When developing the WMP, did the Company 19
consider different pruning cycle lengths? 20
A. Yes. The Company considered other vegetation 21
management cycle alternatives, including shorter trimming 22
cycles, longer trimming cycles, and strategies that 23
evaluate each tree individually and only trim it once it 24
has nearly grown back to the power line (known as “just-in-25
COLBURN, DI 47
Idaho Power Company
time trimming”). Each alternative presented challenges or 1
resulted in negative impacts that undermined any potential 2
benefits. While shorter trimming cycles result in less 3
vegetation being removed during each trimming cycle, this 4
practice costs more due to the need for more resources and 5
more frequent trimming of trees near the power lines. 6
In contrast, longer cycles result in less frequent 7
trimming of each tree but larger amounts of vegetation that 8
must be removed to maintain larger clearance envelopes 9
around the power lines to accommodate additional years of 10
vegetative growth. Further, longer trimming cycles create 11
logistical challenges that are exacerbated by tree biology. 12
Some trees simply grow faster than a given trimming cycle 13
and the longer the trimming cycle, the more pervasive this 14
issue becomes. Longer cycles that call for heavy pruning 15
also lead to hormonal imbalances between a tree’s canopy 16
and its root system. To correct this imbalance, the tree 17
aggressively re-grows new sprouts to quickly replace its 18
lost canopy. In this regard, heavier pruning results in a 19
faster rate of tree regrowth than normal, making it even 20
more difficult to consistently maintain longer trimming 21
cycles. 22
Finally, “just-in-time trimming” is primarily a 23
reactive strategy that ultimately leads to challenges 24
associated with securing qualified tree-trimming crews, as 25
COLBURN, DI 48
Idaho Power Company
this ad hoc approach involves hiring crews on an as-needed 1
basis rather than on a consistent schedule. 2
After evaluating these alternative approaches, Idaho 3
Power concluded that maintaining a three-year trimming 4
cycle is the most cost-effective and sustainable strategy 5
to keep vegetation away from power lines in a proactive 6
manner. 7
Q. How has shifting to a three-year cycle and 8
implementing other enhanced vegetation management 9
activities affected costs? 10
A. Moving to a three-year vegetation management 11
cycle and performing enhanced vegetation activities —12
including pre-season patrols, additional inspections, pole 13
clearing, tree and shrub removal, and quality assurance in 14
Red and Yellow Risk Zones — has resulted in a sizeable 15
increase in O&M expenditure. In 2022, Idaho Power spent 16
$25,151,422 on vegetation management — more than double the 17
$10.7 million of vegetation management expense in 2019 — 18
and representing the single largest source of the Company’s 19
wildfire-related expenditure. The Company’s second largest 20
source of wildfire-related expenditure is insurance, which 21
is addressed in Mr. Buckham’s testimony. 22
Q. Why has the Company experienced such 23
substantial growth in the cost of vegetation management? 24
COLBURN, DI 49
Idaho Power Company
A. A variety of factors help explain the cost 1
increases Idaho Power has experienced to perform vegetation 2
management. Most notably, the availability of qualified 3
labor has diminished while demand for vegetation management 4
services has grown across the western US among other 5
utilities, other industries, and government agencies that 6
also recognize vegetation management is a critical 7
component of wildfire risk mitigation. 8
Importantly, the vegetation management companies 9
hired by Idaho Power and other utilities are not simple 10
arborists or landscapers. Rather, vegetation management 11
companies qualified to work near electrical lines and 12
equipment require special certifications and training. The 13
limited number of companies offering such qualified 14
services are in high demand in many western states and 15
especially in California, where labor rates are higher for 16
the work itself and the labor that provides it. Idaho Power 17
has felt the effect of out-of-state competition in the form 18
of double-digit cost increases and qualified labor 19
shortages. 20
Another exacerbating factor of vegetation management 21
cost is Idaho's growth. Greater population density and 22
expansion of homes into more vegetation-dense areas has 23
made it harder to maintain a consistent vegetation 24
management cycle. New development is routinely built with 25
COLBURN, DI 50
Idaho Power Company
frontage trees and other vegetation. The growth in newly 1
planted trees certainly leads to more work, but an 2
associated problem is that these trees are often 3
inappropriate for their location and environment. Trees 4
that grow wide and tall and/or mature quickly are poor 5
candidates for planting near or beneath electrical lines, 6
