20240415Wildlife Mitigation Plan.pdf

1407 W. North Temple, Suite 330 Salt Lake City, UT 84116
April 15, 2024
VIA ELECTRONIC DELIVERY
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd
Building 8 Suite 201A
Boise, ID 83714
RE: CASE NO. PAC-E-23-18
IN THE MATTER OF ROCKY MOUNTAIN POWER’S APPLICATION FOR A
DEFERRED ACCOUNTING ORDER RELATED TO INSURANCE COSTS
Attention: Commission Secretary
Pursuant to Order No. 36045 in the above referenced matter PacifiCorp d/b/a Rocky Mountain
Power hereby respectfully submits its 2024 Idaho Wildfire Mitigation Plan to the Idaho Public
Utilities Commission.
Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at [phone].
Very truly yours,
Joelle Steward
Senior Vice President, Regulation and Customer & Community Solutions
RECEIVED
Monday, April 15, 2024 11:40:59 AM
IDAHO PUBLIC
UTILITIES COMMISSION
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IDAHO WILDFIRE
MITIGATION PLAN
2024-2026

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TABLE OF CONTENTS
1. Baseline Risk Analysis .......................................................................................................................... 8
2. Inspection and Correction .............................................................................................................. 22
3. Vegetation Management .................................................................................................................. 28
4. System Hardening ............................................................................................................................. 33
5. Situational Awareness ...................................................................................................................... 38
6. System Operations ........................................................................................................................... 53
7. Field Operations And Work Practices ......................................................................................... 57
8. Public Safety Power Shutoff (PSPS) Program ............................................................................. 62
9. Public Safety Partner Coordination Strategy .............................................................................. 73
10. Wildfire Safety & Preparedness Engagement Strategy ............................................................. 77
11. Industry Collaboration ..................................................................................................................... 86
12. Plan Monitoring And Implementation .......................................................................................... 87
13. Plan Summary, Costs, And Benefits .............................................................................................. 88
Appendix A – Adherence To Requirements ........................................................................................... 94
Appendix B – Wildfire Risk Modeling Data Inputs ................................................................................ 95
Appendix C – Encroachment policy .......................................................................................................... 98

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LIST OF FIGURES
Figure 1: Rocky Mountain Power’s Baseline Risk Assessment Framework ........................................................ 8
Figure 2: Historic Ignition Risk Drivers During Fire Season ................................................................................. 11
Figure 3: Historic Ignition Risk Drivers During Non-Fire Season ....................................................................... 11
Figure 4: Overall FireSight Model for Risk Estimates ............................................................................................. 14
Figure 5: Composite Risk Consideration Wind-Driven and Fuel/Terrain-Driven Events ............................. 16
Figure 6: Inputs and Weightings for Composite Risk Calculation ....................................................................... 16
Figure 7: Comparison of Fuel/Terrain-Driven Composite Risk to Wind-Driven Composite Risk Near
Baldy Knoll, ID .................................................................................................................................................................. 17
Figure 8: Comparison of Wind-Driven Composite Risk to Fuel/Terrain Composite Risk in Goshen
Junction, ID ....................................................................................................................................................................... 17
Figure 9: Calculation of Wind-Driven and Fuel/Terrain-Driven Composite Risk ............................................ 18
Figure 10: Combined Composite Risk Score Calculation ..................................................................................... 18
Figure 11: 2024 Areas of Interest ................................................................................................................................ 19
Figure 12: High Level Program and Project Selection Process............................................................................. 20
Figure 13: Fire Threat Condition Identification ....................................................................................................... 24
Figure 14: Hazard Tree Removal ................................................................................................................................. 28
Figure 15: High-Risk Tree Removal ............................................................................................................................. 29
Figure 16: Pole Clearing Strategy ................................................................................................................................. 32
Figure 17: Pole Clearing at Pole Base ......................................................................................................................... 32
Figure 18: Covered Conductor Compared (left) to Bare Conductor (right) Images from VW Wire and
Cable Product List ........................................................................................................................................................... 34
Figure 19: Distribution Fiberglass Poles ..................................................................................................................... 36
Figure 20: Overview of Situational Awareness ......................................................................................................... 38
Figure 21: Meteorology Daily Process ........................................................................................................................ 39
Figure 22: General Weather Station Siting Methodology ...................................................................................... 42
Figure 23: Publicly Available Situational Awareness Information from a Weather Station West of Idaho
Falls, ID ............................................................................................................................................................................... 43
Figure 24: Example of FireCast Output near Spencer, ID, July 2023 ................................................................. 45
Figure 25: FireSim Output (left) and Report (right) near Spencer, ID, July 2023 ............................................ 46
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Figure 26: Fire Potential Index Scale ........................................................................................................................... 47
Figure 27: Correlation of Utility Ignitions to Modified Hot Dry Windy (MHDW) Index and Wind Gust
Percentiles to Determine Risk Levels ........................................................................................................................ 49
Figure 28: Example System Impacts Forecast ........................................................................................................... 51
Figure 29: Example of Distribution Circuit with Multiple Reclosers .................................................................. 53
Figure 30: General Fault Indicator Configuration .................................................................................................... 55
Figure 31: 2023 EFR Setting Impact ............................................................................................................................ 56
Figure 32: Line Workers Performing Work ............................................................................................................. 57
Figure 33: Rapidly Deployable Cell-on-Wheels (COW) ........................................................................................ 60
Figure 34: PSPS Overview ............................................................................................................................................. 62
Figure 35: PSPS Assessment Methodology ................................................................................................................ 63
Figure 36: Example of a Temporary CRC ................................................................................................................. 69
Figure 37: General Re-Energization Process ............................................................................................................. 69
Figure 38: Visual Depiction of Step Restoration ...................................................................................................... 70
Figure 39 : PSPS Preparedness Strategy ..................................................................................................................... 73
Figure 40: Sample YouTube Content ......................................................................................................................... 78
Figure 41: Sample Support Collateral ......................................................................................................................... 79
Figure 42: Sample Email Communication - Modified Operational Settings ....................................................... 80
Figure 43: Wildfire Mitigation Program Infographic ................................................................................................ 81
Figure 44: Sample Webpage Content - Spanish ....................................................................................................... 81
Figure 45: Wildfire Safety Webpage Content .......................................................................................................... 82
Figure 46: Public Safety Power Shutoff Webpage ................................................................................................... 83
Figure 47: Sample Email Communication .................................................................................................................. 84
Figure 48: Wildfire Communications and Outreach Plan Timeline ..................................................................... 85

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LIST OF TABLES
Table 1: Outage Causes with Possible Correlation to Ignition Potential .......................................................... 10
Table 2: Comparison of General Characteristics of Wind-Driven and Fuel/Terrain-Driven Wildfires ..... 16
Table 3: Risk Driver Mapping to Potential Mitigation Program(s) ...................................................................... 21
Table 4: Energy Release Risk Conditions ................................................................................................................... 25
Table 5: Planned Inspection Frequency ...................................................................................................................... 26
Table 6: Planned Correction Timeframes for Fire Threat Conditions in the FHCA ...................................... 27
Table 7: Normal Distribution Minimum Post-Work Vegetation Clearance Distances .................................. 29
Table 8: Transmission Minimum Vegetation Clearance (in Feet) by Line Voltage .......................................... 30
Table 9: Weather Station Build Out Plan .................................................................................................................. 42
Table 10: Additional Considerations for District Fire Risk ................................................................................... 50
Table 11: PSPS Notification Timeline for Customers ............................................................................................ 68
Table 12: Summary of PSPS Experiences ................................................................................................................... 72
Table 13: 2023 Completed Workshops and Exercises .......................................................................................... 75
Table 14: 2024 Tentative Workshop and Exercise Plan ........................................................................................ 76
Table 15: 2024 Tentative Workshop and Exercise Plan ........................................................................................ 77
Table 16: Summary of 2023 Program Results and 2024 Objectives ................................................................... 88
Table 17: Planned Incremental Capital Investment by Category ($millions) .................................................... 90
Table 18: Planned Incremental Expense by Category ($millions) ........................................................................ 90
Table 19: Co-benefit Objectives .................................................................................................................................. 92

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INTRODUCTION
Wildfire threats have been growing in the United States and Rocky Mountain Power has
developed a comprehensive plan describing its wildfire mitigation efforts. The 2024 Wildfire
Mitigation Plan (WMP) guides the mitigation strategies that are, or will be, deployed in Idaho.
These efforts are designed to reduce the risk of utility-related wildfires, and proactively mitigate
damage to Rocky Mountain Power facilities because of wildfire.

Wildfire has long been an issue of notable public concern. Electric utilities have always needed to
be concerned with the potential of a fire starting because of sparks that could be emitted from
an electrical facility, typically during a fault condition. The growth of wildfire size and intensity
have magnified these concerns. Regardless of the causes, or political debates surrounding the
issue, the reality is stark. Despite effective fire suppression agencies and increased suppression
budgets, wildfires have grown in number, size, and intensity. Increased human development in
the wildland-urban interface, the area where people (and their structures) are intermixed with,
or located near, substantial wildland vegetation has increased the probability and the costs of
wildfire damage in terms of both harm to people and property damage. A wildfire in an
undeveloped area can have ecological consequences – some positive, some negative – but a
wildfire in an undeveloped area will not typically have a direct effect on many people. A wildfire
engulfing a developed area, on the other hand, can have significant consequences for people and
property. For all these reasons, Rocky Mountain Power is committed to making long-term
investments to reduce the risk of wildfire.

The measures in this WMP describe those investments to construct, maintain and operate
electrical lines and equipment in a manner that will minimize the risk of wildfire. In evaluating
which engineering, construction, and operational strategies to deploy, Rocky Mountain Power
was guided by the following core principles:

• Systems that facilitate situational awareness and operational readiness are central to
mitigating fire risk and its impacts.
• When a fault event does occur, the impact of the event can be minimized using equipment
and personnel to shorten the duration to isolate the fault event.
• Frequency of ignition events related to electric facilities can be reduced by engineering
more resilient systems that experience fewer fault events.

A successful plan must also consider the impact on Idaho customers and Idaho communities, and
balance costs, benefits, operational impacts, and risk mitigation in the overall imperative to
provide safe, reliable, and affordable electric service.

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In 2023, Idaho wildfire mitigation strategies, included:
• Completed additional vegetation management practices on 67 circuit segments.
• Expanded situational awareness through installation of ten weather stations and
procurement of new risk modelling tools, datasets, and software.
• Implemented modified operational settings and re-energization practices.
• Launched the Public Safety Partner portal.

Rocky Mountain Power’s 2024 WMP incorporates the company’s 2023 experience as well as
feedback and recommendations from stakeholders, and communities. As a result, in 2024 the
company is forecasting an additional investment of $31.40 million in Idaho through 2026. Section
13, Plan Summary, Costs, and Benefits includes a summary of all plan elements, forecasted costs,
and anticipated benefits.

Rocky Mountain Power’s wildfire mitigation efforts in Idaho are centered on certain operating
practices, informed by ongoing wildfire risk analysis. Rocky Mountain Power has the capability to
enact specific operational protocols service territory wide, in response to situational awareness
monitoring. Situational awareness monitoring is service territory wide and year-round, directing
alternative operating practices such as advanced control systems and incremental patrols which
can lead to expedited corrections and vegetation clearing. All of these programs are designed to
target work in the areas of wildfire risk. Many wildfire mitigation efforts, especially those driven
long-term and sustained risk factors, are focused in the defined geographic area of highest wildfire
risk called the Fire High Consequence Area (FHCA), as explained in greater detail in Section 2.2.
To date, the wildfire risk assessment conducted by Rocky Mountain Power has not identified any
FHCA in Rocky Mountain Power’s Idaho service territory. Nonetheless, baseline risk analysis is
re-evaluated regularly, and Rocky Mountain Power may designate FHCA in Idaho at some point
in the future. Therefore, this plan describes FHCA programs for informational purposes.

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1. BASELINE RISK ANALYSIS
Rocky Mountain Power’s baseline risk analysis framework consists of four main components as
depicted in Figure 1 below. The framework is a cycle consisting of data collection and analysis,
risk evaluation, risk treatment, and risk monitoring and review.

Figure 1: Rocky Mountain Power’s Baseline Risk Assessment Framework
1.1 DATA COLLECTION AND ANALYSIS
Data Collection and Analysis provides enhanced data collection and analytics for incident tracking,
trend analysis and measurement of mitigation effectiveness. This capability is discussed in the
Advanced Data Analytics Tool improvements below. The following types of data are continuously
collected, organized, and analyzed to support development of risk assessment tools and
evaluation and inform Rocky Mountain Power’s understanding of the wildfire risk. Additional
details regarding the specific types of data collected can be found in Appendix C.

RISK DRIVER ANALYSIS
Rocky Mountain Power analyzes the components of risk associated with utility facilities. In
particular, an understanding of risk drivers informs specific mitigation tactics or strategies that
can be used to reduce the total amount of risk associated with utility operations. For example,
if a risk of utility-related-wildfire exists due potential equipment failure, an increase in inspections
or maintenance activities might help to mitigate the risk. If a risk exists due to potential contact
between power lines and third-party objects, installing conductor more resilient to contact with
objects might help to mitigate that particular risk.

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Risk Evaluation includes the development of tools and models to supports location-specific
risk identification to inform mitigation programs. These risk evaluation tools and models include
the delineation of geographic areas of heightened risk of wildfire designated as the Fire High
Consequence Area (FHCA), as described and shown in Section 2.2, as well as the asset-specific
risk modeling tool, FireSight, explained in Section 1.2.

Risk Treatment involves the development and implementation of mitigation programs
informed by the data analysis and risk evaluation.

Finally, Risk Monitoring and Review supports evaluation of the effectiveness of mitigation
strategies using a consistent framework and process.

The framework in Figure 1 is represented as a cycle to depict a process geared to make
continuous improvement. For example, data collection and analysis support inputs to risk
evaluation in a repeatable and transparent way to identify areas of risk. This in turn supports
development and updates to risk evaluation tools, such as mapping of the FHCA, to inform risk
mitigation programs such as Vegetation Management and asset inspections. Finally, risk is
monitored, and programs are evaluated to enable Continuous Improvement.

In determining the potential risk drivers, Rocky Mountain Power employs a data driven approach
that references certain categories of historical outage records as a proxy for risk events. Outage
data is the best available data to correlate an identifiable event on the electrical network to the
risk of a utility-related-wildfire. There is a logical physical relationship: if a fault creates a spark,
there is a risk of fire. An unplanned outage – which is when a line is unintentionally de-energized
– is most often rooted in a fault. Accordingly, outage records were organized into categories to
understand the cause of each outage with the potential for an ignition as shown in below. The
outage categories in the table align with potential correlation to an ignition.1

1 These outage categories are not the same as the outage classifications traditionally used for reliability reporting. For example, certain outage categories, such as
loss of upstream transmission supply, planned outage, or not an outage (misclassification), do not correlate to the potential for an ignition and were excluded from
the data set used for risk driver analysis.
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Table 1: Outage Causes with Possible Correlation to Ignition Potential

Rocky Mountain Power compiled an outage history from the past ten years grouped by these
ten outage categories, both inside of fire season (June 1 through October 1) and outside of fire
season. Because “wire down” events represent situations with heightened ground fuel ignition
correlation, wire down event data is also assessed. This data is overlaid in and below.

Risk Driver to cause Outages Risk Driver Description
Animals Animals make unwanted direct contact with energized assets.
Environment Exposure to environmental factors, such as contamination
Equipment Damaged Broken equipment from car hit-poles, vandalism, or other non-lightening weather- related
factors.
Equipment Failure
Failure of energized equipment due to normal deterioration and wear, such as a cross arm
that has become cracked or the incorrect operation of a recloser, circuit breaker, relay, or
switch
Lightning Outage event directly caused by lightning striking either (i) energized utility assets or (ii)
nearby vegetation or equipment that, as a result, contacts energized utility assets
Other External Interference External factors not relating to damaged equipment such as mylar balloons, hay or other
interference resulting in a potential ignition source
Not Classifiable Outage event with unknown cause or multiple potential probable causes identified
Operational Unplanned outage resulting from operations
Tree-Within Right-of-Way (ROW) Outage attributed to vegetation contact with vegetation located within the power line right-of-
way
Tree-Outside Right-of-Way (ROW) Outage attributed to vegetation contact with vegetation from outside the right-of-way
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Figure 2: Historic Ignition Risk Drivers During Fire Season

Figure 3: Historic Ignition Risk Drivers During Non-Fire Season
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The analysis of risk drivers incorporates outage data collected through the company’s normal
outage response systems. As Rocky Mountain Power’s risk modeling efforts evolve, there may
be opportunities to gather more detailed data regarding outages, which may further refine the
analysis of such data to support the modeling and correlations between outages, risk events and
ignition probabilities.
FIRE INCIDENT HISTORY
Rocky Mountain Power tracks fires potentially originating from Rocky Mountain Power
equipment, as well as other fires that impact Rocky Mountain Power’s facilities. An initial report
of a fire can be obtained through a variety of sources. It is common for an initial report to come
via a call to Rocky Mountain Power’s system operations center from an emergency response
agency or local government. Other times, Rocky Mountain Power field personnel may observe a
fire or fire damage while performing work in the field.
After receiving an initial report of a fire incident, Rocky Mountain Power records the incident in
a fire incident tracking database. Rocky Mountain Power gathers other information, as available,
to record in the database. Fields maintained in this database include fire start date and time;
location, with a latitude and longitude reference; land use in the area; fire size; suppression agency;
facility identification; voltage; associated equipment; outage information; and the suspected
initiating event. Data fields are organized to align with regulatory reporting requirements.
Information is often estimated, based on known available information. For example, a recorded
fire start time may be the time when the fire is first observed or when a report of fire is first
received; but the precise time that the fire ignited may not be known. Fields are sometimes
populated as “unknown” when there is insufficient available information. Fire incidents have been
tracked since 2020, and the data is an input to the risk model.
ASSET INFORMATION
Information on transmission and distribution equipment, including type of equipment, location,
installation date, and material is captured and used during analysis, where available.
1.2 RISK EVALUATION AND TOOLS
Rocky Mountain Power’s baseline risk evaluation process employs the general concept that risk
is the product of the likelihood of a specific risk event multiplied by the impact of the event, also
referred to as risk consequence. The likelihood, or probability, of an event is an estimate of a
particular event occurring within a given timeframe. The impact of an event is an estimate of the
effect to people and property when an event occurs. Impact can be evaluated using a variety of
factors, including considerations centered on health and safety, the environment, customer
satisfaction, system reliability, the company’s image and reputation, and financial implications.
Rocky Mountain Power uses modelling tools to evaluate both likelihood and impact.
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FIRESIGHT
To perform risk evaluation, Rocky Mountain Power strives to combine utility and public data to
analyze the components of risk associated with utility facilities in a consistent, repeatable way.
Rocky Mountain Power procured and is currently implementing FireSight, a commercially
available module in a broader software suite from Technosylva referred to as Wildfire Analyst
(WFA-E). Technosylva has provided advanced wildfire products and services to utilities
throughout the United States since 1997 and other modules in WFA-E are used by state agencies
such as the California Department of Forestry and Fire Protection (Cal Fire). With in-house fire
and data scientists, Technosylva partners with key providers in fire planning, advanced data
modeling, and wildland fire research and development to enhance the models used in their
software. Technosylva has also published studies in scientific journals and wildfire industry
publications such as Current Opinion in Environmental Health and Science 2 and International
Journal of Wildland Fire.3
FireSight specifically builds upon the quantitative risk model developed by Technosylva that
associates wildfire hazards with the location of electric overhead assets. FireSight is used to
forecast the consequence or impact of a wildfire from a given ignition point in Rocky Mountain
Power’s service territory based on the potential spread of a wildfire, should it occur. Rocky
Mountain Power chose to implement FireSight based on Technosylva’s experience with other
utilities and their partnerships with experts in wildfire risk modeling and fire data science. The
FireSight model, which is depicted in below, combines the utility asset information and data
described in Section 1.2 with public data regarding community characteristics, terrain, vegetation,
and weather information, to provide ignition risk scores at points along a circuit. Specific to this
model, Technosylva sources information on climate, historic weather conditions, terrain, fuels,
population, and the built environment (buildings and roads) from public sources. A complete list
of inputs, with source and frequency of update, is provided in Appendix C – Wildfire Risk
Modeling Data Inputs.