and yet tree selection is more often made based on 7
aesthetics rather than safety. This problem persists 8
despite Idaho Power making significant efforts to 9
communicate and educate on appropriate tree selection in 10
several ways, including the "Right Tree, Right Place" tree 11
planting guide, which offers detailed information on 12
selecting appropriate trees and planting them at safe 13
distances from power lines. 14
Finally, climate change is a factor contributing to 15
escalating vegetation management costs. ln recent years, 16
Idaho has experienced wetter springs followed by more 17
temperate summers and falls, leading to longer vegetation 18
growing seasons. 19
Another climate-related issue is the spread of pests 20
such as the bark beetle that leave dead trees in their 21
wake. Failure to remove dead or dying vegetation - a 22
problem felt most acutely on government land - complicates 23
vegetation management work and makes adhering to a routine 24
COLBURN, DI 51
Idaho Power Company
clearing cycle more challenging, time consuming, and, 1
thereby, more costly. 2
Q. Has the Company explored any alternatives to 3
vegetation management? 4
A. Yes. The primary alternative to vegetation 5
management is converting overhead distribution circuits to 6
underground. However, undergrounding is consistently more 7
expensive than enhanced vegetation management. The Company 8
continues to evaluate and implement underground solutions, 9
as appropriate and cost-effective based on risk, as part of 10
its WMP hardening efforts, as described in the section 11
below. 12
Q. Has the Company identified benefits other than 13
risk reduction from enhanced vegetation management 14
practices? 15
A. Yes. Although vegetation management is a 16
sizeable increased wildfire mitigation expense, performing 17
this work is expected to have notable co-benefits, 18
including reduced vegetation-caused outages, thereby 19
enhanced reliability, in Red and Yellow Risk Zones. Idaho 20
Power plans to monitor performance and outage metrics to 21
confirm the success of the enhanced program. Decreasing 22
vegetation outages was considered one of the most 23
important, cost-effective measures Idaho Power could take 24
COLBURN, DI 52
Idaho Power Company
to reduce the likelihood of an ignition event and protect 1
utility infrastructure. 2
Q. Is Idaho Power’s enhanced vegetation 3
management program prudent and in customers’ best interest? 4
A. Yes. Shifting to enhanced vegetation 5
management practices, including the move to a three-year 6
pruning cycle, was deemed a prudent course of action based 7
on the reduction of risk in wildfire risk zones and the 8
number of potential outages or ignition sources that may be 9
eliminated. A vegetation management-focused wildfire 10
mitigation program is also the approach adopted by many of 11
Idaho Power’s peer utilities. 12
Q. Has the Company evaluated new technology to 13
help in vegetation management efforts and reduce 14
vegetation-related risks? 15
A. Yes. Vegetation monitoring tools have come to 16
market in recent years that have the potential to help 17
Idaho Power apply a more targeted approach to vegetation 18
management. The Company conducted a pilot effort in 2022 19
that involved combining artificial intelligence (“AI”) with 20
satellite and aerial imagery surveys of overhead powerlines 21
to detect vegetation encroachment and hazard trees. 22
The surveys have the potential to identify problem 23
areas more quickly than conventional methods and provide 24
less reliance on “eyes on the ground” to identify areas at 25
COLBURN, DI 53
Idaho Power Company
risk of vegetation contact or trees in poor health that may 1
fall into powerlines. In addition, the technology has the 2
potential to allow Idaho Power to invest resources where 3
they will be the most effective in mitigating the impact of 4
wildfires. 5
Q. What were the results of the pilot? 6
A. Initial results of the pilot did not 7
demonstrate sufficient accuracy needed to make risk-8
informed decisions for vegetation encroachment. 9
Q. Will the pilot shift Idaho Power’s approach to 10
vegetation management? 11
A. Perhaps. The Company plans to reassess the 12
technology in 3 to 5 years as improvements in machine 13
learning and AI are made. 14
Q. What is Idaho Power’s assessment of the need 15
for ongoing enhanced vegetation management? 16
A. Based on comparison to underground conversions 17
and the insufficiency of current technology to allow a more 18
targeted approach to vegetation management, Idaho Power 19
considers its strategy of achieving and maintaining a 20
three-year pruning cycling, along with enhanced practices 21
in Red and Yellow Risk Zones, the most prudent approach for 22
reducing wildfire risk associated with vegetation. 23
Considering the challenges noted above, the Company 24
expects vegetation management expense may continue to rise. 25
COLBURN, DI 54
Idaho Power Company
A discussion of this concern, and the associated 1