2 Cardil, Adrián, Santiago Monedero, Gavin Schag, Sergio de Miguel, Mario Tapia, Cathelijne R. Stoof, Carlos A. Silva, Midhun Mohan, Alba Cardil, and
Joaquin Ramirez, “Fire behavior modeling for operational decision-making.” Current Opinion in Environmental Health and Science, Volume 23. October 202

3 Cardil, Adrián, Santiago Monedero, Phillip SeLegue , Miguel Ángel Navarrete, Sergio de-Miguel, Scott Purdy, Geoff Marshall , Tim Chavez, Kristen Allison, Raúl
Quilez, Macarena Ortega, Carlos A. Silva, and Joaquin Ramirez, “Performance of operational fire spread models in California,” International Journal of Wildland Fire,
July 7, 2023, Sourced November 2, 2023
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Figure 4: Overall FireSight Model for Risk Estimates
The FireSight model has two primary parts - Risk Associated with Ignition Location (RAIL)
and Risk Associated with Value Exposure (RAVE). RAIL, depicted on the left side of Figure
4, represents the risk presented by the asset based on its characteristics, including age and
materials. RAIL assesses the risk by associating the ignition impact over an eight-hour and 24-
hour period to a specific asset. The eight-hour period is the typical period used by utilities to
model risk, but there is growing interest in 24-hour modeling risk to understand how that
changes the risk profile.4 Therefore, Rocky Mountain Power is modeling both to better
understand if there are significant differences in the results that may impact mitigation efforts.
Factors considered in RAIL calculations include:
• Surface and canopy fuels outlook in 2030, including consideration of climate change
impacts in the modeling.
• Topography.
• Wind speed and direction.
• Historical fire occurrence identifying time of data, typical weather conditions, and
duration.

4 California Office of Energy Infrastructure Safety. “Standardized Wildfire Risk Type Classifications and in Situ Wildfire Risk Assessment.” Risk Modeling Working
Group. October 11, 2023.
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Outputs from RAIL include:
• Ignition risk from overhead transmission and distribution assets.
• Potential fire characteristics: Fire size, rate of spread, potential for crown fire, flame
length.
• Population at risk.
• Number of buildings at risk.
Risk Associated with Value Exposure (RAVE), depicted on the right side of Figure 4,
assesses the characteristics of the area that is under risk of ignition. Community demographics,
geography, and the built environment influence how risky or resilient a community is to wildfire.
RAVE is independent of the asset risk calculated in RAIL and considers the risk associated with
additional factors:
• Population density.
• Socially vulnerable populations such as the elderly, people with a disability, or people at
or below the poverty level.
• Infrastructure: Major and minor road density and building density.
• Suppression difficulty: Terrain, fuels, and fire station locations all impact how quickly
firefighters can respond to a fire in the initial attack.
• Crown fire crowning acres: the amount the fire can spread through crowning in trees.
• RAVE Outputs:
• Community impacts: How vulnerable a community is to wildfire and the potential
consequences.
• Fire intensity: How a fire is expected to behave and what area may be impacted from the
point of ignition.
COMPOSITE RISK SCORE
The composite risk score is a combination of the RAIL and RAVE, and reflects three components:
• Where is the predicted impact. This is the measure of the population and buildings
if there is an ignition.
• How destructive could the fire be. This is the expected fire behavior over the
forecast fire area.
• How resilient is the community. This is affected by the difficulty of suppression and
population characteristics.
Rocky Mountain Power models and calculates separate composite risk scores for wind-driven
and fuel/terrain-driven wildfires to account for the unique characteristics of its service territory
that spans both steep forested areas as well as high desert areas. Table 2 below shows the unique
characteristics of each wildfire type modeled.

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Table 2: Comparison of General Characteristics of Wind-Driven and Fuel/Terrain -Driven Wildfires

Category Wind-Driven Wildfires Fuel/Terrain-Driven Wildfires
Locational Risk More likely in areas subject to PSPS
(Public Safety Power Shutoff)
Confined to areas of complex fuels and terrain with
difficult access
Frequency Some years have none; others several Annually during peak fire season
Event Duration 1-3 days per event Can persist several weeks or months
Outage Risk Wind-driven and somewhat predictable Difficult to predict
Consequence Immediately catastrophic May be catastrophic over time
Calculating the risk separately and then combining them into a single composite risk, as shown
in below, provides a robust risk calculation and identification of the risk driver at a location to
apply the appropriate mitigation.

Figure 5: Composite Risk Consideration Wind-Driven and Fuel/Terrain-Driven Events
Figure 6 below shows the inputs and weightings for the composite risk for wind-driven and
fuel/terrain-driven wildfires. On the left side of the table are the RAIL inputs with the selected
input for the type of wildfire, the percentile selected and the weighting for each variable. On the
right side of the table are the RAVE inputs with the weightings for each variable, there are no
percentiles for these inputs as they are relatively static values, i.e., the number of fire stations the
number of disabled people in geographic area.

Figure 6: Inputs and Weightings for Composite Risk Calculation
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The inputs and percentages above were selected based on inputs from internal subject matter
experts and reviews of other utilities risk models. A sensitivity analysis was performed on the
selected inputs and weightings to validate that the selected percentiles and weightings identified
circuits expected to be higher risk for fuels or terrain driven wildfires based on subject matter
expertise.
Figure 7 below is an example of the difference in the Fuel/Terrain-Driven and Wind-Driven
Composite Risk Score on a Rocky Mountain Power circuit. The terrain here is steeper and has
more fuels, which is reflected in an average Fuel/Terrain Driven Composite Risk score of 0.71
compared to an average Wind-Driven Composite Risk score of 0.26.

Figure 7: Comparison of Fuel/Terrain -Driven Composite Risk to Wind-Driven Composite Risk Near Baldy Knoll, ID
below is an example of the difference in the Fuel/Terrain-Driven and Wind-Driven Composite
Risk Score on a Rocky Mountain Power circuit. Here the terrain is flatter, and the Wind-Driven
Composite Risk is significantly higher than the Fuel/Terrain-Driven Composite Risk score.

Figure 8: Comparison of Wind -Driven Composite Risk to Fuel/Terrain Composite Risk in Goshen Junction, ID
As seen in and above, the composite risk scores can vary along a circuit due to changes in fuels,
terrain, build environment, assets and community demographics that affect the risk score inputs.
This variation is seen below in the change in composite risk score for a circuit segment as well
as visually in the change in color along the circuits. The composite score is calculated for each
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circuit segment using an equation that calculates a wind-driven and terrain-driven risk as shown
in below.

Figure 9: Calculation of Wind-Driven and Fuel/Terrain -Driven Composite Risk
The calculation for the combined risk score for each circuit segment is shown in Figure 10 below.
Each composite score is on a scale of 0-1.

Figure 10: Combined Composite Risk Score Calculation
The FireSight tool, together with composite and combined composite risk score methodology
described above, were leveraged to create two, parallel evaluations. First, assuming a fixed, equal
probability, the wind-driven and fuel/terrain-driven composite risk scores were calculated and
compiled to inform an evaluation of baseline wildfire risk.
FIRE HIGH CONSEQUENCE AREA (FHCA)
Rocky Mountain Power has identified areas of heighted risk of wildfire, with delineated geographic
areas referred to as the Fire High Consequence Area or “FHCA.” The FHCA sets geographic
boundaries for wildfire mitigation programs including asset management and vegetation
management discussed in Section 2.2 and Section 3.2 respectively.
Rocky Mountain Power leveraged FireSight to model risk scores for wind-driven and fuel/terrain-
driven risk on each circuit assuming a probability factor of 1 as described in the Composite Risk
Score section above to focus on the consequence of potential ignitions. Expressed as percentiles,
the FHCA reflects areas with FireSight model risk scores in the 85th-100th percentile. Based on
this approach and, specifically, the FireSight model risk scores, Rocky Mountain Power has not
identified any geographic areas in Idaho for inclusion in an FHCA.

AREAS OF INTEREST
Rocky Mountain Power continues to study other geographic areas for wildfire risk, even if
FireSight model risk scores did not warrant inclusion of such areas in the FHCA at this time. The
FireSight model risk scores reflect the reality that there is a spectrum of wildfire risk. Not
surprisingly, certain areas, such as wooded forests have more wildfire risk than other areas, such
as irrigated agricultural areas. Along those same lines, certain areas have FireSight model risk
scores which approach the scores resulting in FHCA treatment. Rocky Mountain Power will
continue to evaluate those areas, including for possible future expansion of the FHCA. To that
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end, Rocky Mountain Power has identified additional “Areas of Interest,” which reflect geographic
areas with above average FireSight model risk scores. The Areas of Interest are grouped in two
parts: Area of Interest I refers to areas with risk scores closest to the risk scores used to
demarcate the FHCA, while Area of Interest II refers to areas with risk scores lower than Area
of Interest I. Expressed as percentiles, the FHCA reflects areas with FireSight model risk scores
in the 85th-100th percentile; Area of Interest I reflects areas in the 65th-85th percentile; and Area
of Interest II reflects areas in the 45th-65th percentile. The Areas of Interest are shown in below.

Figure 11: 2024 Areas of Interest

Rocky Mountain Power plans to provide information on the risk modeling approach to the
following utilities with assets in close proximity to the Areas of Interest:
• Bonneville Power Administration
• City of Idaho Falls
• City of Soda Springs
• Fall River Rural Electric Cooperative
• Idaho Power Company
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Finally, Rocky Mountain Power also intends to continue evaluating the FHCA on an annual basis
to incorporate new data, modeling techniques, and stakeholder input. As part of that process,
Rocky Mountain Power plans to confer with state and local agencies, such as Idaho Department
of Lands, and possibly other private stakeholders, such as the Southern Idaho Timber Association.
RISK TREATMENT - PROGRAM SELECTION AND PRIORITIZATION
For the FHCA, Rocky Mountain Power applies a high-level decision-making process that aligns
with many other utilities to develop specific projects or programs, not including compliance
driven system wide programs. The high-level process, represented by Figure 12, includes four
key phases: (1) risk modeling and assessment, (2) program identification and planning, (3) project
evaluation and selection, and (4) implementation and monitoring. While not specifically shown in
the general framework, part of the process allows for a program or project to be moved back
to a previous step if needed.

Figure 12: High Level Program and Project Selection Process
Table 3 below generally maps Rocky Mountain Power’s key risk drivers to the primary programs,
demonstrating what elements impact a group or groups of risk drivers. It is important to note
that elements may not eliminate a risk driver but are designed to mitigate the risk associated
with that driver. For many risk drivers, risk is mitigated through a combination of programs and
there is not always a 1:1 relationship between a risk driver category and a mitigation program.
All elements and programs in the plan work together to collectively mitigate wildfire risk.

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Table 3: Risk Driver Mapping to Potential Mitigation Program(s)

Key Risk Driver
Significant
Contributor to
Wire Down
Events
Potential Mitigation Program Categories
Asset
Inspections
Vegetation
Management
System
Hardening
Field
Operations
System
Operations
Object Contact      
Other      
Equipment Failure      
Unknown      
Wire-to-wire contact     
Contamination    
Utility Work    
Vandalism/ Theft   
Lightning 

As program scoping identifies potential mitigations, it is designed to make sure the ignition risk
driver is addressed and considers other programs to avoid duplicate efforts.

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2. INSPECTION AND CORRECTION
Inspection and correction programs are the cornerstone of a resilient system. These programs
are tailored to identify conditions that could result in failure or potential fault scenarios. These
scenarios can arise when the infrastructure may no longer be able to operate per code or
engineered design, or may become susceptible to external factors, such as weather conditions.

Rocky Mountain Power performs inspections on a routine basis as dictated by company policies
and completes supplemental visual patrols ahead of elevated fire risk conditions (Section 6.1).
Areas classified as FCHA are subject to additional inspection program elements. At this time,
Idaho does not have FHCA, so all assets will be subject to the standard inspection program.
When an inspection is performed on an asset, inspectors use a predetermined list of condition
codes and priority levels (defined below) to describe any noteworthy observations or potential
noncompliance discovered during the inspection. Once recorded, the condition codes are used
to establish the scope of and timeline for corrective action to maintain conformance with
National Electric Safety Code (NESC) requirements and company policies. This process is
designed to correct conditions while reducing impact to normal operations.

Key terms associated with the inspection and correction programs are defined as follows:

• Visual Assurance Inspection: A brief visual inspection performed by viewing each facility
from a vantage point allowing reasonable viewing access, which is intended to identify
clearance violations, damage or defects to the transmission and distribution system, or other
potential hazards or right-of-way-encroachments that may endanger the public or adversely
affect the integrity of the electric system, including items that could potentially cause a spark.
• Detailed Inspection: A careful visual inspection accomplished by visiting each structure, as
well as inspecting spans between structures. This inspection is intended to identify potential
nonconformance with the NESC or company standards, infringement by other utilities or
individuals, defects, potential safety hazards, and deterioration of the facilities that need to be
corrected to maintain reliable and safe service.
• Sound and Bore: An inspection performed by sounding the pole to locate external and
internal decay pockets. The pole is tapped with a metal hammer to identify potential soft
spots or hollow-sounding areas. If decay is suspected, inspection holes are drilled to
determine the extent of the internal decay.
• Pole Test & Treat: An inspection of wood poles to identify decay, wear, or damage.
Inspections may include pole-sounding, inspection hole drilling, and excavation to assess the
pole condition at groundline to identify the need for any repair or replacement. When
applicable, preservative treatment is also applied as part of this inspection.
• Enhanced Inspection: A supplemental inspection performed that exceeds the
requirements of normal detailed or visual inspections; typically, a capture of infrared data.
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• Patrols: Patrols are visual inspections performed in addition to scheduled inspection cycles
during elevated fire risk conditions. Patrols can be performed prior or during significant
weather events and are usually performed prior to re-energization of lines in FHCA during
fire season. Patrolling can result in conditions being identified and corrected similar-to
scheduled inspections. More details on patrolling activities are described in Section 6.2.
• Condition: The state of an asset regarding appearance, quality, or working order that can
sometimes be used to identify potential impact to normal system operation or clearance,
which is typically identified by an inspection.
• Energy Release Risk Condition: A type of condition that, under certain circumstances,
can correlate to increase the risk of a fault event and potential release of energy at the
location of the condition.
• Condition Codes: Predetermined list of codes for use by inspectors to efficiently capture
and communicate observations and inform the scope of and timeline for potential corrective
action.
• Correction: Scope of work required to remove a condition within a specified timeframe.
• Priority Level: The level of risk assigned to the condition observed, as follows:
 Imminent – imminent risk to safety or reliability
 Priority A – risk of high potential impact to safety or reliability
 Priority B – low or moderate risk to safety or reliability
2.1 STANDARD INSPECTION AND CORRECTION PROGRAMS
Rocky Mountain Power’s asset inspection programs involve four primary types of inspections:
(1) visual assurance inspection; (2) detailed inspection, (3) sound and bore, and (4) pole test &
treat. Inspection cycles, which dictate the frequency of inspections, are set by Rocky Mountain
Power asset management department. In general, visual assurance inspections are conducted
more frequently, to quickly identify any obvious damage or defects that could affect safety or
reliability. Detailed inspections have a more comprehensive scope of work, so they are
performed less frequently than visual assurance inspections. Pole test and treat (including sound
and bore inspections) are more intrusive and in aims of finding internal decay. The frequency of
these intrusive inspections is based on the age of wood poles, and such inspections are typically
scheduled in conjunction with detailed inspections. Regardless of the inspection type, any
identified conditions are entered into Rocky Mountain Power’s facility point inspection system
database for tracking purposes. For any condition identified, the inspector conducting the
inspection will assign a condition code and the associated priority level. Corrections are then
scheduled and completed within the correction timeframes established by internal company
policies, as discussed below. While the same condition codes are used throughout Rocky
Mountain Power’s service territory, the timeframe for corrective action varies depending on
location, wildfire risk area, and if the condition has the potential to release energy. In all cases,
the timeline for corrections considers the priority level of any identified condition.
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2.2 FHCA INSPECTION AND CORRECTION PROGRAMS
The existing inspection and correction programs are effective at maintaining regulatory
compliance and managing routine operational risk. They also mitigate wildfire risk by identifying
and correcting conditions which, if uncorrected, could potentially ignite a fire. While Idaho does
not have a designated FHCA today, the enhanced FHCA programs described in this section could
be implemented in the future, should FHCA be identified in Idaho. Recognizing the growing risk
of wildfires, Rocky Mountain Power is continuing to supplement its existing programs within the
FHCA areas as defined in Section 1 to further mitigate the growing wildfire specific operational
risks and create greater resiliency against wildfires. There are three primary elements that have
been implemented: (1) creating a fire threat classification for specific condition codes which
correlate to a heightened risk of fire ignition; (2) performing inspections more often in the FHCA
and (3) expediting the correction of any fire threat conditions identified within the FHCA.
FIRE THREAT CONDITIONS
Certain conditions are classified as energy release risk conditions. As the name suggests, this
category includes conditions which, under certain circumstances, can increase the risk of a fault
event and potential release of energy at the location of the condition. Certain condition codes
are categorically designated as an energy release risk. If a condition is designated as an energy
release risk and the condition is located within the FHCA, the condition is designated as a fire
threat condition, which means that the condition is treated as a type which corresponds to a
heightened risk of fire ignition; see Figure 13.

Figure 13: Fire Threat Condition Identification

Condition codes reflecting an appreciable risk of energy release are designated as energy release
risk conditions. For example, a damaged or frayed primary conductor has a condition code
CONDFRAY, which is designated as an energy release risk condition because the condition could
eventually result in a release of energy under certain circumstances. CONDFRAY conditions
identified within the FHCA are then designated as a fire threat condition because, due to
Page | 25
escalation and environmental factors, the condition could eventually result in an ignition. In
contrast, the observation of a missing or broken guy marker would result in the condition code
GUYMARK, which is not designated as an energy release risk condition or a fire threat condition.