justification for ongoing vegetation management cost 2
deferral at a new baseline level, is provided in the Direct 3
Testimony of Company Witness Mr. Timothy Tatum. 4
O&M: Communications & Information Technology 5
Q. Please explain the Company’s communication and 6
information technology-related strategies in the WMP. 7
A. The Company conducts several education 8
campaigns around wildfire each year, including promoting 9
the Company’s wildfire mitigation activities and work 10
within communities, providing awareness and education on 11
how to prepare for wildfire season. The following core 12
messages are the foundation for all wildfire-related 13
communications each year: 14
• How customers can prepare for wildfire-related 15
outages, including where to find outage and PSPS 16
information and how to sign up for alerts and update 17
contact information; 18
• Ways customers can reduce wildfire risk; and 19
• Idaho Power’s work to protect the grid from 20
wildfire and reduce wildfire risk. 21
Idaho Power communicates with customers and the 22
public before and throughout wildfire season to inform them 23
of steps the Company is taking to reduce wildfire risk and 24
ways they can help prevent wildfires and prepare for 25
COLBURN, DI 55
Idaho Power Company
outages. Various communication mediums used to accomplish 1
this include: newsletters, news media, website content and 2
videos, social media, postcards, and paid advertising. 3
The Company also promotes ways that the public can 4
reduce the potential to ignite fires. Customers in PSPS 5
zones are targeted for expanded communication to promote an 6
awareness of PSPS and outage preparation. PSPS-focused 7
communication comes in the form of advertisements, bill 8
inserts, postcards, and other awareness raising and 9
educational campaigns. 10
Q. What efforts has the Company made to 11
directly contact customers about emergency events and 12
outages? 13
A. To help provide timely communication of 14
emergency events — specifically, PSPS — to customers, the 15
Company has implemented a communication tool called the 16
Enterprise Omnichannel Notification System (“EONS”). Having 17
advanced alerts prior to and during a PSPS is an important 18
aspect of Idaho Power’s PSPS program. A large component of 19
the EONS tool is identifying critical customers and 20
facilities that will automatically be contacted leading up 21
to, during, and after a PSPS event. 22
Q. What did the Company spend in 2022 on 23
customer communication and related information technology? 24
COLBURN, DI 56
Idaho Power Company
A. In 2022, Idaho Power spent $106,779 on 1
communications to customers and communities before, during, 2
and after wildfire season. This amount includes postcards 3
sent to all customers in PSPS zones to educate them about 4
the purpose of PSPS and how they can stay connected to the 5
Company to learn about PSPS events. 6
Implementing the EONS system, a critical tool for 7
more timely communication with customers, cost $80,531 in 8
2022. 9
Wildfire Mitigation Capital Investments 10
Q. In what capital projects has the Company 11
invested related to wildfire mitigation? 12
A. The table below summarizes wildfire 13
mitigation investments by mitigation program: 14
// 15
// 16
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COLBURN, DI 57
Idaho Power Company
TABLE 2 1
CAPITAL INVESTMENT BASED ON PLANT CLOSINGS IN 2021 AND 2022 2
3 Mitigation Program the Program Benefit Closings in 2021
Overhead Primary
Hardening Program
replacement of
hardware, equipment, and
materials, 113-line miles in Red Risk
Zones
potential of
equipment failure,
utilizing material and equipment with
less energy release and
potential of ignition, increased
Undergroundi
ng
conversion of
overhead to underground conversion in
Red Risk Zones, 1.85
miles completed in
and potential of
ignition by locating power lines
underground
Zone Overcurrent Protection Se
relocation, and expanded communication for Automatic Reclosing
overcurrent protection
segments and improve reliability for enhanced Fire Potential Index
settings and PSPS
4
Q. What is included in the Overhead Primary 5
Hardening Program? 6
A. The Overhead Distribution Hardening program 7
involves systematic replacement of hardware, equipment, and 8
COLBURN, DI 58
Idaho Power Company
materials to improve safety and reliability and reduce 1
ignition risk. The program is targeted for Red Risk Zones. 2
Enhanced measures to mitigate wildfire are: 3
Wood Pole Replacement—The Company will replace wood 4
poles if field evaluations determine that significant 5
deterioration or damage has occurred since the last 6
inspection or treatment. Furthermore, poles having wood 7
stubs/structural reinforcements are changed out pursuant to 8
current practices. 9
Spark Prevention Units—Porcelain arresters used for 10
overvoltage protection will be changed out with arresters 11
utilizing Spark Prevention Units (“SPU”). The SPU acts to 12