Table 4: Energy Release Risk Conditions

Condition Type Description
Pole Replacement
A pole identified for replacement as a result of intrusive testing or
visual inspection that does not meet strength requirements /
safety factors
Frayed or Damaged Conductor A conductor identified with damage/fraying on conductor strands
because of visual or detail inspection
Loose Connections / Bolts / Hardware
A connection, bolt, or hardware component identified that is loose
or missing from equipment or framing on the pole during visual or
detail inspections
Loose / Broken Anchors and Guys Loose or broken anchor and guying identified on the pole as a
result visual or detail inspections
Loose / Damaged Equipment Loose or damaged equipment (capacitors, regulators, reclosers,
etc.) identified on the pole during visual or detail inspections
Primary And Secondary Conductor Clearances
Primary and secondary conductor clearances from the pole,
buildings, or ground that do not meet minimum clearance
requirements specified in the NESC identified during visual or
detail inspections
Vegetation Clearances
Vegetation clearances from the pole, primary/secondary
conductor, and climbing space that do not meet minimum
clearance requirements specified in the NESC identified during
visual or detail inspections
Loose / Broken Communication Lashing Wires One or more lashing wires (Telco, CATV, Fiber) that are broken
or loose identified during visual or detail inspections
Broken / Missing Grounds Broken or missing ground on a pole or equipment identified
during visual or detail inspections.
Infrared
Components or equipment that has a temperature rise that
exceeds thresholds in company policy identified during enhanced
inspection.
Unstable Soils Soil or backfill on a pole that is unstable or insufficient identified
during visual or detail inspections.

describes the general types of energy release risk conditions designated by Rocky Mountain
Power that, if located within the FHCA, correlate to a heightened risk of fire ignition, and are
then designated fire threats.

INSPECTION FREQUENCY
Consistent with industry best practices, inspections are the company’s preferred mechanism to
identify conditions. Also consistent with industry best practices, standard inspection frequencies
are designed to identify a condition within a reasonable amount of time after the condition
emerges. In the areas of greatest wildfire risk, the FHCA, Rocky Mountain Power also believes
Page | 26
that having more frequent inspections is a good mitigation strategy because more regular
inspections should identify a certain percentage of conditions at an earlier stage than otherwise.
If conditions are identified at an earlier date, they will be corrected sooner. If a particular
condition exists for a shorter amount of time, that condition is then less likely to cause a fault
event or release energy, which could lead to a wildfire ignition. Inspection frequencies for Idaho
asset types are summarized in Table 5 under the standard inspection frequency heading.
Table 5: Planned Inspection Frequency

Inspection Type* Standard Inspection Frequency
(Years)
FHCA Inspection Frequency
(Years)
Overhead Distribution (Less than 46 kV)
Visual 2 1
Detailed 10 5
Pole Sound and Bore 10 10
Pole Test and Treat** - 10
Overhead Local Transmission (Greater than 46 kV and less than 200 kV)
Visual 2 1
Detailed 10 5
Pole Sound and Bore 10 10
Pole Test and Treat 10 10
Overhead Main Grid (Greater than 200kV)
Visual 1 1
Detailed 2 2
Pole Sound and Bore 10 10
Pole Test and Treat 10 10
* Inspections with same inspection frequency are performed at the same time.
** Treatment may not be applied if the pole is scheduled for replacement through the line rebuild program.

EXPEDITED CORRECTION TIME PERIODS
Rocky Mountain Power further mitigates wildfire risk in the areas of greatest risk by reducing
the time for correction of fire threat conditions, which by definition are located in FHCA. As
expressed above, certain types of conditions have been identified as having characteristics
associated with a heightened risk of wildfire potential. Identified violations, recorded as fire threat
conditions, are on an accelerated correction schedule within the FHCA, as they are considered
a heightened risk to safety. The accelerated timeframe reduces the correction timeframe by half
for A conditions from the 120 days to 60 days. Additionally, the conditions classified as an
Page | 27
imminent energy release risk within the FHCA are corrected immediately. Correction
timeframes for fire threat conditions in Table 6.

Table 6: Planned Correction Timeframes for Fire Threat Conditions in the FHCA

Condition Priority Correction Timeframes
A - Imminent Energy Release Risk in FHCA Immediate
A – Energy Release Risk in FHCA 60 Days
B – Energy Release Risk in FHCA 12 Months
2.3 ENHANCED INSPECTIONS
Rocky Mountain Power’s enhanced inspection programs use alternate technologies such as
infrared or drone imagery to supplement visual inspections, identify hot spots, equipment
degradation, and potentially substandard connections.
The infrared inspection program is performed on transmission lines that are interconnected with
the FHCA. The identified lines are grouped by peak loading intervals for the inspections to be
performed. The infrared data is used to identify thermal rises in equipment which could be a
potential issue not visible through other inspection programs. Drone inspections are performed
using an Unmanned Aerial Vehicle (UAV), referred to as a drone. A drone can provide enhanced
imagery, alternate perspectives, and the ability to package new technology (LiDAR, IR, detailed
imagery) to view assets and assess conditions.

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3. VEGETATION MANAGEMENT
Rocky Mountain Power’s vegetation management program is designed to reduce the potential of
vegetation contact with power lines, which reduces the potential of an ignition originating from
electrical facilities. While it is impossible to eliminate all vegetation contact, at least without
radically altering the landscape near power lines, a primary objective of the vegetation
management program is to minimize contact by addressing both grow-in and fall-in risks. Rocky
Mountain Power manages a comprehensive vegetation management program throughout Rocky
Mountain Power’s territory. All the work performed in the core program provides wildfire
mitigation, because the core program is designed to minimize the risk of vegetation contact.
Currently, Idaho does not have FHCA, so all routine vegetation management work in Idaho is
done consistent with the regular vegetation management program. In addition, Rocky Mountain
Power’s vegetation management department may perform specific incremental activities to
address wildfire risk in Idaho, when a near-term risk is identified through increased situational
awareness efforts, discussed in greater detail in Section 5.
3.1 REGULAR VEGETATION MANAGEMENT PROGRAM
Tall growing vegetation is pruned to maintain a safe distance between vegetation and power lines.
Dead, dying, diseased, or otherwise impacted trees or
vegetation, which are at an elevated risk of falling into a power
line, are removed. Like other utilities, Rocky Mountain Power
contracts with vegetation management service providers to
perform the pruning and tree removal work for both
transmission and distribution lines.
DISTRIBUTION
Vegetation near distribution facilities is pruned to maintain a
clearance between conductors and vegetation. Vegetation
work is performed on a regular cycle, which, in Idaho, is a
three-year cycle. When cycle work is planned, the circuit is
inspected to identify vegetation that needs to be pruned
because it may grow too close to power lines before the next
scheduled cycle work. When vegetation is identified for pruning,
it is pruned to achieve minimum post-work clearance distances,
designed to maintain a sufficient clearance until the next
scheduled cycle work. Tree growth rates influence the minimum post-work clearance distance.
For example, faster growing trees need a greater minimum post-work clearance to maintain
required clearance throughout the cycle. Rocky Mountain Power also integrates spatial concepts
to distinguish between side clearances, under clearances, and overhang clearances. The distances
for the minimum post-work clearances used for normal cycle maintenance are listed in Table 7.

Figure 14: Hazard Tree Removal

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Table 7: Normal Distribution Minimum Post-Work Vegetation Clearance Distances

Slow Growing
(<1 ft/yr.)
Moderate Growing
(1-3 ft/yr.)
Fast Growing
(> 3 ft./yr.)
Side Clearance 8 ft. 10 ft. 12 ft.
Under Clearance 10 ft. 12 ft. 14 ft.
Overhang Clearance 12 ft. 12 ft. 12 ft.

Rocky Mountain Power also removes high-risk trees as
part of distribution cycle work, to minimize fall-in risk.
High-risk trees are dead, dying, diseased, deformed, or
unstable trees which have a high probability of falling
and contacting a substation, distribution conductor,
transmission conductor, structure, guys, or other
electric facility. High-risk trees pose a safety and
reliability risk and are, therefore, removed. High-risk
trees are identified for removal in any vegetation
inspection. To identify high-risk trees, the inspector
applies the best management practices set forth in ANSI
A300 (Part 9).
Distribution cycle work also includes work designed
to reduce future work volumes.
Volunteer saplings, or small trees that were not
intentionally planted, are typically removed if they
could eventually grow into a power line. From a long-
term perspective, reducing unplanned vegetation
growth helps mitigate wildfire risk by eliminating a potential vegetation contact long before it
could ever occur.
TRANSMISSION
Vegetation management on transmission lines is also focused on maintaining clearances between
vegetation and electrical facilities, which vary according to the voltage of the transmission line.
At all times, Rocky Mountain Power must maintain the required minimum clearances set forth
in FAC-003-04,5 are referred to as the “Minimum Vegetation Clearance Distance” (MVCD). To

5 See Table 2 of FAC-003-04, at https://www.nerc.com/pa/Stand/Reliability%20Standards/FAC-003-4.pdf
Figure 15: High-Risk Tree Removal
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determine whether work is needed, an action threshold distance is applied, meaning that work
is required if vegetation has grown within the action threshold distance. When work is
completed, vegetation is cleared, at a minimum, to a minimum post-work clearance distance. The
applicable distances for various voltages of transmission lines are shown in Table 8.
Table 8: Transmission Minimum Vegetation Clearance (in Feet) by Line Voltage

Minimum
Clearance Type 500 kV 345 kV 230 kV 161 kV 138 kV 115 kV 69 kV 45 kV
Minimum
Vegetation
Clearance
Distance (MVCD)
8.5 5.3 5.0 3.4 2.9 2.4 1.4 N/A
Action Thresholds 18.5 15.5 15.0 13.5 13.0 12.5 10.5 5
Minimum
Clearances
Following Work
50 40 30 30 30 30 25 20

In some circumstances, when local conditions and property rights allow, Rocky Mountain Power
may use “Integrated Vegetation Management” (IVM) practices to prevent vegetation growth from
violating clearances by proactively managing the species of trees and other vegetation growing in
the right-of-way. Under such an approach, Rocky Mountain Power may remove tree species that
could potentially threaten clearance requirements, while encouraging low-growing cover
vegetation, which would never bring about clearance issues.
Main grid transmission lines are inspected annually. Other transmission lines (“local”
transmission) are inspected as needed. Vegetation work is scheduled dependent on several local
factors, consistent with industry standards and best management practices. When transmission
lines are overbuilt, meaning they are located on the same poles as distribution lines, vegetation
management work is completed on the normal distribution cycle schedule.
POST-WORK AUDITS
After work is completed on distribution cycle maintenance Rocky Mountain Power conducts
post-audits (quality control reviews) to compare completed work against required specifications.
Post-audits are conducted after the vegetation management work is completed at a location,
typically as soon as reasonably practicable to arrange for prompt corrective work if any
exceptions are identified. Rocky Mountain Power targets to perform a full post-work audit on
distribution cycle and correction work associated with the distribution annual vegetation
inspection program.
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3.2 ENHANCED VEGETATION MANAGEMENT
Vegetation management programs can be targeted to achieve long term wildfire risk reduction
or can be a rapid response to dynamic situational awareness which can occur anywhere in the
service territory and is described further in Section 3.2.
OFF-CYCLE VEGETATION INSPECTION
As discussed above, normal vegetation management work on the distribution system is
performed on a three-year cycle. In areas of elevated fire risk, however, Rocky Mountain Power
may schedule an off-cycle vegetation inspection. In the FHCA, an off-cycle vegetation inspection
is typically scheduled on an annual basis (meaning every year except those years where the circuit
is already scheduled for regular maintenance). In Idaho, outside the FHCA, an off-cycle vegetation
inspection may be scheduled as needed, typically in conjunction with other wildfire mitigation
activities (as discussed in Section 3.2). An off-cycle inspection is typically scheduled with the goal
to complete the inspection prior to the height of fire season. An off-cycle inspection is geared
to identify any high-risk trees which may have emerged since the last inspection. An inspector
conducting an annual inspection will also identify vegetation likely to exceed minimum clearance
requirements prior to the next scheduled inspection. After an annual inspection is completed,
vegetation management work is promptly completed as reasonably practicable, including removal
of any high-risk trees.
EXTENDED CLEARANCES
In the FHCA, Rocky Mountain Power uses increased minimum post-work clearance specifications
distances for any distribution cycle work in the FHCA. In summary, the minimum post-work
clearance distances applicable to the FHCA require pruning even slow-growing trees to at least
12 feet in all directions.

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POLE CLEARING
Rocky Mountain Power vegetation management performs pole clearing on subject equipment
poles located in the FHCA. Pole clearing involves removing all vegetation within a ten-foot radius
cylinder (up to eight feet vertically) of clear space around a subject pole and applying herbicides
and/or soil sterilant to prevent any vegetation regrowth (unless prohibited by law or the property
owner), as illustrated in Figure 16.

Figure 16: Pole Clearing Strategy
This strategy is distinct from the clearance and removal activities discussed above because it is
not designed to prevent contact between vegetation
and a power line. Instead, pole clearing is designed
to remove fuels at the base of equipment poles, to
reduce the risk of fire ignition if sparks are emitted
from electrical equipment. Pole clearing will be
performed on wildland vegetation in the FHCA
around poles that have fuses, air switches, clamps, or
other devices that could create sparks.

Figure 17: Pole Clearing at Pole Base
Page | 33
4. SYSTEM HARDENING
Rocky Mountain Power’s electrical infrastructure is engineered, designed, and operated in a
manner consistent with utilities best practice, enabling the delivery of safe, reliable power to all
customers. When installing new assets as a part of corrective maintenance or growth projects,
Rocky Mountain Power incorporates the latest technology and engineered solutions that have
been assessed and proven to be effective. When conditions warrant, Rocky Mountain Power
engages in strategic system hardening, like replacing or modifying existing assets and/ or utilizing
a new design or technology to make the asset more resilient. With the growing risk of wildfires,
the company supplements existing asset replacement projects with system hardening programs
designed to mitigate operational risks associated with wildfire. The areas assessed for system
hardening are usually within the FHCA as defined by the risk modeling described in Section 1,
however hardening work could also occur in response to situational awareness inputs. System
hardening work that occurs as a result of near-term risk, are typically not planned across multiple
years but are smaller projects to address a more immediate resiliency need. Currently Idaho does
not have a defined FHCA but may be updated with future iterations of the risk model.
System hardening programs are designed in reference to the equipment on the electrical network
that could be involved in the ignition of a wildfire or be subject to an existing wildfire event. In
general, system hardening programs attempt to reduce the occurrence of events involving the
emission of sparks (or other forms of heat) from electrical facilities or reduce the impact of an
existing wildfire on utility infrastructure. System hardening programs represent the greatest long-
term mitigation tool available for use by electric utilities. The phasing and prioritization of such
programs, as described in Section 4, will utilize risk modeling and assessments for program
identification which will be evaluated for implementation as a strategic hardening initiative.
No single system hardening program mitigates all wildfire risk related to all types of equipment.
Individual programs address several factors, different circumstances, and different geographic
areas. Each program described below, however, shares the common objective of reducing overall
wildfire risk associated with the design and type of equipment used to construct electrical
facilities. In prioritizing a particular design or equipment elements, these programs can also
consider environmental factors impacting the magnitude of a wildfire. Extreme weather
conditions such as dry and windy conditions, present an increased risk of wildfire ignitions and
spread. Consequently, system hardening programs may specifically attempt to reduce the
potential of an ignition event when it is dry and windy, by utilizing equipment that is less likely to
release energy if failure or contact with foreign objects occur.
It must be emphasized, however, that system hardening cannot prevent all ignitions, no matter
how much is invested in the electrical network. Equipment does not always work perfectly and,
even when manufactured and maintained properly, can fail; in addition, there are external forces
and factors impacting equipment, including from third parties and natural conditions. Therefore,
Rocky Mountain Power cannot guarantee that a spark or heat coming from equipment owned
and operated by the company will never ignite a wildfire. Instead, the system hardening efforts
Page | 34
seek to reduce the potential of an ignition associated with any electrical equipment by making
investments with targeted system hardening programs.
4.1 LINE REBUILD PROGRAM
Circuits within the FHCA and constructed with bare overhead are evaluated for potential system
hardening work. As a part of this program, certain overhead lines may either be moved, removed,
retrofitted with more resilient materials such as covered conductor or non-wooden poles, or
converted to underground. After completion of system hardening, such lines will be more
tolerant to incidental contact, thereby reducing the risk of wildfire.
COVERED CONDUCTOR
Historically, most distribution power lines in the United States – and in Rocky Mountain Power’s
service territory – were installed with bare overhead conductor. As the name “bare” suggests,
the wire surface is uninsulated and exposed to the elements. For purposes of wildfire mitigation,
covered conductor which can also be called tree wire or aerial spacer cable, has been installed
to provide an insulating layer around the conductor.
The dominant characteristic of covered conductor is manufactured with multiple high-impact
resistant extruded layers forming an insulation around stranded hard drawn conductor. The
inherent design provides insulation for the energized metal conductor. To be clear, covered
conductor is not insulated enough for people to directly handle an energized high voltage power
line (as discussed below). The
insulating layers reduce the risk of
wildfire by minimizing the potential
of vegetation or ground contact
with the conductor.
Variations in covered conductor
products have been used in the
industry for decades. Due to many
operating constraints, however, use
of covered conductor tended to be
limited to locations with extremely dense vegetation where traditional vegetation management
was not feasible or efficient. Recent technological developments have improved covered
conductor products, reducing the operating constraints historically associated with the design.
These advances have improved the durability of the product and reduced the impact of conductor
thermal constraints. There are still logistical challenges with covered conductor. The wire is
heavier, especially during heavy snow/ice loading, meaning that more and/or stronger poles may
be required to support covered conductor.
The wildfire mitigation benefits of covered conductor are significant. As discussed in the risk
assessment in Section 1, a disruption on the electrical network, a fault, can result in emission of
Figure 18: Covered Conductor Compared (left) to Bare Conductor (right) Images
from VW Wire and Cable Product List
Page | 35
a spark or heat that could be a potential source of ignition. Covered conductor reduces the
potential of many kinds of faults. For example, contact from an object is a major category of real-
world faults which can cause a spark. Whether it is a tree branch falling into a line and pushing
two phases together or a Mylar balloon carried by the wind drifting into a line, contact with
energized bare conductor can cause the emission of sparks. If those same objects contact covered
conductor, the wire is insulated enough that there are no sparks. Likewise, many equipment
failures are a wildfire risk because the equipment failure then allows a bare conductor to contact
a grounded object. Consequently, covered conductor reduces the risk of ignition associated with
most types of equipment failure. For example, if a cross arm breaks, the wire held up by the
cross arm often falls to the ground (or low and out of position, so that the wire might be
contacting vegetation on the ground or the pole itself). In those circumstances, a bare conductor
can emit sparks (or heat) that can cause an ignition. The use of covered conductor, in those exact
same circumstances, would almost certainly not lead to an ignition, because the insulation around
the wire is sufficient to prevent any sparks and limit energy flow, even when there is contact with
an object.
Covered conductor is especially well-suited to reduce the occurrence of faults linked with the
worst wildfire events. Dry and windy conditions increase the wildfire risks. Wind is the primary
driving force behind wildfire spread. At the same time, wind has distinct and negative impacts on
a power line. The wind blows objects into lines; a strong wind can cause equipment failure; and
even parallel lines slapping in the wind can cause sparks. Covered conductor specifically reduces
the potential of an ignition event, because covered conductor is especially effective at limiting the
kinds of faults that occur when it is windy. Taken together, these substantial benefits warrant the
use of covered conductor in areas with a high wildfire risk.
UNDERGROUND
Rocky Mountain Power also continues to evaluate the potential to convert overhead lines to
underground lines for the rebuild projects. The potential wildfire mitigation benefits are
undeniable. While an underground design does not eliminate every ignition potential (i.e., because
of above-ground junctions), it is the most effective design to reduce the risk of a utility-related
ignition. Currently, the cost and operational constraints of underground construction often make
it difficult to apply on a widespread basis. Nonetheless, some electric utilities are planning to
employ an underground strategy more broadly.
Currently, Rocky Mountain Power is continuing to evaluate the use of underground design as
part of the rebuild program on a project-by-project basis; and it uses under-grounding where
practical. Through the design process, every rebuild project is assessed to determine whether
sections of the rebuild should be completed with underground construction. Some communities
and landowners may prefer, for aesthetic reasons, to pursue a higher cost underground
alternative. Consistent with electric service regulations and company design standards, Rocky
Mountain Power will collaborate with communities or individual landowners who are willing to
Page | 36
pay the incremental cost and obtain the necessary legal entitlements for underground
construction.
NON-WOODEN POLES
Traditionally, overhead poles are replaced or reinforced within the service territory consistent
with the NESC, company policies, and prudent utility
practice. When a pole is identified for replacement,
typically through routine inspections and testing, major
weather events, or joint use accommodation projects, a
new pole consistent with engineering specifications
suitable for the intended use and design is installed in its
place. Engineering specifications typically reflect the use of
wooden poles which is consistent with prudent utility
practice as they are considered safe and structurally
sufficient to support overhead electrical facilities during
standard operating conditions. However, the use of
alternate non-wooden construction, such as steel or
fiberglass, can provide additional structural resilience in
high-risk locations during wildfire events and, therefore,
aid in restoration efforts. For example, as a part of covered
conductor installation, the strength of existing poles is
evaluated. In many cases, the strength of existing poles may
not be sufficient to accommodate the additional weight of
covered conductor. In these instances, the existing
wooden pole is upgraded to support the increased
strength requirements and replaced with a non-wooden
solution for added resilience.
4.2 ADVANCED SYSTEM PROTECTION AND CONTROL
Rocky Mountain Power is continuing to replace and upgrade electro-mechanical relays with
microprocessor relays. Microprocessor relays provide multiple wildfire mitigation benefits. They
can exercise programmed functions much faster than an electro-mechanical relay and, most
importantly, the faster relay limits the length and magnitude of fault events. After a fault occurs,
energy is released, posing a risk of ignition, until the fault is cleared. Reducing the duration of a
fault event reduces the risk that the fault might result in a fire.
Additionally, microprocessor relays also allow for greater customization to address
environmental conditions through a variety of settings and are better able to incorporate
complex logic to execute specific operations. These functional features allow for the company
to use more refined settings for application during periods of greater wildfire risk, to be discussed
in Section 6. As part of replacing an electro-mechanical relay, the associated circuit breaker or
Figure 19: Distribution Fiberglass Poles
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other line equipment may also be replaced, as appropriate to facilitate the functionality of a
microprocessor relay.
4.3 EXPULSION FUSE REPLACEMENT
Overhead expulsion fuses serve as one of the primary system protection devices on the overhead
system. A typical expulsion fuse has a small metal element within the fuse body that is designed
to melt when excessive current passes through the fuse body, interrupting the flow of electricity
to the downstream distribution system. Under certain conditions, the melting action and
interruption technique will expel an arc out of the bottom of the fuse tab. To reduce the potential
for ignition because of fuse operation, Rocky Mountain Power uses alternate equipment that
does not expel an arc. The company’s standards for expulsion equipment replacement are based
on Cal Fire’s Power Line Fire Prevention Field Guide (2021 Edition).
4.4 FAULT INDICATORS
As described above, Rocky Mountain Power is continuing to replace and upgrade electro-
mechanical relays with microprocessor relays to enable the use of more refined settings for
application during periods of greater wildfire risk, discussed in detail in Section 6. To supplement
these programs and mitigate the potential impacts to customers of these types of wildfire
mitigation strategies to the greatest extent possible, Rocky Mountain Power may install
communicating fault indicators across the Idaho service territory on where EFR settings are most
likely to be implemented.

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5. SITUATIONAL AWARENESS
As described in Section 1, Rocky Mountain Power uses the Fire High Consequence Area (FHCA),
the company’s baseline risk map, layered with a risk driver analysis to inform longer term strategic
investment and modifications to asset inspections and vegetation maintenance practices.
However, as climate and weather patterns change, extreme weather events are predicted to
become more frequent, and the potential exists for seasonal, dynamic, and/or isolated risk events
to occur that compound or deviate from this baseline risk. Therefore, having an additional
sophisticated, dynamic risk model grounded in situational awareness is pertinent to ensure
electric utilities know when, where, how, and why to take additional action to mitigate the risk
of wildfire in the shorter term.
Rocky Mountain Power’s approach to situational awareness includes the acquisition of data to
forecast, model, and assess the risk of potential or active events to inform operational strategies,
response to local conditions, and decision making. These key components, as described below
and illustrated in Figure 20, rely on a core team of utility meteorologists to guide, execute, and
continuously evolve.

Figure 20: Overview of Situational Awareness

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5.1 METEOROLOGY
As described above, the ability to gather, interpret, and translate data into an assessment of utility
specific risk and informed decision making is a key component of Rocky Mountain Power’s
situational awareness capability. To support this effort, Rocky Mountain Power developed a
meteorology department that consists of four full-time meteorologists, one data scientist, and
one manager. The team’s experience includes decades of fire weather forecasting for various
government agencies such as the National Weather Service (NWS) and Geographic Area
Coordination Center (GACC).
The objectives of this department are to supplement the company’s longer term risk analysis
capabilities by:
• Implementing a real-time risk assessment and forecasting tool,
• Identifying and closing any forecasting data gaps,
• Managing day-to-day threats and risks, and
• Providing information to operations to inform and recommend changes to operational
protocols during periods of elevated risk, as depicted below.

Figure 21: Meteorology Daily Process
Rocky Mountain Power’s meteorology department also coordinates with government agencies
that provide weather warnings. For instance, during high-risk weather events, the company’s
meteorologists participate as a represented partner in daily coordination calls hosted by the
National Weather Service (NWS) and/or the Geographic Area Coordination Center (GACC).
In these calls, they ingest information and updates, and may provide additional pertinent
information to the GACC. Additionally, the NWS may host briefings during high-risk weather
events that are geared toward an emergency management audience. The company’s meteorology
department also participates in these calls to ensure that forecasting discrepancies are
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understood and that there is alignment and/or clarity regarding external messages from a utility
or the NWS.
5.2 NUMERICAL WEATHER PREDICTION
The creation of an impacts-based forecasting system consisting of an operational Weather
Research and Forecasting (WRF) model and a complimentary 30-year WRF reanalysis across the
company’s entire service territory forms the foundation of Rocky Mountain Power’s
meteorology program. Using the WRF reanalysis and other training data, the company plans to
continue building and training machine learning models to improve its operational thresholds and
convert its weather forecasts into predictions of system impacts. To assess confidence in the
calculated values, forecasts are actively monitored to assess trends and potential convergence or
divergence between forecasts and actuals during period(s) of elevated risk. As the time of
observation nears the forecast period, confidence in the forecasted values increases.
OPERATIONAL WRF MODEL
Rocky Mountain Power’s meteorology department uses a twice daily, two-kilometer-resolution,
hourly WRF model. It produces a comprehensive forecast of atmospheric, fire weather, and
National Fire Danger Rating System (NFDRS) parameters out to a timescale of 96 hours (four
days). The model’s high resolution gives a much more complete picture of finer scale atmospheric
features than what is available with most public four-day ahead timescale models. In addition, the
WRF data is overlayed on overhead distribution circuits and transmission lines, along with other
relevant utility asset data, for further analysis.
30-YEAR WRF REANALYSIS
Rocky Mountain Power’s meteorology department developed a 30-year, two-kilometer
resolution, hourly WRF reanalysis. The 30-year WRF reanalysis uses the same configuration and
contains the same weather, fire weather, and NFDRS parameters as the company’s operational
WRF to minimize any potential forecast biases between the two datasets. This reanalysis data
was correlated with historic outage data and wildfire events using statistical and machine learning
techniques to improve the company’s weather-related outage and wildfire risk thresholds.
Output from Rocky Mountain Power’s operational WRF model is then ingested by the company’s
machine-learning models and GIS tools to convert the daily forecast into potential circuit-level
system impacts and to map the intersection of fire weather and outage related risks across its
service territory. The 30-year WRF re-analysis also provides a daily circuit-level look at the
severity of fire weather conditions relative to the past 30 years and, based on that historic data,
an assessment of whether the forecast weather event would historically have resulted in an
outage on that circuit.
CONTINUAL IMPROVEMENT
The Rocky Mountain Power WRF domain covers the entirety of PacifiCorp’s six-state service
territory. From 2021 to 2022, Rocky Mountain Power invested in the procurement of two High
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Performance Computing Clusters (HPCCs) to provide the computational resources needed to
run an operational WRF model that large. Currently, the two systems provide a high resolution,
four-day forecast of the WRF domain twice daily through a single, deterministic model.
This single, deterministic WRF model has allowed Rocky Mountain Power to take meaningful
action in advance of severe weather to reduce restoration times and increase reliability.
However, it does not account for multiple weather scenarios, which makes it more difficult to
forecast the types of low probability, high-impact weather events that are becoming both more
common and more impactful. To address this issue, Rocky Mountain Power plans to implement
a multi-member WRF ensemble forecasting system. This new forecasting system will enable
analysis of multiple weather scenarios simultaneously, thereby improving the accuracy of the
company’s forecasts and its ability to respond to severe weather in advance. Additionally, the
company also plans to increase the computational capacity of its forecast system by purchasing
3 new HPCCs. These new supercomputers will add the compute power needed to implement
the new forecasting system and, at the same time, allow for full system redundancy, which can
be critical during severe weather events.
5.3 ONGOING DATA ACQUISITION AND INPUTS
Ongoing data acquisition and inputs, from both internal and external sources, is another key
component of Rocky Mountain Power’s situational awareness model.
WEATHER STATION NETWORK
Public weather data has been available for many years for reference. However, relying only on
publicly available data can have limitations. When using publicly available weather data the utility
does not have visibility into the maintenance and calibration records or standards used to
maintain the weather station collecting the data. Additionally, the frequency of data collection
may not match the requisite intervals for performing real time risk assessments and dynamic
modeling. Finally, publicly available data may have geographic coverage gaps within the utility’s
service territory.
When weather stations are owned by the utility, the calibration date and usability of the data is
known, the data reporting intervals can be adjusted to report more frequently, and the data can
be used to inform real time operations. Additionally, weather stations can be installed and
adjusted to pinpoint specific locations needed to inform utility risk assessment. For all these
reasons Rocky Mountain Power is continuing to invest in a utility-owned and operated weather
station network within the company’s service territory. Currently, Rocky Mountain Power has a
network of 21 weather stations in Idaho installed directly on utility infrastructure. Additionally,
the company also has portable weather stations that it can deploy as needed, for example, during
extreme weather events.
As shown in Figure 22 below, data gaps are a key consideration in siting weather stations. These
can include a lack of data granularity, as well as the absence of any data altogether. Additionally,
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as part of its weather station siting methodology, the company accounts for geographic gaps in
publicly available weather data from within its service territory, to include factors like data
resolution, and consistency.

Figure 22: General Weather Station Siting Methodology
Weather station data is used to create a model of routine weather patterns in specific areas. This
weather data is then leveraged alongside the operational WRF, its companion 30-year weather
data reanalysis, and Technosylva’s Wildfire Analyst-Enterprise (WFA-E) software (described in
Section 5.4 below), to model potential impacts to infrastructure associated with forecasted
weather events and inform operational protocols and decision making, such as when and where
to stage resources and how to prioritize restoration times. This improved modeling allows for
better anticipation of impactful weather events and is a key component of situational awareness.
Table 9 below depicts the plan and annual phasing of Rocky Mountain Power’s weather station
installation work.
Table 9: Weather Station Build Out Plan

2023 Actuals 2024 Plan 2025 Areas to Evaluate Total
New Weather Stations 10 10 7
Total Idaho Fleet 25 35 42 42
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In 2024, Rocky Mountain Power plans to install 10 additional weather stations, evaluate additional
locations for installation in 2025, and depending on data gaps and risk, grow the weather station
fleet to approximation 42 stations by 2026. To ensure the weather stations are operating
appropriately, they are calibrated on an annual basis. Rocky Mountain Power’s meteorology
department will continue to evaluate the benefits of installing additional weather stations.

PUBLICLY AVAILABLE SITUATIONAL AWARENESS DATA
Rocky Mountain Power’s weather stations and WRF model generate a considerable amount of
data each day. The company makes this data available to its employees, customers, and public
safety partners through a Situational Awareness website, pacificorpweather.com, alongside
weather station observations and forecast data from other trusted government sources, including
the National Weather Service. Combining weather station observations with forecast data allows
Rocky Mountain Power to compare real-time weather observations with forecast data. Further,
the wind climatology of each weather station is considered, with real-time and forecast wind
conditions color-coded based on station-specific statistics like 95th and 99th percentile values. All
the above data are automatically updated on the website as new data is available and can be
viewed in maps, tables, and meteograms. Figure 23 below includes sample material from the
company’s public situational awareness website.

Figure 23: Publicly Available Situational Awareness Information from a Weather Station West of Idaho Falls, ID
This data is also ingested into an internal dashboard used for situational awareness during periods
of elevated risk, like during a PSPS. The dashboard is also customizable based on the scale of the
event and includes station alert speeds and/or other decision points. For example, in September
2022, the wind forecasts indicated that there was potential for wind-related power outages at a
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time when wildfire danger was high. The data plots on the forecasts also provided the
approximate timing of outage-producing winds at multiple weather stations across the service
territory, thereby supporting operational decision-making around targeted de-energization(s).
In 2024, Rocky Mountain Power plans to incorporate additional information into the internal
dashboard to support its situational awareness and implement improved website functionality.
5.4 WILDFIRE RISK MODELS AND TOOLS
Rocky Mountain Power leverages a variety of models and tools to assess dynamic wildfire risk,
which are described in the subsections below.
FIRECAST AND FIRESIM
As discussed in Section 1.2, in reference to the FireSight tool, Rocky Mountain Power procured
and implemented Wildfire Analyst Enterprise (WFA-E), the broad suite of wildfire risk modeling
tools from Technosylva. WFA-E includes two seasonal wildfire models, FireCast and FireSim, and
is used by the company to forecast the risk of wildfire and the potential behavior of a wildfire,
should it occur. As described in Appendix C – Wildfire Risk Modeling Data Inputs, the inputs for
the various WFA-E models are similar. They are, however, used for different purposes. FireCast
performs simulations daily to assess wildfire risk more broadly, while FireSim is used to simulate
growth and spread of specific and unique fire events.
FireCast: FireCast performs millions of wildfire simulations daily across the company’s service
territory to provide a 96-hour look ahead that identifies the risk of wildfire (both of ignition and
impact) in particular locations. This output is then joined with overhead distribution and
transmission asset location data to provide location-specific wildfire risk and consequence
forecasts. It is important to note that the asset location data does not assess the probability of a
utility asset causing an ignition but, instead, is used to inform operational decision-making, as
discussed in Sections 5.5 and 8.
FireCast outputs include the following information:
• An assessment of the potential for a wildfire given fuel, weather, and other conditions.
• A simulation of how a wildfire would behave in the event of an ignition. This would
include, for instance, the forecasted rate of spread, size, and flame length.
• Data on the population threatened and potential impact to assets (e.g., identification of
buildings that would be threatened in the event of a wildfire).
Figure 24 is an example of FireCast output from July 2023. It shows the potential acreage burned
should an ignition occur near a circuit. The areas around the circuits highlighted in blue are not
forecasted to be impacted by wildfire spread. In contrast, the areas around the circuits highlighted
in yellow are forecast to be within 100 acres of wildfire spread. The line graphs to the right depict
variables like wind speed and fuel moisture for the forecast period. This information is then used
to inform operational practices like whether to de-energize proactively or, if time allows, take
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measures to protect utility assets and communities that could be in the path of a wildfire. This
example does not make any assumptions about the effectiveness of the initial or extended attack
that may impact the forecast of acres burned.

Figure 24: Example of FireCast Output near Spencer, ID, July 2023
FireSim: FireSim runs simulations that forecast potential fire behavior and spread from a 1 to
96-hour period and assess the potential impact on populations, buildings, utility assets, and other
resources in the field. FireSim’s model assumes no suppression efforts to slow the fire’s spread
and considers the following elements:
• Initial Attack Assessment. Assessment of how difficult initial attack could be for first
responders and the probability of stopping the fire within the first operating period. An
operational period is “The period of time scheduled for execution of a given set of tactical
actions”6 and varies from incident to incident.
• Population at Risk. Projection of the number of people in the path of the fire and the
timing of when the fire is likely to arrive.
• Assets at Risk. Physical assets like utility equipment, residential and commercial
structures, barns, outbuildings, other structures, and the timing of when the fire is likely
to arrive.

6 Federal Emergency Management Agency. FEMA Operational Planning Manual FEMA P-1017. June 2014. Sourced November 6, 2023.
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• Places at Risk. These are locations identified on the maps that may not be physical
assets but have other significance. These could include parks, reservoirs, cultural sites,
campgrounds, or other locations.
• Weather and fuels conditions: Wind speed, direction, fuel moisture content.
Figure 25 below includes an example of both FireSim outputs and reports from a simulated event
near Spencer, ID in July 2023.

Figure 25: FireSim Output (left) and Report (right) near Spencer, ID, July 2023
The shaded area in the graphic on the left shows the forecasted spread of the simulated fire over
a period of 12 hours. In the companion FireSim report to the right, the rating of the Initial Attack
Index difficulty and Fire Behavior Index are highly influenced by fuels models and forecasted
weather conditions. The image on the left shows the forecasted direction of the fire and the
image on the right shows the forecasted flame length. Below the images is a table showing a time-
based impact analysis of forecasted acres burned, population and buildings at risk and weather
and fuel conditions. In sum, FireSim modeling is used to assess potential fire growth, spread, and
damage to inform response efforts and decision-making by Rocky Mountain Power operations.
FIRE POTENTIAL INDEX
Prior to the start of the 2023 fire season, Technosylva developed a complementary metric called
the Fire Potential Index (FPI) for Rocky Mountain Power. The FPI is a supplementary metric that
quantifies the potential for large or consequential wildfires based on weather, fuels, and terrain.
In combination with the Modified Hot Dry Windy (MHDW) Index, the FPI is used to guide
operational decision-making as it relates to wildfire risk and spread.
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The following three inputs contribute to the final FPI score:
• A Fuel Model Complex that assesses the type of fuels and the time elapsed since the
last fire to quantify how the fuels may affect fire behavior, type, and suppression difficulty.
The model considers fire history, fuel growth, and fuel dryness over time in response to
weather conditions to support accurate wildfire modeling.
• Weather Conditions that consist of a combination of wind gusts, temperatures, and
fuel conditions. For wind driven risk events in particular, Rocky Mountain Power has
identified some geographically driven patterns that correlate to higher risk.
• Terrain Difficulty Index which represents the level of geographical complexity to
access an area. For instance, regarding fuels and terrain driven risk events, large areas of
contiguous complex fuel and terrain in areas of limited or difficult access present the
greatest risk when fuels are dry, and weather is hot and dry.
The scores from these inputs are then correlated to a level of fire risk in Figure 26 below which
shows the FPI scoring scale and percentiles. An FPI value or FPI percentile can then be used to
determine the FPI risk level. For instance, FPI values >37.5 or percentiles >99% indicate that fire
risk is extremely high. In contrast, an FPI value <5 or percentile <60 indicate that fire risk is low.