eliminate the potential of catastrophic failure during 13
arrester operation. 14
Fiberglass Crossarms—Replacing wood tangent and 15
dead-end crossarms with fiberglass. Fiberglass crossarms 16
provide decrease the likelihood of heating through a 17
crossarms and cross-functional benefits of lower cost, ease 18
of installation, strength, and supply availability. 19
Small Conductor—Replace copper conductor and 20
conductor smaller than #4 Aluminum Conductor Steel 21
Reinforced. 22
Porcelain Switches—All porcelain switches installed 23
in Red Risk Zones will be changed out with cutouts 24
featuring Ethylene Propylene Diene Monomer Rubber. 25
COLBURN, DI 59
Idaho Power Company
Avian Protection Coverings—Idaho Power employs 1
several different protection measures to protect wildlife 2
on existing structures, including but not limited to 3
covers, insulated conductor, diverters, perches, nesting 4
platforms, and structural modifications. 5
In addition to the enhanced hardening measures 6
mentioned above, each location is inspected to ensure 7
structures and equipment are brought up to current 8
construction standards. All existing hardware that will 9
remain in place is re-tightened, loose conductors are re-10
tensioned, and third-party pole attachments are checked for 11
proper clearances. 12
Q. Does hardening work occur on the transmission 13
system? 14
A. Yes. On the transmission side, the Company 15
evaluates upcoming transmission line construction projects-16
such as new line construction and line rebuilds with the 17
plan to use steel construction for all lines of 138 kV and 18
above. For existing wood poles, a fire-resistant mesh wrap 19
is applied to existing wood poles in designated wildfire 20
risk zones, as discussed earlier in my testimony. The mesh 21
wrap improves the resiliency of the pole and keeps it from 22
catching fire if exposed to a surface fire. 23
COLBURN, DI 60
Idaho Power Company
Q. What steps did the Company take to determine 1
what mitigation measures should be included in the 2
hardening program? 3
A. Idaho Power researched historical faults on 4
the T&D system to determine outage causes that may result 5
in potential ignition. That analysis determined that 6
tree/vegetation contact, equipment failure, loose hardware, 7
corrosion, and animal contact are among the top causes of 8
faults throughout the service area. Specific risk drivers 9
were established and identified as part of the risk 10
evaluation process. 11
In addition, the Company used the Cal Fire Powerline 12
Fire Prevention Guide to help identify equipment and 13
materials that may contribute or cause an ignition on the 14
power system. This guide, combined with the Company’s past 15
root cause analysis and feedback from employees with line 16
construction and maintenance experience, helped identify 17
expulsion fuses, porcelain switches, deteriorated wood 18
crossarms, expulsion arresters, and small conductor as 19
being potential ignition sources. 20
Q. Does the hardening program offer any co-21
benefits for customers? 22
A. Yes. The Overhead Distribution Hardening 23
program includes infrastructure upgrades and the 24
replacement of several materials or equipment to reduce the 25
COLBURN, DI 61
Idaho Power Company
likelihood of ignition on the distribution system. Each 1
material or equipment selected was analyzed to determine 2
its effectiveness at reducing risk, estimated near-term 3
cost, potential co-benefits of the activity to Idaho Power 4
and its customers, and costs between alternatives. At a 5
foundational level, the program offers the co-benefit of 6
improved reliability for customers and a decrease of 7
ignition potential. 8
Q. Can reliability indices be used to measure the 9
effectiveness of the hardening program? 10
A. Yes. Prior to developing the WMP, Idaho Power 11
successfully implemented distribution hardening measures 12
and, through outage data and analytics over that period 13
(2010 through 2019), learned that customer outages were 14
reduced by approximately 38 percent in areas where 15
reliability hardening projects were carried out. This 16
initial success of reducing outages for reliability 17
purposes resulted in the Company selecting similar 18
activities in the WMP to further increase reliability and 19
help reduce ignition potential in Red Risk Zones. Idaho 20
Power is tracking reliability performance in wildfire risk 21
zones over time to assess effectiveness. 22
Q. What is the Strategic Undergrounding Program? 23
A. As part of Idaho Power’s effort to reduce 24
wildfire risk and impacts associated with outages and PSPS, 25
COLBURN, DI 62
Idaho Power Company
Idaho Power evaluates the cost-effectiveness of overhead-1
to-underground conversion of distribution lines on a case-2
by-case basis. 3
Areas selected for conversion will have increased 4
reliability and resiliency to wildfire, and customers in 5
the area will no longer be exposed to the potential of long 6