Figure 26: Fire Potential Index Scale
MODIFIED HOT DRY WINDY INDEX
In 2023, Rocky Mountain Power analyzed over 2,000 wildfires between 1991-2021 across the
western United States that were known to be or widely suspected of being caused by power
lines.7 Based on its analysis of the ignitions, which included fire size and consequence, the
company identified a correlation between utility ignition and a measure of fire weather based on
temperature, relative humidity, wind, and fuels conditions. As a result, Rocky Mountain Power
created an index called Modified Hot Dry Windy (MHDW) Index. The Modified Hot Dry Windy

7 States included in the analysis were Utah, Arizona, California, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Washington, and Wyoming.
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(MHDW) Index combines the Energy Release Component (ERC) from fuels with weather data
from the surface and low levels of the atmosphere from the Hot Dry Windy (HDW)8 Index to
help determine what days are more likely to have conditions that could result in consequential
wildfires. Based on this analysis, levels of risk (non-fire season, low, elevated, significant, and
extreme) were assigned to certain combinations of environmental conditions that can be used
to inform decision-making. Figure 27 visually depicts the historic analysis, correlation of utility
ignitions to the Modified Hot Dry Windy (MHDW) Index and wind gust percentiles and assigned
levels of risk expressed using a five color-code scheme where a higher percentile of wind gusts
and Modified Hot Dry Windy (MHDW) Index correlated to a higher level of risk. In terms of the
historic analysis, circles in blue reflect fire events where no structure damage or injuries occurred.
The circles in red reflect events where one or more structure was damaged, or one or more
injury occurred. As depicted in Figure 27, the events in red, where structure damage or injuries
occurred, correspond to significant or extreme risk levels.

8 United States Forest Service” “A Brief Introduction to the Hot Dry Windy Index.”
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Figure 27: Correlation of Utility Ignitions to Modified Hot Dry Windy (MHDW) Index and Wind Gust Percentiles to Determine Risk
Levels
5.5 APPLICATION AND USE
Rocky Mountain Power’s meteorology team leverages the various analysis, model outputs, and
indices described above to produce a district-based, weather-related system impact forecast.
ASSESSING DISTRICT FIRE RISK
Meteorology combines the Fire Potential Index (FPI), the Modified Hot Dry Windy (MHDW)
Index, and an analysis of the state of grass curing to produce a daily district-based, weather-
related system impacts forecast that guides operational decision-making. Additionally, when
moving into elevated, significant, or extreme wildfire risk, meteorology also performs an
additional review of fuels and fire weather forecasts and observations by using some or all the
metrics and methods identified in Table 10 below.

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Table 10: Additional Considerations for District Fire Risk

Additional Considerations District Fire Risk
Current or Recent Wildfire Activity Current or recent wildfire activity is an indication that the weather
and fuels conditions will contribute to fire occurrence and spread.
Geographic Area Coordination Center (GACC) Products Seven-Day Significant Wildfire Potential, Fuels & Fire Behavior
Advisories, and other outlooks or discussion products.
National Weather Service Watches or Warnings Fire Weather Watches, Red Flag Warnings, High Wind Warnings,
and other products issued by the National Weather Service
Evaporative Demand Drought Index (EDDI) EDDI identifies anomalous atmospheric evaporative demand and
provides an early warning of increased wildfire risk.
Fire High Consequence Areas (FHCA)
Fire High Consequence Areas are pre-identified areas of
elevated risk based on historical fires, climatology, geography,
and populations
Fire Potential Index (FPI) FPI quantifies the potential for large or consequential wildfires
based on weather, fuels, and terrain.
Fuels Conditions (Grasses, Live Fuels, & Dead Fuels)
Observations of the local fuel conditions including 1, 10, 100, and
1000-hour dead fuel moisture, herbaceous and woody live fuel
moisture, tree mortality, Energy Release Component, etc.
High Resolution Fire Weather Forecasts (WRF)
Rocky Mountain Power’s two-kilometer WRF model produces a
twice daily territory-wide forecast of fire weather and National Fire
Danger Rating System (NFDRS) outputs across a 96-hour time
horizon.
Severe Fire Danger Index
Publicly available index that uses two United States National Fire
Danger Rating System indices that are related to fire intensity
and spread potential.
Vapor Pressure Deficit (VPD) one month running average
Vapor Pressure Deficit is a measure of the atmospheric demand
(thirst) for water. Values above the 94th percentile have been
associated with large wildfires.
Wildfire Consequence Modeling (WFA-E)
Millions of wildfire simulations are performed daily to map out
potential wildfire risk and consequence across the service
territory.

If the forecast indicates that a significant fire weather event is possible within the forecast period,
the meteorology team may leverage more resources to analyze concerns such as timing, strength,
areas potentially impacted, and forecast confidence. These resources include tools like wildfire
consequence modeling and high-resolution models to identify localized areas of greatest risk.
Additionally, the meteorology team may collaborate with the local National Weather Service
office and/or the regional Geographic Area Coordination Center (GACC) office if there is
significant or extreme wildfire risk.
Significant fire potential forecasts issued by the GACC are also used as supplemental criteria to
the Modified Hot Dry Windy (MHDW) Index, an output of PacifiCorp’s WRF model. In addition
to the GACC forecast, the meteorology team closely monitors fuel and Energy Release
Component (ERC) charts that are published by regional GACC coordination centers. Wildfire
and traffic cameras are also used to assess fuel conditions. Additionally, the on-duty
meteorologist also reviews the most recent publicly available weather forecast model trends and
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National Weather Service products (forecast discussions, watches, warnings, advisories, etc.) to
complete a more comprehensive analysis.
The risk level for each district is then determined by the on-duty meteorologist’s evaluation of
all the information gathered relative to the criteria listed in Figure 27 above. In addition to the
system impact forecast matrix shown below, a written weather summary is prepared in which
the on-duty meteorologist provides key forecast takeaways and additional detail regarding the
strength and timing of any weather threats.
This analysis is then combined with the team’s district-based fire risk forecast to produce a
complementary system impacts forecast that is used to support decision-making related to
implementation of the operational, short term risk mitigation programs and measures that will
be discussed in Section 6, Section 7, and Section 8. An example of a district-based fire risk
forecast is shown in Figure 28 below.

Figure 28: Example System Impacts Forecast

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In sum, Rocky Mountain Power’s meteorology team leverages a considerable number of
resources to produce its forecast reports. These include internal and external data sources and
metrics, like the company’s Weather Research Forecast (WRF) model, Modified Hot Dry Windy
(MHDW) Index, Fire Potential Index (FPI), Geographic Area Coordination Center (GACC)
forecast reports, and publicly available weather trends.
The company recognizes that under certain conditions, wildfires can occur anywhere there is
sufficient wildland vegetation that is dry and flammable, even in historically low-risk areas;
therefore, the system impacts forecast covers the company’s entire service territory. Typically,
the forecast reports are produced on business days; however, during periods of extreme weather
or wildfire risk, a forecast is generated every day, including weekends and holidays.

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6. SYSTEM OPERATIONS
Adjustments to power system operations can help mitigate wildfire risk. System operations
adjustments may include the modification of relay settings for protective devices on distribution
lines or changes to line re-energization testing protocols. Adjustments beneficial to wildfire
mitigation are not universally applied to power system operations, however, because there are
certain disadvantages in their use, primarily an increase in outage frequency and duration
experienced by customers. In other words, a balance is required to provide customers with
reliable power while still mitigating wildfire risk. To help balance these concerns, Rocky Mountain
Power is deploying technologies such as fault indicators and assessing outages to inform short
term mitigation projects which are also discussed in the subsections below.
6.1 ELEVATED FIRE RISK SETTINGS
Line protective devices, such as line reclosers, are currently deployed on various transmission
and distribution lines throughout Rocky Mountain Power’s service territory. When a line trip
opens due to fault activity, reclosers can be programmed to momentarily open, allow the fault
to dissipate, then reclose to assess whether the fault is temporary. The reclosing function gives
the ability to restore service on a line that has tripped while maintaining the option to open again
if the fault persists. If the fault is permanent, the recloser will operate and stay open (known as
the “lock out” state) until the line has been deemed ready for re-energization. Figure 29 below
generally depicts one potential configuration of a distribution circuit with multiple line reclosers
installed.

Figure 29: Example of Distribution Circuit with Multiple Reclosers
In general, recloser operation is beneficial because it reduces the number of sustained outages
and improves customer reliability. The reclosing function, however, implicates some degree of
ignition risk because additional energy can be released if a fault persists. When a fault is detected
on the line, a recloser will trip and reclose to re-energize the line based on predetermined
settings. If the fault is temporary in nature and is no longer present upon the reclose operation,
the line will re-energize resulting in limited impact to customers. If the fault persists, however,
reclosing can, depending on the circumstances, potentially result in arcing or an emission of
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sparks. Accordingly, a strategic balance between customer reliability and wildfire mitigation goals
is required.
Rocky Mountain Power is implementing additional strategies on the distribution network,
including the use of modified and more sensitive protection and control schemes, referred to as
Elevated Fire Risk (EFR) settings. Such applications on the distribution network, however, can
have a greater impact on customer reliability and Rocky Mountain Power is exploring different
strategic combinations to find the right balance.
The daily risk assessment process and situational awareness reports described in Section 5.5 are
used to support a risk-based approach for the deployment of EFR settings. For example, when
meteorological conditions of increased wildfire risk occur, an alternative operating mode may
sometimes be used to clear detected faults faster, reduce the number of reclose attempts,
increase the open interval time between trip and reclose operations, or set the recloser to lock
out upon a single trip event. Rocky Mountain Power plans to continue evaluating situational
awareness, customer outages and other information to further optimize the settings and
implement EFR settings as needed.
6.2 ADDITIONAL PATROLS
When district fire risk indicates elevated fire risks, a pro-active, targeted, patrol may be
performed. These patrols target obvious defective equipment and conditions that could lead to
increased ignition risk. Targeted patrols allow for expedited correction of any serious conditions.
They also provide valuable reports of the situation “on the ground” by subject-matter-expert,
field personnel.
Additionally, vegetation management may patrol lines, targeting conditions subject to severe
weather conditions, especially hazard trees. As conditions are found, they are promptly pruned
or removed.
Overall, these additional, responsive patrols aim to provide Rocky Mountain Power, with
additional situational awareness of on the ground conditions before a weather event and
expedited corrections of targeted equipment conditions and hazardous vegetation. These
targeted patrols do not replace standard programs (described on Sections 2 and 3 above);
instead, they supplement them.
6.3 RE-ENERGIZATION PRACTICES
In addition to enabling EFR settings as described above, Rocky Mountain Power may also modify
re-energization practices, which can include patrols and line testing. Line testing involves closing
an open circuit at a protective device to again allow the flow of electricity past the device. If a
fault condition persists, the protective device will open again, and additional work will be
necessary to clear the fault condition. If the line holds, however, the line is re-energized and can
be returned to a normal operating state. Line testing can be an efficient tool to maintain customer
reliability, like the use of reclosing, as described in the previous section. At the same time, line
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testing can potentially result in arcing or an emission of sparks if a fault has not yet cleared when
the line is evaluated. To mitigate this risk (depending on local circumstances), an enhanced patrol
that includes a patrol and step restoration of the entire circuit prior to line testing, may be
required under certain conditions. This often results in an increase to restoration time and costs.
6.4 FAULT INDICATORS TO MITIGATE IMPACTS
The time it takes to patrol a line and the impact to customers can be significantly reduced when
a fault location can be determined. Therefore, as described in Section 4.4 and depicted in Figure
30, the utility has installed fault indicators across its service territory on circuits where EFR
settings are more likely to be implemented, such as the FHCA and surrounding areas. When an
outage occurs, regional operators and field personnel use these tools to narrow down potential
fault locations, optimize the deployment of resources, and expedite restoration.

Figure 30: General Fault Indicator Configuration
EFR settings will continue to be implemented to reduce the wildfire risk associated with
prolonged fault events while being strategic in the EFR implementation to balance the reliability
impacts to customers. Rocky Mountain Power will also continue to assess the need for and install
additional fault indictors as described in Section 4.4.
6.5 2023 EFR EXPERIENCE
In 2023, Rocky Mountain Power implemented its EFR program across the company’s service
territory based on dynamic risk assessment forecasts and tracked outages with EFR settings
enabled. EFR settings, as discussed above, leverage a faster isolation scheme to reduce the
amount of energy that may be released during an event, which can lead to more frequent outages.
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Each outage that correlates to a device having EFR settings enabled is considered an event where
risk was mitigated through the refined settings as the settings limit the amount of energy that
may be released. The correlation between EFR settings being enabled and an outage being
recorded does not mean the settings caused an outage. Outages can be caused by a variety of
factors, not limited to, planned work and/or environmental factors. Figure 31 below depicts the
number of outages with and without EFR enabled each month in 2023 compared to a five-year
average.

Figure 31: 2023 EFR Setting Impact
As shown above, Rocky Mountain Power experienced approximately 90 EFR outages between
July and August in 2023 during periods of elevated fire risk. This represents approximately 2.5%
of the total outages experienced in 2023 and 12% of outages experienced from July to August
2023. The EFR outages may be reviewed in conjunction with seasonal risk experienced in 2023
to identify and prioritize short term mitigation projects for completion to reduce wildfire risk
and mitigate potential reliability impacts to customers associated with the EFR program.
Examples of prioritized projects include upgrading cutouts, fuses, crossarms, and insulators on
circuits that experienced EFR outages in 2023.
Additionally in 2023, Rocky Mountain Power implemented alternate re-energization practices
that required incremental or augmented patrols after system faults, which led to increased
restoration times. While these strategies mitigate wildfire risk, Rocky Mountain Power
recognizes the disruption on customers and communities when there are additional and longer
duration outages.
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Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
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2023 Idaho EFR Setting Program Impacts
5 Year Outage AVG (2019-2023)
2023 Outages with EFR Settings
2023 Outages Non-EFR Settings
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7. FIELD OPERATIONS AND WORK PRACTICES
During fire season, Rocky Mountain Power modifies field operations and work practices to
further mitigate wildfire risk. Additionally, investments are made in tools and equipment to
mitigate wildfire risk.
7.1 MODIFIED PRACTICES AND WORK RESTRICTIONS
As a part of the situational awareness reports and briefings prepared by the meteorology
department, the operations department within Rocky Mountain Power considers the local
weather and geographic conditions that may create an elevated risk of wildfire. The intent behind
implementation of this practice is to reduce the potential of direct or indirect causes of ignition
during planned work activities, fault response, and outage restoration.
Personnel working in the field during fire season mitigate wildfire risk through a variety of tactics.
Routine work, such as condition correction and outage response, poses some degree of ignition
risk, and, in certain circumstances, crews modify their work practices and equipment to decrease
this risk. In the extremely unlikely
event that a fire ignition occurs while
field crews or other Rocky Mountain
Power personnel are working in the
field (collectively “field personnel”),
such field personnel are equipped
with basic tools to extinguish small
fires.
Some wildfire risk can be mitigated
by managing the way that field work
is scheduled and performed. To
effectively manage work during fire
season, area managers regularly
review local fire conditions and the
weather forecasts provided to them
as part of the situational awareness program, as discussed in Section 5 of this document.
During fire season, operations managers are encouraged to defer any nonessential work at
locations with dense and dry wildland vegetation, especially during periods of heightened fire
weather conditions. If essential work needs to be performed in areas with appreciable wildfire
risk, certain restrictions may apply, including:
Hot Work Restrictions. Evaluating whether field personnel should perform work during a
planned interruption, rather than while a line is energized.
Time of Day Restrictions. Considering using alternate work hours to accommodate evening
and night work when there may be less risk of ignition.
Figure 32: Line Workers Performing Work
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Wind Restrictions. Deferring work, if feasible, when there are windy conditions at a particular
work site.
Driving Restrictions. Keeping vehicles on designated roads whenever operationally feasible.
Worksite Preparation. Removing wildland vegetation that poses an ignition risk from a
worksite if the work to be performed involves the potential emission of sparks from electrical
equipment, and only where it is allowed in accordance with land management/agency permit
requirements. In addition to clearing work, water truck resources, discussed below, are
strategically assigned to accompany field personnel working in wildland areas during fire season.
Depending on local conditions, dry vegetation in the immediate vicinity may be sprayed with
water before conducting work as a preventative measure.
As noted above, whether to implement these restrictions is evaluated based on the daily reports
and briefings provided by meteorology. As Rocky Mountain Power is continuously improving and
evolving its plan and programs, the process below is subject to change and is managed by internal
company policies and procedures.
In general, whenever wildfire risk potential is minimal to none, work may be conducted using
normal operating practices. However, when meteorology forecasts wildfire risk conditions that
are elevated, significant, or extreme, local operations may modify operating practices. For
example, the personal protective equipment and basic firefighting tools described above are
required for any field work conducted during periods of elevated fire risk. Local area management
will also evaluate, after considering multiple factors regarding the local circumstances of a
particular circuit, whether any hot work modifications should be made. If wildfire risk is significant
or extreme, local area management will also consider whether any additional work is appropriate.
Section 5 of this document provides an in-depth discussion of how meteorology forecasts impact
field operations and work practices.
ADDITIONAL LABOR RESOURCES
To implement some of the wildfire mitigation programs described above and at greater length in
Section 6 of this document, incremental labor resources and field personnel time is often
required to: (1) support system operations in assessing localized risk and administering EFR
settings and (2) respond to outages during fire season with additional patrols and coordination.
Under normal operating procedures, system operators and field personnel work together daily
to manage the electrical network and there are many situations where system operators depend
on field personnel to gather information and assess local conditions. As discussed in Section 6,
there are system operations procedures during wildfire season for implementing EFR settings
and limiting line-testing. Consequently, system operators need field personnel to gather
information and assess local conditions during fire season more often than what is required under
normal operating procedures. The requests from system operators may be varied, ranging from
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a simple phone call to confirm that it is raining in a particular area, to a much more time-intensive
request, such as a full line patrol on a circuit.
Depending on current conditions at the work site and the duration of the restoration work, field
personnel may also spend incremental time when responding to an outage during fire season. As
discussed in Section 6.2, Re-Energization Practices, a heightened risk exists with traditional
restoration practices. To mitigate this risk, field operations may perform line patrol on certain
de-energized sections of circuits, most notably during fire season. Depending on the
circumstances, this extra patrol might be done just before or just after re-energizing the line.
Typically, this type of line patrol does not involve a close inspection of a particular facility; instead,
it is a quick visual assessment specifically targeted to identify damaged equipment or obvious
foreign objects that may have fallen into the line during restoration work.
ACTIVE WILDFIRE RESPONSE
Rocky Mountain Power monitors and may support the response of active wildfires in or near
assets and service territory. While Rocky Mountain Power employees may carry small fire
suppression equipment, they are not professionally trained fire fighters; therefore, when they
encounter a fire of any appreciable magnitude, Rocky Mountain Power employees will call 9-1-1.
For known active wildfires, Rocky Mountain Power will monitor the situation and may contact
the appropriate incident management team to support efforts needed which can include de-
energization of lines.
7.2 FIELD OPERATIONS CIRCUIT HARDENING
As a result of modified work practices, additional patrols performed, and experiences from times
of elevated risk, circuits may be identified on a case-by-case basis for system hardening upgrades.
System hardening initiatives include but are not limited to the hardening programs identified in
Section 4 such as relay or recloser upgrades, replacement of wooden poles, installation of fault
indicators, or replacement of fuses.
7.3 EQUIPMENT AND TOOL PURCHASES
In addition to changes in work practices, Rocky Mountain Power invests in tools and equipment
to mitigate wildfire risk. These investments include (1) mobile communication devices, (2)
vehicles, (3) personal suppression equipment, and (4) water trucks or trailers.
MOBILE COMMUNICATION DEVICES
Rocky Mountain Power operates and serves customers in very rural locations, some of which
have limited to no cellular connectivity back to the local district office and/or the control center.
During large disasters, like wildfire events, Rocky Mountain Power field personnel need to be
able to communicate quickly and effectively to maintain safe operation of its system and support
emergency response and restoration activities. Therefore, in 2022 Rocky Mountain Power
procured a compact rapid deployable cell tower, this device is also known as Cell-On-Wheels
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(COW). This equipment, as shown on the
right, generates an area of FirstNet cellular and
Wi-Fi coverage, to improve communications
when cell coverage is unavailable. These
devices will be strategically staged at service
centers throughout Idaho for use during a
major event, such as a wildfire emergency, to
improve communication capabilities into the
control center, base camp, and/or
management. This equipment will also enable
communication when there is a loss of it due
to infrastructure failure for SCADA access,
WAN, and portable radios.
In addition to the COW device, Rocky
Mountain Power is currently considering other,
emergency communication alternatives, such as Starlink devices, to help mitigate wildfire risk in
locations where there is no cellular coverage. The Starlink device would provide a Wi-Fi hot spot
connection to allow communication with the local district office and the control center. Overall,
the communication equipment will improve emergency restoration activities and mitigate impacts
to customers.
VEHICLES
Vehicles can be a source of ignition. As discussed above, operations personnel are instructed to
stay on designated roads during fire season, as feasible, and to avoid vegetation which could
contact the undercarriage of parked vehicle. To further mitigate any wildfire risk associated with
the use of vehicles, Rocky Mountain Power plans to convert, over time, the vehicle exhaust
configuration of work trucks. Long term, when new vehicles are purchased, Rocky Mountain
Power plans to purchase trucks with a vehicle exhaust configuration which minimizes ignition
risk.
BASIC PERSONAL SUPPRESSION EQUIPMENT
Personal safety is Rocky Mountain Power’s priority, and the company’s field personnel are
encouraged to evacuate and call 911 if necessary. Field personnel working in fire risk areas
maintain the capability to extinguish a small fire that ignited while they are working in the field.
Field personnel should attempt suppression only if the fire is small enough so that one person
can effectively fight the fire while maintaining their personal safety. All field personnel working in
the FHCA during fire season will have basic suppression equipment available onsite, because field
utility trucks typically carry the following equipment: (1) fire extinguisher; (2) shovel; (3) Pulaski;
(4) water container; and (5) dust mask. The water container should hold at least five gallons and
may be a pressurized container or a backpack with a manual pump (or other).
Figure 33: Rapidly Deployable Cell-on -Wheels (COW)
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WATER TRAILER RESOURCES
Rocky Mountain Power has water trucks or trailers that field operations use to mitigate against
wildfire risk. For clarity, these resources are not dispatched to reported fires (i.e., like a fire
truck). Instead, Rocky Mountain Power resources are strategically assigned to accompany field
personnel if conditions warrant. For example, if it is necessary to perform work during a period
in which there is a Red Flag Warning, Rocky Mountain Power field operations may schedule a
water trailer to join field personnel working in the field. As discussed above, the water trailer
can be used to help prep the site for work. By watering down dry vegetation in the work area,
any chance of an ignition can be minimized. In the extremely unlikely event there was an ignition,
the water trailer could be used to assist in the suppression of a small fire.

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8. PUBLIC SAFETY POWER SHUTOFF (PSPS) PROGRAM
Rocky Mountain Power may de-energize power lines as a temporary, preventative measure
during periods of the greatest wildfire risk. This practice is referred to as “proactive de-
energization” or is more commonly known as a “Public Safety Power Shutoff” or “PSPS.” The
decision to implement a PSPS is based on extreme weather and area conditions, including high
wind speeds, low humidity, and critically dry fuels. The Company may also de-energize power
lines in response to an active wildfire that is within a defined distance of the lines (described in
Section 8.5 below). A PSPS event is implemented as a last resort and is intended to supplement
– not replace – existing wildfire mitigation strategies. The general process is depicted below in
Figure 34.

Figure 34: PSPS Overview
The following subsections describe Rocky Mountain Power’s PSPS program in greater detail.
Many of the program elements revolve around the successful execution of a PSPS event, while
other elements bolster decision-making, mitigate the potential impact of a PSPS event, or help
to avoid use of the tool altogether.
8.1 INITIATION
As discussed in Section 5, situational awareness reports are generated daily during business days
by the meteorology department to aid in decision making during periods of elevated risk. During
periods of extreme risk like during PSPS assessment and activation, these reports are generated
daily, including weekends. They identify where fuels (dead and live vegetation) are critically dry,
where and when critical fire weather conditions are expected (gusty winds and low humidity),
and where and when the weather is forecast to negatively impact system performance and
reliability. It is the intersection of these triggers that result in the potential for a PSPS event, as
shown below in Figure 35.
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Figure 35: PSPS Assessment Methodology
8.2 ASSESSING THE POTENTIAL FOR A PSPS
As discussed in Section 5, meteorology generates a daily weather briefing that includes a system
impact forecast matrix for Rocky Mountain Power’s entire service territory. This matrix includes
a district-level forecast of weather-related outage potential and fire risk as described in detail in
Section 5 of this document. When the district fire risk is significant or extreme, meteorology will
use a combination of its Weather Research Forecast (WRF) and outage models, Technosylva’s
Wildfire Analyst Enterprise (WFA-E) software, and subject matter expertise (as described in
Section 5.4) to identify circuits of concern. Emergency management will also schedule a
coordination meeting to discuss circuits of concern and to determine the appropriate operational
response, up to and including PSPS. A PSPS is typically discussed and/or considered when the
forecast matrix indicates a combination of wind-related outage potential and extreme wildfire
risk in the same district.
8.3 DE-ENERGIZATION WATCH PROTOCOL
Rocky Mountain Power actively monitors real-time weather conditions. When real-time
observations and weather forecasts indicate extreme risk, a de-energization watch protocol is
initiated that includes:
• Activation of an Emergency Coordination Center (ECC).
• Communication with local public safety partners.
• Implementation of additional monitoring activities.
The ECC is staffed by a specialty group of company representatives who assemble during the de-
energization warning through completion of the event to provide critical support to operational
resources. The ECC makes decisions to maintain the safety and reliability of the transmission and
distribution system and helps facilitate cross-organization coordination. The ECC is led by an
Incident Command and has the support of a safety officer, a joint information team, emergency
management, meteorology, and operational stakeholders representing field operations, system
operations, vegetation management, engineering, and other specialties.
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Upon activation of the ECC, Rocky Mountain Power emergency management gathers input from
public safety partners to properly characterize and consider impacts to local communities. The
ECC also sends advance notifications to the operators of pre-identified critical facilities, partner
utilities, and adjacent local public safety partners. The company’s customer service team then
coordinates through the ECC to confirm customer lists for the subject area to develop a
communication plan for customers that may be impacted.
Local assessments of lines may occur during a PSPS watch by way of various methods depending
on the accessibility of locations, the reliability of the line, area conditions and other factors. The
ECC reviews various factors and may deploy crews to perform these assessments in the field or
remotely monitor from the coordination center.
PSPS is a temporary mitigation measure. Consistent with existing regulations and the general
mandate to operate the electrical system safely, the ECC has discretion to determine when (or
if) a PSPS is appropriate. Given the potential impacts to customers and communities, the Incident
Command will consider all available information, including real-time feedback and other
considerations from other ECC participants, public safety partners, and field observers, to
determine whether a PSPS should be executed. Additionally, the Incident Command may decide
to further refine the PSPS areas identified.
8.4 DE-ENERGIZATION PROTOCOL
When a PSPS event is initiated, an action plan is prepared to include affected location details,
event timing and projected event duration. Once approved by the Incident Command, an internal
notification is sent to initiate appropriate communications to customers, critical facilities, public
safety partners, regulatory organizations, large industrial customers, and required field and system
operations team members. Preparations also begin for the opening of community resource
centers (CRCs) and, if needed, additional field resources may be deployed or staged accordingly.
Conditions are continually monitored; when they no longer meet the requirement for a PSPS,
the lines are patrolled and assessed for damage to begin the process of re-energization.
8.5 ACTIVE WILDFIRE DE-ENERGIZATION
Wildfires can spread rapidly and behave unpredictably. Rocky Mountain Power will sometimes
de-energize power lines when there is an active wildfire threatening the lines. For example, fire
suppression authorities may request de-energization of lines to protect firefighters working in
the area; most often, Rocky Mountain Power always accommodates those requests. Additionally,
Rocky Mountain Power may initiate a de-energization after receiving information about an
advancing wildfire, to reduce the risk of energized electrical equipment contributing to fire spread
or endangering fire suppression personnel. Consistent with an established procedure for this
scenario, Rocky Mountain Power will de-energize power lines when a wildfire is within defined
distance of the lines, with a sufficient buffer to guard against the potential spread, as described in
the Appendix C. To help evaluate a fire’s location and probable spread, Rocky Mountain Power
uses the fire modelling software and other situational awareness tools described in Section 5.
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8.6 COMMUNICATION PROTOCOL
Rocky Mountain Power recognizes that adequate and clear communication is a key component
to the successful implementation of a PSPS event, and the company will always strive to provide
as much notice as practical to impacted parties. Nonetheless, PSPS decisions are made based on
weather forecasts, and weather can change quickly or dramatically with little forewarning. This
requires some degree of balancing in communication protocols and, accordingly, advanced notice
may not always be possible.
PUBLIC SAFETY PARTNERS AND CRITICAL FACILITIES
Public safety partners, like emergency dispatch centers, state, regional and local emergency
management, fire agencies, and law enforcement agencies, are an essential component to any
communication plan during an event. They provide essential insight into the geographic and
cultural demographics of affected areas to advise on protocols that address limited broadband
access, languages, medical needs, and vision or hearing impairment. Rocky Mountain Power’s
initial communication with local public safety agencies starts as early as possible when weather
forecasts indicate a PSPS event is possible. Proactive communication to public safety partners
allows them to prepare for anticipated operational impacts internally and mitigate any
community-wide impacts that may occur because of de-energization. Collaboration with these
agencies also supports impact reduction of de‐energization and communication of information
regarding the impacted areas and expected event duration.
Upon activation of the ECC, emergency management resources coordinate, as appropriate, with
local, county, tribal, and state emergency management to provide information through the
assigned representative of the agency. A full list of public safety partners is provided in Appendix
C; however, it is important to note that public safety partners will only be contacted if it is
appropriate for the situation and location. ECC-assigned staff provide event details including
estimated timing and event duration, potential customer impacts, and GIS shapefiles that include
PSPS boundaries for areas subject to de-energization. Throughout a PSPS event, Rocky Mountain
Power’s emergency management group maintains regular communication with its public safety
partners and other entities as applicable. The company will also support efforts to send out
emergency alerts and status updates, as appropriate, until restoration efforts begin.
Critical facilities and infrastructure 9, are particularly vulnerable to the impact of PSPS events.
Rocky Mountain Power emergency management maintains a list of critical facilities within its
service territory. Upon activation of an ECC, they work to establish and maintain direct contact

9 Critical facilities and infrastructure are entities that are essential to the public safety and/ or that require additional assistance and advance planning to ensure
resiliency during de-energization events. These include, but are not limited to, medical, public, and private utility, drinking water or wastewater processing,
transportation, chemical processing, food/ agriculture, and/ or communications facilities.
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with these facilities’ emergency points of contact to provide projected PSPS timing, estimated
duration, regular status updates, and restoration notifications. Additionally, Rocky Mountain
Power will provide, where possible, GIS shapefiles to communications facility operators in
potentially impacted areas.
During a PSPS event, Rocky Mountain Power recognizes the importance of providing additional
geographic details of the affected area and provides them to public safety partners through a
secure web-based public safety partner portal. The public safety partner portal is a secure, map-
centric application that hosts information regarding critical facilities and infrastructure like GIS
files for location, primary/secondary contact information, and known backup generation
capabilities.
CUSTOMERS
The Rocky Mountain Power PSPS webpage 10 provides timely and detailed information regarding
potential and actual PSPS events for a specific location. The website has the bandwidth to manage
site traffic under extreme demand because it has implemented bandwidth capacity to a level that
will allow for increased customer access while maintaining site integrity. The PSPS webpage
provides webpage visitors with an interactive map where they can input an address to see if a
residence or business could be affected by a PSPS. When a potential PSPS is announced, the map
is updated to show the geographic boundaries of potentially impacted areas. The boundaries will
be colored yellow, or “Watch” prior to de-energization, then red or “Event” once de-
energization occurs. The website is easily accessible by mobile device, and a Rocky Mountain
Power ‘app’ is available that enables customer access to real-time outage updates and information
via their mobile device.
Customers with specific language needs can also contact the company’s customer care number
and request to speak with an agent that speaks their preferred language. Rocky Mountain Power
employs Spanish-speaking customer care professionals and contracts with a 24/7 service that
provides interpretation in real-time over the phone in multiple languages and dialects. Customer
care agents have received training on wildfire safety and preparedness, and PSPS-related
information to facilitate conversations between the customer(s) and interpretive service to
ensure they receive the wildfire safety and preparedness, or PSPS-related information they are
looking for. Additional information on the company’s customer wildfire safety and preparedness
engagement strategy can be found in Section 10 of this document.
Rocky Mountain Power’s communications plan also includes procedures that ensure appropriate
notifications are given to medically vulnerable customers. The utility leverages insight from its
partners and customer records to pre-identify these customers. Upon activation of the ECC,

10 See https://www.pacificpower.net/psps.
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customer care agents will attempt, time and circumstances allowing, to make personal outbound
calls to known medically vulnerable customers.
The communication plan allows for informational updates to customers using multiple methods
of communication. Direct customer notifications are made by way of outbound calls, text
messaging, and email notifications. Customers will receive an outbound call, when possible,
within:
• 48 hours of a potential PSPS event,
• 24 hours prior to de-energization,
• 1 to 4 hours prior to de-energization,
• At the commencement of the event,
• At the beginning of the re-energization process, and
• Upon the event conclusion.
Additional methods of notification include the use of social media sites like Facebook and X
(formerly Twitter). Upon activation of the ECC, and following appropriate customer
notifications, the public information officer will distribute press releases to news outlets that
serve the affected areas. Regular updates across all available channels are distributed as they are
available, and the public information officer will manage press inquiries as appropriate.
In making the customer notifications described above, Rocky Mountain Power provides a
statement with:
• The impending PSPS execution, with information about the estimated date, time, and
duration of the event.
• A 24-hour means of contact for customer inquiries, and links to pertinent PSPS websites.
• Event status updates, and re-energization expectation notices.
NOTIFICATION TIMING
When a potential PSPS event is forecasted, customers and local government representatives will
be provided with advanced notice. If feasible, notifications of a potential de-energization event
will begin at 72 hours in advance for public safety partners and 48 hours in advance for customers.
If this is not possible due to rapidly changing weather conditions or other emerging
circumstances, the notification process will begin as soon as possible. Additional notice will be
provided as appropriate, as conditions are monitored and depending on the circumstances. There
is some degree of balancing required. Customers generally want ample advance notice of any
actual de-energization. At the same time, recognizing that weather forecasts are inherently
speculative, it is possible to overburden them with notices of potential PSPS events that never
materialize, especially given that the company’s fundamental business objective is to keep the grid
energized except under the most extreme conditions. Table 11 illustrates Rocky Mountain
Power’s planned PSPS notification timeline for notifications sent to customers. Notifications to
public safety partners and critical facilities will take place as appropriate throughout the event.
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Timelines may be reduced if rapidly changing conditions do not allow for advance notification. In
these cases, the company will make all notifications as promptly as possible.
Table 11: PSPS Notification Timeline for Customers

PSPS Notification Timeline and Summary
48-72 Hours Prior De-energization Warning to Public Safety Partners & Operators of Critical Facilities
24-48 Hours Prior De-energization Warning
1-4 Hours Prior De-energization Imminent / Begins
Re-energization Begins Re-energization Begins
Re-energization Completed Re-energization Completed
Cancellation of Event De-energization Event Canceled (if needed)
Status Updates Every 24 hours during event (if needed)
8.7 COMMUNITY RESOURCE CENTERS
Rocky Mountain Power is aware of the potential impacts of PSPS events to all customers,
businesses, and communities, and plans to provide support to impacted communities through
activation of Community Resource Centers (CRCs) as appropriate. By taking advantage of
established relationships with community and public safety partners, a CRC may be activated in
an impacted area to give community members and businesses access to items that may be
affected by interruption of electrical service. The services, which can vary between CRCs, may
include:
• Potable water
• Shelter from hazardous environment
• Air conditioning
• Seating and tables
• Restroom facilities
• Refrigeration for medicine and/or baby needs
• Interior and area lighting
• On-site security
• Communications including internet, Wi-Fi, cellular access, and satellite phone.
• Television and radio
• On-site medical support (where available)
• Charging stations for cellular devices, radios, and computers
CRCs adhere to all existing local, county, state or federal public health orders and will have
personal protective equipment on site and available to customers if needed. Local emergency
management and community-based organizations will be notified of CRC activation(s) as
appropriate and with advanced notice, generally three days prior to the event, when possible.
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CRC activation timing, protocols, and locations are discussed with area emergency management
and community-based organizations during emergency management workshops and tabletop
exercises.
Depending on the needs of its public safety partners, CRC locations may be pre-identified.
However, this is not always the case. For instance, in 2023 Rocky Mountain Power, together with
its partners, determined that the need for and
location of a CRC should be dependent on a PSPS
area and community needs. As a result, it was
decided that a CRC, if needed, should be activated
in close coordination with public safety partners
during a PSPS event. Rocky Mountain Power
intends to continue collaborating with public
safety partners to evaluate its approach to CRC
activation and adapt its practices accordingly.
8.8 RE-ENERGIZATION
As described above, local conditions are
continually monitored during a PSPS event. Based
on forecasted risk reduction, Rocky Mountain
Power may begin staging resources to expedite restoration. Then, when local conditions subside
consistent with the forecasted reduction in risk, restoration activities officially begin. The general
steps of restoration are depicted below.

Figure 37: General Re-Energization Process
Once the local and forecasted conditions are favorable to re-energize and no new risk(s) have
been identified, field personnel begin assessing the de-energized circuits through ground or air
patrols. Power lines that have been de-energized during a PSPS event have been exposed to
strong winds and the potential for damage. In addition, even after the wind has dropped to levels
low enough to support a decision to re-energize, fire weather conditions typically remain
elevated. Therefore, before re-energizing a line post-event assessments are completed to
determine whether any damage has occurred to the line and/ or substation that needs to be
corrected prior to re-energization (e.g., line down, broken crossarms, tree through line and/ or
tree branches or other items blown into the line). Field personnel report any damage identified
to Rocky Mountain Power’s facilities to the ECC where it is tracked. If issues are discovered, the
necessary repairs are made within an appropriate corrective time-period.
Figure 36: Example of a Temporary CRC
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While all lines and facilities (e.g., substations) de-energized as part of a PSPS event are assessed,
a step restoration process is leveraged where possible so that power to customers may be
restored as the assessments progress, instead of waiting for the assessment of the entire
impacted area to complete. While not to scale or representative of an actual event, this concept
is visually depicted in Figure 38 below.