outages associated with operational protection settings on 7
high fire potential days or PSPS. Strategic Undergrounding, 8
one effort of many the Company is taking to reduce wildfire 9
risk, is selected in highest-risk areas when the cost-10
benefit analysis shows that underground construction is 11
prudent. 12
Q. Has the Company completed any underground 13
conversion projects for wildfire mitigation? 14
A. Yes. In 2022, overhead-to-underground 15
conversion was performed on 1.85 miles of distribution 16
lines in Idaho. The projects included four line segments on 17
the Boise Bench and Cartwright feeders in Boise, Idaho. 18
These were the first underground conversion projects that 19
the Company has undertaken to reduce wildfire risk. 20
Q. Why were the locations selected for 21
underground conversion? 22
A. The areas were chosen for underground 23
conversion due to the results of risk quantification and 24
work, summarized later in my testimony. That work 25
COLBURN, DI 63
Idaho Power Company
identified the areas having a combination of high wildfire 1
probability and impacts to structures. 2
Field assessments and feedback from local fire 3
officials confirmed that the topography and surface fuels 4
in the areas were conducive to rapid fire spread, which 5
could lead to structure and human safety impacts. 6
Fire history was another factor considered for the 7
project near Idaho Power’s Boise Bench Substation, located 8
off Amity Road in East Boise. Another consideration was 9
that the undergrounding of these line segments would 10
decrease the overall risk profile of each feeder due to 11
most of the feeders already having underground 12
distribution. 13
Q. What criteria did the Company use to select 14
the underground conversion projects? 15
A. The Overhead Distribution Hardening program is 16
the primary program used to decrease the likelihood of 17
ignition on the distribution system. Underground conversion 18
projects are undertaken for locations where outage data and 19
risk assessments show the need for increased risk reduction 20
beyond what the hardening program provides. 21
Idaho Power’s approach to selecting underground 22
conversion projects involves the ISO 31000 risk management 23
framework. Established criteria used in the assessment for 24
optimal underground conversion locations is as follows: 25
COLBURN, DI 64
Idaho Power Company
• Wildfire risk modeling scores, having high 1
wildfire probability and impacts to structures; 2
• Fire history where distribution overhead circuits 3
may be susceptible to repeat wildfire events over their 4
lifetime; 5
• Areas having a high likelihood of ignition due to 6
risk drivers such as vegetation contact, contact from 7
objects, lightning, and equipment failure; 8
• PSPS zones having high likelihood of proactive 9
de-energization due to historic weather patterns, 10
vegetation, or ignition risk; 11
• Areas of high wildfire risk that present 12
challenges to patrol due to access issues, terrain, or 13
inability to perform aerial inspections after a PSPS or 14
outages on days with high FPI; and 15
• Areas where PSPS and enhanced protection settings 16
may impact critical infrastructure. 17
The underground conversion projects in 2022 were 18
analyzed by their expected risk-reduction benefit to 19
overall project cost. And, for the projects in question, 20
underground conversion was deemed cost-effective based on 21
the level of risk reduction and type of risk driver that 22
was mitigated. 23
Q. How do the costs of overhead distribution 24
hardening compare to underground conversions? 25
COLBURN, DI 65
Idaho Power Company
A. The cost of converting overhead distribution 1
lines to underground can vary significantly based on the 2
voltage level, equipment, and terrain to be worked. The 3
2022 underground conversion projects cost $1,822,482 — or an 4
average cost of $985,125 per line mile. The benefit of the 5
projects are increased wildfire resiliency and decreased 6
potential of ignition. Based on wildfire modeling and 7
property values8 in the area, Idaho Power estimates that the 8
project is protecting structures that could cost upwards of 9
$45 million to replace in the event of a destructive 10
wildfire. 11
Q. What is the Overcurrent Protection 12
Segmentation program? 13
A. The Overcurrent Protection Segmentation 14
program involves the installation of automatic reclosing 15
equipment (“reclosers”) at the edge of Red Risk and PSPS 16
zones. By strategically locating reclosers at the edge of a 17
zone, the Company can limit the impact on customers outside 18
of those zones from increased outages due to enhanced 19
protection settings on days with high fire potential and 20
PSPS. The program also includes adding communication 21
capabilities to recloser so they can be remotely operated 22
through the Company’s dispatch group. The remote operation 23

8 2022 median home prices as reported by the Ada County Assessor’s Office.