Figure 38: Visual Depiction of Step Restoration
Wherever possible, Rocky Mountain Power also works with emergency and public safety
partners to identify critical customers for prioritization. After the line patrol and facility
inspection is completed, the impacted circuits or portions of circuits are re-energized,
and the date and time of re-energization is logged. Once service is restored to all
customers impacted by the PSPS event, the event concludes.
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8.9 EXPERIENCE
Rocky Mountain Power plans to continuously improve all aspects of its emergency management
practices. From its experience to date, it has identified four key opportunities for improvement
to its Public Safety Power Shutoff Program moving forward. These include:

• Broaden public outreach and engagement. Rocky Mountain Power plans to expand its
communication and overall preparedness as appropriate to ensure adequate public outreach
and engagement regarding PSPS and wildfire safety. As noted above, more detailed
information on the Rocky Mountain Power’s customer wildfire safety and preparedness
engagement strategy can be found in this document.

• Strategize community resource center locations. One CRC was stood up during a
2022 PSPS event in Cedar City with minimal customer interest. Rocky Mountain Power will
continue to emphasize CRC planning during workshops and tabletop exercises. During
events, it will work with local public safety partners to better identify the needs of
communities impacted.

• Streamline GIS and information sources. Due to the dynamic nature of a PSPS event,
there may be a need to manually update multiple sources of information and GIS layers among
various internal platforms. Rocky Mountain Power has a process in place to streamline and
align GIS layers and information sources so it can communicate information quickly. For
instance, Rocky Mountain Power has developed a secure, web-based public safety partner
portal where critical information can be shared with its partners during a PSPS event. The
public safety partner portal is described at greater length in Section 9.

• Internal communication and coordination. Most documents, communication
protocols, and processes have worked well. Nevertheless, there is still an opportunity to
build out new tracking tools, documents, and training within the existing response structure.
To that end, a novel tracking tool has been developed and Rocky Mountain Power has begun
to look at building out additional situational awareness tools.

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Table 12: Summary of PSPS Experiences
Description of Experience Recommended Action Status
Multiple points of contact among
partners resulted in missed
opportunities for communication
with partners.
Update documentation and incident action
plan to include a single point of contact for
partners.
Implemented. Rocky Mountain Power
emergency management has established
service territories for its emergency
managers to create a single point of
contact for partners.
Critical facility (customer)
identification (GIS information).
Complete implementation of the Public
Safety Partner Portal.
Identify steps for producing shapefiles with
critical customer information and identify
who should receive them.
Implemented. The Public Safety Partner
Portal was launched in the first quarter of
2024.
Inconsistent documentation
created potential for confusion
internally and external partners.
Improve documentation consistency.
Task Information Management Specialist
(IM) or Joint Information System (JIS) with
ensuring that all sources of information
match.
Include details on who is responsible for
what information.
Implemented. Joint information system
training has been given to corporate
communications, Regional Business
Managers (RBMs), customer service, and
regulatory on the documentation process to
include roles and responsibilities.
Feedback from partners. Provide more outreach and training on
PSPS to partners.
Expanded PSPS outreach and workshops
statewide.

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9.PUBLIC SAFETY PARTNER COORDINATION STRATEGY
Rocky Mountain Power takes a multi-step approach to coordination with its public safety
partners on wildfire mitigation and PSPS preparedness, as shown in below.
Figure 39: PSPS Preparedness Strategy
As a part of this strategy, each element builds upon the previous step to increase overall
preparedness. They include outreach, workshops, Tabletop Exercises (TTXs), Community
Resource Center (CRC) demonstrations, and functional exercises (FEs) as described in more
detail in the following subsections.
9.1 GENERAL OUTREACH
Rocky Mountain Power participates in multiple public safety partner meetings and workshops
throughout the calendar year across its service territory. Meetings include monthly, quarterly,
and annual County and State Emergency Management partner meetings, in addition to pre- and
post-fire season collaboration meetings with local, state, and federal fire suppression agencies.
These informal discussions are designed to orient participants to a new concept or procedure
and continue fostering key working relationships. Additionally, Rocky Mountain Power provides
an annual customer webinar, described at greater length in Section 10.5, that provides additional
information about PSPS practices that is displayed prominently on the wildfire safety and
preparedness webpage.
9.2 WORKSHOPS
Workshops are more local, targeted discussions that build upon general outreach to further
compare and refine plans, streamline processes, and confirm capabilities (such as customer
outreach, critical facilities, and CRC locations and operations) with local public safety partners.
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In 2023, the company did not conduct workshops as part of its outreach outside the FHCA. In
2024 and beyond, however, it anticipates targeting workshop locations outside of the FHCA and
leveraging them to bring other communities and public safety partners up to speed.
9.3 TABLETOP EXERCISES
Rocky Mountain Power facilitates annual discussion-based and functional tabletop exercises to
develop awareness of PSPS planning and procedures. These exercises aim to facilitate public and
private sector coordination, validate communications protocols, and verify capability to support
communities during extreme risk events through mitigation actions such as the deployment of
community resource centers. Additionally, the exercises include the collective identification of
critical infrastructure at the county level to better inform restoration planning and notifications.
Rocky Mountain Power collects after-action reports from exercises and real-world events
involving wildfire safety and Public Safety Power Shutoff. The after-action reports request
feedback on areas for improvement, potential corrective actions and suggestions for plan or
procedure development. The company considers suggestions for inclusion in a comprehensive
plan that is subsequently shared with the appropriate public safety partners.
9.4 COMMUNITY RESOURCE CENTER DEMONSTRATIONS
Rocky Mountain Power may provide a public demonstration of a Community Resource Center
(CRC) prior to the start of wildfire season. This public event provides an opportunity for
members of the public, as well as public safety partners, to learn about the type of services
offered at a CRC during a PSPS event.
9.5 FUNCTIONAL EXERCISES
Functional Exercises (FE) are the last step in PSPS preparedness. Rocky Mountain Power
coordinates these exercises to examine or validate coordination, command, and control between
various agencies. Unlike TTXs or workshops, which are discussion based, these exercises are
larger scale, last much longer (e.g., multiple days), require significantly more planning and
coordination, and include deployment of resources to practice protocols and processes. A
functional exercise requires that part of the plan be executed. Examples relevant to a PSPS FE
might include performing customer calls or updating websites. To be successful, functional
exercises require that foundational planning like workshops and TTXs be complete, and formal
plans to be in place. Currently, Rocky Mountain Power is not planning to conduct a functional
exercise in Idaho in 2024. Rocky Mountain Power does expect to leverage its experience
conducting functional exercises in other states with more mature PSPS programs and incorporate
functional exercises in Idaho in the future as needed.
9.6 2023 ACTIVITIES
In 2023, Rocky Mountain Power conducted outreach and exercises statewide. It held two
regional TTXs to improve efficiency and enhance broader coordination and collaboration with
public safety partners. Even though both events targeted certain counties, Rocky Mountain
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Power encouraged expanding participation by inviting officials from adjacent counties.
Additionally, it held two outreach events and conducted a CRC demo in July 2023. Table 13
below provides a more detailed overview of these activities.

Table 13: 2023 Completed Workshops and Exercises
Activity General Location 11 Target Counties 12 Planned Complete Date Complete Date
Outreach/Conf. Statewide Idaho Statewide February 2023 January 2023
Outreach/Conf. Statewide Idaho Statewide April 2023 April 2023
Tabletop
Exercise/CRC demo Southeast
Bear Lake, Caribou,
Bannock, Oneida, and
Franklin
July 2023 July 2023
Tabletop Exercise Southeast
Butte, Clark, Fremont,
Jefferson, Madison,
Bonneville, and Bingham
July 2023 July 2023
In addition to executing planned activities, Rocky Mountain Power may also participate in various
other workshops, conferences, and discussions to ensure coordination and preparedness with
public safety partners, state agencies, and other utilities. For example, at an event targeted to
Southeastern Idaho wholesale transmission customers on September 28, 2023, emergency
management presented the PSPS process to transmission customers in Idaho Falls, Idaho.
9.7 2024 EMERGENCY PREPAREDNESS AND EXERCISE PLAN
In 2024 and beyond, the company plans to continue building upon previous years’ experience to
engage and coordinate with public safety partners. Based on the company’s experience to date,
planning, in collaboration with public safety partners, is most effective when completed closer to
the start of fire season. Therefore, Rocky Mountain Power intends to solicit input from public
safety partners later in the year to firm up the details and schedule of its activities for the current
year. Table 14 below provides an overview of emergency management activities for 2024.

11 Rocky Mountain Power identifies general locations and then works with public safety partners to select the most appropriate location and dates for activities.
12 Target counties are informed of the coordination plan and strategy; however, Rocky Mountain Power does not limit participation in the event.
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Table 14: 2024 Tentative Workshop and Exercise Plan

Activity General Location 13 Target Counties 14 Planned Complete Date
Tabletop Exercise Southeast
Bear Lake, Caribou,
Bannock, Oneida, and
Franklin
July 2024
Tabletop Exercise Southeast
Butte, Clark, Fremont,
Jefferson, Madison,
Bonneville, and Bingham
July 2024
The company may also participate in workshops, conferences, and discussions, or it may host
other activities to ensure coordination and preparedness with public safety partners, state
agencies, and other utilities. In sum, the annual activity plan is subject to change depending on
public safety partner input and availability.
9.8 PUBLIC SAFETY PARTNER PORTAL
During a PSPS event, Rocky Mountain Power recognizes the importance of providing additional
geographical details of the affected area. Therefore, in addition to the coordination strategy
described above, Rocky Mountain Power launched a secure, web-based portal to share
information about critical facilities and infrastructure 15 with Public Safety Partners during a PSPS
event. It is a secure, map-centric application that hosts GIS files and information regarding critical
facilities and infrastructure like primary/secondary contact information and known backup
generation capabilities. In addition to enhancing coordination with local public safety partners,
the portal also improves Rocky Mountain Power’s capabilities to evaluate, communicate with,
and prioritize restoration of critical facilities and infrastructure.

13 Rocky Mountain Power identifies general locations and then works with public safety partners to select the most appropriate location and dates for activities.
14 Target counties are informed of the coordination plan and strategy; however, Rocky Mountain Power does not limit participation in the event.

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10. WILDFIRE SAFETY & PREPAREDNESS ENGAGEMENT STRATEGY
Rocky Mountain Power employs a multifaceted approach to support community engagement and
outreach with the goal of providing clear, actionable, and timely information to customers,
community stakeholders and regulators. Over the past several years, the company has engaged
customers and the general public throughout its three-state service area on wildfire safety and
preparedness through a variety of tactics including webinars, targeted paid advertising campaigns,
informational videos featuring company subject matter experts, press engagement, distributed
print materials, infographics, social media updates, and direct communication through: bill
messages, emails and website content, among other communication channels. The wildfire safety
and preparedness community engagement plan will continue to evolve year-over-year as
customer and stakeholder feedback and regulatory guidance is incorporated. Rocky Mountain
Power maintains an awareness and engagement strategy that is flexible and allows for dynamic
tactics, informed by customer survey data, community stakeholder input and community needs.
Overall, Rocky Mountain Power’s plan includes information that can be heard, watched, and read
in a variety of ways with the goal of accessibility and understandability.
10.1 AWARENESS AND ENGAGEMENT CAMPAIGN
For the past several years, the company has deployed some form of paid media campaign to raise
awareness and action on wildfire safety and preparedness. The 2023 wildfire safety and awareness
paid advertising campaign, which launched March 20, 2023, and concluded October 1, 2023,
included radio spots, digital over-the-top (OTT) pre-roll video ads (Hulu, Pluto TV, Roku, etc.),
digital audio ads (Spotify, Pandora, etc.), display ads (search and web banners), and social media
static and video ads (Facebook, Instagram, and YouTube) – each delivered in English and Spanish.
Metropolitan Statistical Areas in Idaho, specifically, were targeted through a social media
campaign on Facebook, Instagram, and X (formerly Twitter). The campaign focused on four main
topics: personal preparedness and safety, PSPS, leadership and vision, and investments the
company is making to reduce wildfire risk, specifically grid hardening. A breakdown of target area
and language are shown in Table 15 below.
Table 15: 2024 Tentative Workshop and Exercise Plan

Target Area Language
Southeast English
The call-to-action in each campaign vertical compelled the audience to visit Rocky Mountain
Power’s wildfire safety and preparedness online resources. In 2023, the company’s social media
campaign in Idaho received 730,438 impressions and 6,331 clicks to company-hosted wildfire
safety and preparedness informational webpages.
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Engaging with local and regional
news media outlets is another key
component of the awareness and
engagement campaign. Each year
prior to fire season, Rocky
Mountain Power distributes
updated wildfire safety information
and information on the company’s
WMP to press outlets across its
service area as an additional low-
cost outreach method. During the
2023 wildfire season, company
wildfire safety and mitigation subject matter experts also provided eight interviews on the topics
of PSPS and wildfire mitigation.
In addition to paid and earned (news media engagement) awareness and engagement strategies,
Rocky Mountain Power also communicates to customers about wildfire safety and preparedness
through channels it owns or manages, as shown in Figure 40. Bill messages, website and social
media updates, emails, texts, automated phone calls are also an additional low cost means to
reach customers.
10.2 SUPPORT COLLATERAL
Rocky Mountain Power has developed several print and digital wildfire safety and preparedness
collateral pieces including factsheets, flyers, brochures, infographics, and safety checklists. These
items are accessible through the company wildfire safety webpages and are utilized at public
meetings and community events to describe PSPS (its necessity, considerations and what to
expect throughout the event, etc.), and to provide general information on emergency kits/plans
and preparation checklists, among other topics.
Figure 40: Sample YouTube Content
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Figure 41: Sample Support Collateral
The Rocky Mountain Power communications team updates these materials annually to ensure
the information is relevant, accessible, and actionable. Spanish versions of each piece of collateral
are also made available. Some examples of support collateral are shown in Figure 41.
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Additionally, the company engages
customers as needed via direct
communications like email. For instance,
beginning in 2023, during periods of
elevated risk, modified operational settings
(described in greater detail in Section 6,
System Operations) may be implemented
in some areas. Customers that are
impacted by implementation of these
settings are sent a notification via email or
paper letter, depending on their
communication preferences, when this
occurs. An example of support collateral
for customer notification of
implementation of modified operational
settings is included in Figure 42.
Going forward into 2024 and beyond,
Rocky Mountain Power plans to align its
communication regarding modified
operational settings with its peer utilities.

10.3 CUSTOMER SERVICE TRAINING
Customer care agents have received training on wildfire safety and preparedness and PSPS-
related information to ensure that customers who call in looking for information about wildfire
safety and preparedness or PSPS get information they are looking for. Additionally, customers
with specific language needs can also contact the company’s customer care number and request
to speak with an agent that speaks their preferred language. Rocky Mountain Power employs
Spanish-speaking customer care professionals and contracts with a 24/7 service that provides
interpretation in real-time over the phone in multiple languages and dialects.
In 2022, Rocky Mountain Power established a process to track customer calls regarding wildfire
safety, wildfire preparedness, and other wildfire concerns. This process allowed customer care
specialists to select the term ‘wildfire’ from a drop-down menu at the conclusion of calls. In 2023,
the company received 294 calls from customers regarding wildfire safety. Of those, 233 occurred
at the peak of fire season (August).
Figure 42: Sample Email Communication - Modified Operational Settings
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10.4 WILDFIRE SAFETY, PREPAREDNESS, AND PSPS WEBPAGES
The Rocky Mountain Power website
provides robust and comprehensive
information on company wildfire
mitigation programs, general wildfire
safety, PSPS information, and more. In
2022, the company launched updated
wildfire safety webpages to improve
customer experience and allow for
improved accessibility to wildfire-
related information. The page refreshes
include a new infographic depicted in
Figure 43 that demonstrates the work
in progress to improve the safety and
reliability of the grid.
Additionally, the page was updated with
embedded videos highlighting the work Rocky Mountain Power will complete to improve the
system, increase situational awareness, and prepare for events that may result in outage activity.
The wildfire safety webpages were also updated in early 2022 to include a 1-to-1 translated
Spanish wildfire safety pages (see Figure 43). This includes a frequently asked questions section,
links to public safety power shutoff maps and information, and resources including public safety
power shutoff and wildfire preparedness brochures.

Figure 44: Sample Webpage Content - Spanish
Figure 43: Wildfire Mitigation Program Infographic
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Various resources and tools for community preparedness can be found on the Rocky Mountain
Power wildfire mitigation webpage.16 Prompts for customers to update contact information are
displayed prominently on the page. Guides and checklists for creating an emergency plan/outage
kit are easily accessible. The wildfire safety webpages also include links to the WMP, as well as
links to webinars and videos describing key components of the plan. Overall, site visitors have a
variety of ways to consume and engage with wildfire safety and preparedness information, as
shown below in Figure 45.

Figure 45: Wildfire Safety Webpage Content
Additionally, the Rocky Mountain Power Public Safety Power Shutoff webpage provides
educational material on PSPS. It describes why a PSPS would happen, includes details of
conditions monitored prior to executing a PSPS, and on how customers can prepare. Information
on how customers will be notified, what to expect during an event, and about the service
restoration process if a PSPS is deemed necessary are detailed on the webpage. There is also an
interactive map of PSPS areas (shown in Figure 46) that provides a visualization of whether the
company is considering a PSPS, and which areas might be affected if one is necessary.

16 www.pacificpower.net/wildfiresafety
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Figure 46: Public Safety Power Shutoff Webpage
To ensure that the website information is provided in identified prevalent languages, the PSPS
webpage has a message in nine languages – Chinese traditional, Chinese simplified, Tagalog,
Vietnamese, Mixteco, Zapoteco, Hmong, German, and Spanish - that states “A customer care
agent can speak with you about wildfire safety and preparedness. Please call 888-221-7070.” The
company will continue to work with Public Safety Partners and Community-Based Organizations
(CBOs) to determine if additional languages should be included.
Additionally, the webpages have the capacity to manage site traffic under extreme demand
because the company has implemented the bandwidth to allow for increased customer access
without compromising site integrity.
10.5 WEBINARS AND COMMUNITY FORUMS
Rocky Mountain Power also hosts an annual webinar that provides an overview of the company’s
wildfire mitigation program and strategies. Among other items, key mitigation topics addressed
in the webinar include situational awareness capabilities, system hardening investments, the PSPS
process, and general emergency preparedness. The webinar brings to focus how the company
engages with local communities and public safety partners on wildfire safety. It also serves as a
forum for customers, community stakeholders, and the public-at-large to ask questions during
Page | 84
the live stream. In 2025, Rocky Mountain Power plans to host a webinar for Idaho in advance of
fire season.
The Rocky Mountain Power communications team updates these materials annually to ensure
the information is relevant, accessible, and actionable. Spanish versions of each piece of collateral
are also made available. Some examples of support collateral are shown in Figure 47.
Additionally, the company engages customers as
needed via direct communications like email. For
instance, beginning in 2023, during periods of elevated
risk, modified operational settings (described in greater
detail in Section 6, System Operations) may be
implemented in some areas. Customers that are
impacted by implementation of these settings are sent a
notification via email or paper letter, depending on their
communication preferences, when this occurs.
Additionally, customers are also sent wildfire safety and
preparedness email at regular intervals and as needed.
An example of support collateral for customer
notification via email is included in Figure 47.
Going forward into 2024 and beyond, Rocky Mountain
Power plans to align its communication regarding
modified operational settings with its peer utilities.