COLBURN, DI 66
Idaho Power Company
provides the benefit of being able to change protection 1
settings remotely on days when the FPI is high. It also 2
gives Reliability Engineers the ability to assess waveforms 3
and fault characteristics immediately after a fault occurs, 4
eliminating the need for a technician to travel and 5
download the event record. 6
2022 WMP Performance 7
Q. What metrics is the Company tracking to gauge 8
the effectiveness of the WMP? 9
A. Idaho Power tracks several metrics to measure 10
the performance of the WMP and its effectiveness over time. 11
Each year, work plans are established at the beginning of 12
the year and items are tracked throughout the year to 13
identify areas needing corrective action or attention. This 14
includes monitoring vegetation management activities, 15
inspections, and circuit hardening. Idaho Power’s goal is 16
to complete 100 percent of the work plan each year; 17
however, emergencies or other unplanned events can occur 18
and disrupt the annual work plan. 19
Q. How did Idaho Power perform on its WMP 20
wildfire mitigation objectives in 2022? 21
A. As is demonstrated in the table below, the 22
Company met or exceeded its wildfire mitigation objectives 23
in 2022, in all but two instances. 24
// 25
COLBURN, DI 67
Idaho Power Company
TABLE 3 1
2022 WMP PERFORMANCE METRICS 2
3
The Company did not fully achieve its 2022 4
vegetation management production goal in the transition to 5
a three-year vegetation management cycle and, similarly, 6
fell below the goal with respect to pruning audits in high-7
risk zones. Both of these outcomes are the direct result of 8
the vegetation management challenges discussed earlier in 9
my testimony — namely, labor shortages that have made it 10
difficult to hire enough qualified crews to perform the 11
Company’s needed vegetation management work. 12
Q. Please summarize your testimony in this 13
case. 14
COLBURN, DI 68
Idaho Power Company
A. As evidenced by the Company’s ongoing 1
improvement in reliability metrics, Idaho Power has taken a 2
thoughtful and prudent approach to construction and 3
maintenance of its T&D systems. 4
Regarding wildfire mitigation, the Company made 5
substantial and prudent 2022 investments in programs, 6
personnel, infrastructure, system hardening, and vegetation 7
management to ensure that Idaho Power can continue to 8
safely and reliably serve customers and continue to make 9
great strides to mitigate wildfire risk. 10
Q. Does this conclude your direct testimony in 11
this case? 12
A. Yes, it does. 13
// 14
// 15
COLBURN, DI 69
Idaho Power Company
DECLARATION OF MITCH COLBURN 1
I, Mitch Colburn, declare under penalty of perjury 2
under the laws of the state of Idaho: 3
1. My name is Mitch Colburn. I am employed by 4
Idaho Power Company as the Vice President of Planning, 5
Engineering, and Construction. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony and Exhibit Nos. 4 through 5 in 8
this 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 1st day of June 2023, at Boise, Idaho. 16
17
Signed: ___________________ 18 MITCH COLBURN 19
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