10.6 CAMPAIGN AND ENGAGEMENT EVALUATION
Rocky Mountain Power is looking to expand the company’s customer survey program in Idaho.
The overall objective of this research would be to measure the public’s awareness of messaging
related to wildfire preparedness and safety to inform the development of the next year’s
engagement campaign.

Figure 47: Sample Email Communication
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Specific research objectives of the surveys would include:
• Measurement of customer awareness of Rocky Mountain Power messages related to
wildfire preparedness.
• Customer recall of specific message topics.
• Customer recall of message channels.
• Measurements of customer recall and understanding about Public Safety Power Shutoff
(PSPS).
• Identification of sources customers are most likely to turn to for information about PSPS.
• Evaluation of the PSPS experience.
• Exploration of actions taken by customers to prepare for wildfire season.
• Measurement of customer awareness of Rocky Mountain Power’s efforts to reduce the
risk of wildfires.
• Evaluation of PSPS notification perception.
• Measurements of customer recall and understanding about Rocky Mountain Power’s PSPS
mitigation programs.
10.7 2024 WILDFIRE COMMUNICATIONS AND OUTREACH PLAN
The company’s overall approach to wildfire communications and its outreach plan remains the
same year over year, as shown in Figure 48. For example, the company always runs a paid
advertising, customer email, and initiative-taking news media engagement campaign.

Figure 48: Wildfire Communications and Outreach Plan Timeline
10.8 BACKUP ELECTRIC POWER REBATE PROGRAM
Currently, the company does not offer a backup power rebate program to its Idaho customers.
However, it is actively exploring whether to implement a backup power rebate program.

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11. INDUSTRY COLLABORATION
Industry collaboration is another component of Rocky Mountain Power’s WMP. Through active
participation in workshops, international and national forums, consortiums, and advisory boards,
Rocky Mountain Power maintains an understanding of existing best practices and collaborates
with industry experts regarding emerging technologies and research.17
For example, Rocky Mountain Power is an active member of the International Wildfire Risk
Mitigation Consortium (IWRMC),18 an industry-sponsored collaborative designed to facilitate the
sharing of wildfire risk mitigation insights and discovery of innovative and unique utility wildfire
practices from across the globe. This consortium, with working groups focused in the areas of
asset management, operations and protocols, risk management, and vegetation management,
facilitates a system of working and networking channels between members of the global utility
community to support the ongoing monthly sharing of data, information, technology, and
practices.
Rocky Mountain Power is participating in the three-year Electric Power Research Institute (EPRI)
Climate Resilience and Adaptation Initiative (READi) to develop, in collaboration with industry
stakeholders and other utilities, a common framework or guideline to assess climate risk, address
resiliency and evaluate investments. This common framework includes aligning on a consistent
approach to understand climate-related data, application, and climate trends, apply a common
set of climate data to perform asset and system vulnerability assessments, and to evaluate
investments and grid hardening technologies across power systems.
Through these various engagement channels, Rocky Mountain Power aims to maintain industry
networks, understand the evolution of technologies, discover broader applications for such
advancements, freely share data to enable scientists and academics, collaborate with developers
to push the boundaries of existing capabilities, and expand its research network through support
of advisory boards or grant funding. Participation in these industry networks is continuing to
increase Rocky Mountain Power’s confidence in its WMP strategies and program elements.

17 A summary of 2023 industry collaborative forums are provided in Appendix E.
18 See https://www.umsgroup.com/what-we-do/learning-consortia/iwrmc/.
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12. PLAN MONITORING AND IMPLEMENTATION
In 2021 Rocky Mountain Power developed a new department, commonly referred to as wildfire
safety. The new department consists of multiple groups, including the program delivery team,
responsible for overall plan development, implementation, and monitoring.
While the broader wildfire safety organization is tasked with supporting all types of wildfire
mitigation initiatives and strategies across the company’s entire service territory, the key function
of wildfire safety program delivery team is to develop, implement, monitor, and improve the
company’s WMP in Idaho. It is the responsibility of wildfire safety program delivery to coordinate
with other internal departments such as asset management, vegetation management, field
operations, and emergency management to ensure all aspects of the plan are delivered.
Additionally, wildfire safety program delivery regularly evaluates its plan and provides updates as
needed and consistent with statutory and regulatory requirements.
The wildfire safety and asset management team, specifically the wildfire safety program delivery
group, is responsible for developing the wildfire mitigation plan, incorporating enhancements to
existing initiatives, and scoping new initiatives. Developing the plan requires internal collaboration
across many different departments to establish the lessons learned applied with existing
initiatives. The group is also responsible for making sure the elements of the plan meet the
regulatory requirements. To further evolve the company’s wildfire mitigation capabilities, new
initiatives are analyzed, scoped, and pursued; for example, the enhanced technologies used to
evaluate risk as described in Section 1 and the increase in computational requirements mentioned
in Section 5.
In addition to evaluating the plan elements, Rocky Mountain Power is also monitoring potential
cost sharing and partnership opportunities to secure federal and state grant funding and offset
the potential impacts to customers. Many of the company’s wildfire mitigation programs, such as
grid hardening, which includes investment in transformational technology, align with the goals and
objectives of potential grant funding.
Implementation of the plan requires processes in place to ensure each initiative is progressing
toward the established plan. Initiative owners are responsible for developing individual project
plans to ensure the plan objectives are met. Wildfire safety program delivery ensures that the
project plans are aligned with the WMP’s objectives, and that key performance metrics are in
place to monitor progress.
Once the plan is filed it is the wildfire safety team’s responsibility to ensure the mitigations are
being performed as described in the plan. Monitoring includes verification that initiative owners
have plans to deliver projects on time and regular status checks to ensure work is progressing as
planned. The regular status checks ensure that risks and issues are being appropriately monitored
and prompt action is taken to resolve issues and remove barriers to successful project execution.

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13. PLAN SUMMARY, COSTS, AND BENEFITS
13.1 2023 PROGRAM ACHIEVEMENTS AND 2024 OBJECTIVES
Rocky Mountain Power WMP is designed to provide timely and cost-effective wildfire mitigation
benefits through a range of programs. While described in more detail through the plan itself,
below summarizes the program elements, 2023 achievements, and 2024 program objectives 19.
Table 16: Summary of 2023 Program Results and 2024 Objectives

19 2023 achievements in this table are estimates or end of year forecasts based on document preparation ahead of the filing.
Program
Category
General Program
Description
2023
Achievements
2024 Program
Objectives
Risk Modeling
& Drivers
Maintain baseline risk
maps and framework to
identify areas that are
subject to a heightened
risk of wildfire and inform
longer term, multi-year
investment and programs
 Refreshed FHCA Map
 Updated Fire Sight composite risk
 Improved advanced data analytics
tools
 Continued FireSight model
updates.
 Update composite risk.
 Continued development for
advanced data analytics
Inspection &
Correction
Perform patrols and
corrections based on the
situational risk
 Completed inspections and
corrections on 54 distribution
circuit segments and 13
transmission circuit segments.
 Continue situational risk
informed inspections and
corrections
Vegetation
Management
Perform vegetation
management work based
on the standard cycle.
Additional work might be
identified through risk
informed inspections.
 Completed approximately
additional vegetation management
practices on 55 circuit segments
which resulted in the following
work:
 ~1150 additional trees pruned.
 ~32 hazard trees removed.
 170 brushes removed.

 Continue standard vegetation
management programs.
System
Hardening
Long term investment to
mitigate wildfire risk
including line rebuilds,
system protection and
control equipment
upgrades, and
replacement of overhead
fuses and adjacent
equipment
 Completed work on 5 fuse savers.
 Completed system hardening on 6
circuits to make the identified
locations more resilient to wildfire
risk.

 No areas identified for system
hardening based on the risk
assessment.
Situational
Awareness
Install and operate a
company owned weather
station network,
implement a risk
forecasting and impact-
based fire weather model,
and inform key decision
making and protocols
 10 weather stations installed.
 Developed Modified Hot-Dry-
Windy Index
 Completed 30-yr WRF reanalysis
and implemented WFA-E software
to model potential impacts based
on weather events.
 Install 10 additional weather
stations.
 Improve weather forecasting.
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Program
Category
General Program
Description
2023
Achievements
2024 Program
Objectives
System
Operations
Risk-based
implementation of EFR
settings and re-
energization practices in
a manner that balances
risk mitigation with
potential impacts to
customers
 Risk-based implementation of EFR
settings and re-energization
practices.
 Installed 59 CFCIs
 Continued risk-based
implementation of EFR settings
and re-energization practices

Field Operations
& Work Practices
Acquire and maintain key
equipment (water trucks,
COWs, & personal
suppression equipment)
and implement risk-based
work practices and
resource adjustments
 Risk based work practices.
 Acquired additional 3 water trucks,
1 UTV, and 1 UTV Trailer
 Purchase 1 COW
 Performed system hardening
upgrades on circuits with EFR
settings as described in Section 7.
 Purchase 4 Starlink devices.
 Continued implementation of
risk-based work practices
 Assess additional equipment
needs
PSPS Program Maintain the ability to
actively monitor
conditions, assess risk,
and implement a PSPS
as a measure of last
resort in a manner that
limits the impacts to
customers and
communities consistent
with regulatory
requirements
 Maintain readiness to implement
PSPS.
 Maintain readiness to
implement PSPS.

Public Safety
Partner
Coordination

Develop and implement a
public safety partner
engagement strategy to
enhance coordination and
ensure preparedness
 Implement Public Safety Partner
Portal
 Completed 2 regional tabletop
exercises.
 Completed 2 statewide outreach
conferences.
 Expand engagement with public
safety partners.
 Complete 2 tabletop exercises
Wildfire Safety &
Preparedness
Engagement
Strategy
Manage a multi-pronged
approach to engage and
inform the public and
customers regarding
wildfire safety &
preparedness
 730k impressions and over 6.3k
clicks.
 Webpage updates for Spanish
translations
 Continue multi-pronged
outreach campaign.
 Continue to refine information
for ease of use and access.
 Identify community engagement
opportunities with external
stakeholders.

Industry
Collaboration
Participate in
consortiums, forums, and
advisory boards to
collaborate with industry
experts, maintain
expertise in leading edge
technologies and
operational practices, and
continue to improve and
advance the WMP and its
programs
 Participated in multi-state industry
collaboration.
 Continue multi-state industry
collaboration.

Plan Monitoring &
Implementation
Leverage a centralized,
dedicated team to
develop, monitor,
implement, and
continuously improve the
WMP
 Investigated grant funding
opportunities.
 Better QA/QC for program tracking

 Complete negotiation of invited
grant funding opportunity
 Continue review of QA/QC
processes for program tracking.
Page | 90
13.2 COSTS
Delivering Rocky Mountain Power’s multi-year WMP, as summarized above, requires an increase
in investment across multiple years. Rocky Mountain Power is currently forecasting an additional
investment of $31.40 million through 2026 (across three years), or $22.26 million capital and
$9.14 million expenses. Some programs, as understood today, require finite investment with a
planned end date. Other programs, such as enhanced inspections or vegetation management, are
expected to be on-going and annual in nature. Furthermore, not all programs require spend of
each type in each year.
The following tables describe Rocky Mountain Power’s three-year estimate of these incremental
costs broken down by expenditure type. Additionally, the capital costs included reflect spend
occurring in a given year, which may differ from values included in GRC filings or cost recovery
mechanism applications which include costs based on when assets are placed in service.
Furthermore, the costs reflect Rocky Mountain Power allocated share of associated programs
and projects and, finally, while the tables only include a three-year forecast, these programs and
increased expenditure are expected to continue beyond 2026.
Table 17: Planned Incremental Capital Investment by Category ($millions)
Program Category Total
2024
Total
2025
Total
2026
3 Year
Total
Risk Modeling and Drivers $0.35 $0.37 $0.38 $1.10
*System Hardening $1.80 $1.80 $1.80 $5.40
Situational Awareness $0.35 $0.74 $0.10 $1.19
Operations & Work Practices (Asset Corrections i.e., pole replacements) $3.50 $5.50 $5.50 $14.50
Public Safety Partner Coordination $0.07 $- $- $0.07
Grand Total $6.07 $8.41 $7.78 $22.26

Table 18: Planned Incremental Expense by Category ($millions)
Program Category Total
2024
Total
2025
Total
2026
3 Year
Total
Risk Modeling and Drivers $0.65 $0.67 $0.71 $2.03
Situational Awareness $0.22 $0.28 $0.32 $0.82
Operations & Work Practices $0.88 $0.88 $0.88 $2.64
*PSPS Program $1.05 $1.05 $1.05 $3.15
WMP Engagement & Plan Development $0.17 $0.17 $0.16 $0.50
Grand Total $2.97 $3.05 $3.12 $9.14
*Asterisks designate reactive spend and not planned spend. Should circumstances indicate a need for these
programs, as described in this WMP, they will be implemented with costs around this projection.
Page | 91
Rocky Mountain Power anticipates continuously improving its WMP in a way that aligns with
community and Idaho Public Utilities Commission expectations. Key takeaways from
collaborations with other utilities, Public Safety Partners, the Idaho Public Utilities Commission,
communities, and customers will be evaluated for incorporation into future WMPs and may
require corresponding changes or updates to these forecasts.
Through partnerships, there are opportunities to secure general and state grant funding which
have the potential to progress wildfire mitigation objectives and offset potential impacts to the
customer. Beginning in 2022, Rocky Mountain Power began applying for, and actively pursuing
grant funding opportunity where in 2023, Rocky Mountain Power was invited to negotiations by
the GRIP grant program. Should the GRIP grant be awarded as proposed, it would support
funding of several programs in this plan.
13.3 CO-BENEFITS OF PLAN
Rocky Mountain Power’s WMP encompasses various strategies, programs, and investments
designed to reduce the risk of wildfire, in a manner consistent with emerging industry best
practices. The elements of this plan provide clear benefits in the areas of wildfire mitigation,
whether through enhanced inspections and corrections, additional vegetation management
activities, or system hardening and the implementation of covered conductor. Additionally,
maturation in the areas of risk mapping and situational awareness facilitate the prioritization and
balancing of efforts to ensure the plan is delivered as efficiently as practical.
In identifying plan elements, Rocky Mountain Power considered both the costs and the benefits
of any approach. Its strategies were guided by the principle that the frequency of ignition events
related to electric facilities can be reduced by engineering more resilient systems that experience
fewer fault events.
While the mitigation strategies in this plan are designed to reduce the risk of wildfire, many also
offer co-benefits to the utility operation and its customers. The joint IOUs have worked on a
common structure for assessing benefits, yet the way the benefits are assessed can vary from
utility to utility. While there are nuances, Table 19 identifies which program categories could
provide perceived co-benefits.

Page | 92
Table 19: Co-benefit Objectives
Projects Utility Definition
Distribution
System
Planning
Safety Reliability Resiliency
Vegetation Management
Incremental wildfire mitigation
programs within the FHCA such as
annual cycle work.
√ √
Asset Inspections and Corrections
Incremental wildfire mitigation
programs within the FHCA such as
increased inspection frequency
and accelerated corrections
√ √
Grid Hardening
Incremental WMP programs such
as recloser / relay installations,
and line rebuilds (covered
conductor, undergrounding, etc.)
√ √ √ √
Situational Awareness Incremental WMP programs such
as weather station installations. √ √ √ √
Research and Development
Advanced Forecasting (Weather) √ √ √
More frequent asset inspections can result in the identification and accelerated correction of
additional conditions, which reduces wildfire risk. This same program can also improve public
safety, worker safety, and reliability. Similarly, system hardening provides one of the most
beneficial ways to reduce wildfire risk, by increasing the level of localized weather conditions that
can be tolerated without impact on the utility operations. For example, installing covered
conductor will increase the grid’s resiliency against wind-driven contacts. The mechanical
properties of a covered conductor design physically prevent the initiation of a flash-over due to
contact, mitigating wildfire risk. For this same reason, covered conductor also reduces the
potential for outages, thereby providing significant reliability benefits.
Furthermore, Rocky Mountain Power’s situational awareness capabilities provide multiple
wildfire mitigation benefits by informing operational and field protocols and playing a key role in
the facilitation of PSPS protocols and decision-making. Along the same lines, situational
awareness, paired with operational readiness, provides co-benefits throughout the year by
supporting Rocky Mountain Power’s response to many types of emergency related events, such
as winter storms. While the program is designed to mitigate wildfire risk, Rocky Mountain Power
anticipates leveraging this new capability to support other types of emergency response and
overall system resilience.
Page | 93
Finally, Rocky Mountain Power’s WMP includes the use of emerging technologies, such as the
implementation of advanced protection and control schemes. While key to reducing the potential
for utility related spark events following a fault event, this equipment provides additional co-
benefits in the areas of distribution system planning readiness. These projects lay the initial
foundation for greater incorporation of other tactics, such as distribution automation or
distributed generation.

Page | 94
APPENDIX A – ADHERENCE TO REQUIREMENTS
Order No. 36045 – Rocky Mountain Power’s application for a deferred accounting order related
to insurance costs dated December 29th, 2023.
Order Requirements Corresponding Plan
The Company shall submit a separate filing a final copy of its
wildfire mitigation plan for Idaho within 30 days of completing
the plan’s development, but no later than April 15, 2024.
This document, Idaho Wildfire Mitigation Plan describes the
wildfire mitigation initiatives performed by Rocky Mountain
Power in Idaho.

Page | 95
APPENDIX B – WILDFIRE RISK MODELING DATA INPUTS
The following describes the general model inputs, data sources, update frequency, and update
plans for data included in the company’s planning and dynamic, seasonal risk model described in
Sections 1.2 and 5.4. Many of the data sources below are provided and managed by Technosylva,
who owns and maintains WFA-E which has the FireSight, FireRisk, and FireSim models.
Dataset Spatial Resolution
(Meters)
Start of Dataset Dataset Update
Frequency
Source
Landscape Characteristics
Terrain 10

Yearly United States Geological Survey
(USGS)
Surface Fuels 30/10 2020 Pre-Fire Season,
Monthly Update in
Fire Season, End of
Fire Season
Technosylva
Wildland Urban
Interface (WUI) and
Non-Forest Fuels
Land Use
30/10 2020 Twice A Year Technosylva
Canopy Fuels (CBD,
CH, CC, CBH)
30/10 2020 Pre-Fire Season,
Monthly Update in
Fire Season, End of
Fire Season
Technosylva
Roads Network 30

Yearly USGS
Hydrography 30

Yearly USGS
Croplands 30 1997 Yearly USDA
Weather And Atmospheric Data
Wind Speed 2000 1990 Hourly / 96 Hour
Forecast
Atmospheric Data Solutions (ADS)
Wind Direction 2000 1990 Hourly /96 Hour
Forecast
ADS
Wind Gust 2000 1990 Hourly / 96 Hour
Forecast
ADS
Air Temperature 2000 1990 Hourly / 96 Hour
Forecast
ADS
Surface Pressure 2000 1990 Hourly / 96 Hour
Forecast
ADS
Page | 96
Dataset Spatial Resolution
(Meters)
Start of Dataset Dataset Update
Frequency
Source
Relative Humidity 2000 1990 Hourly / 96 Hour
Forecast
Technosylva
Precipitation 2000 1990 Hourly / 96 Hour
Forecast
ADS
Radiation 2000 1990 Hourly / 96 Hour
Forecast
ADS
Water Vapor Mixing
Ratio 2 meter
2000 1990 Hourly / 96 Hour
Forecast
ADS
Snow Accumulated –
Observed
1000 2008 Daily National Oceanic and Atmospheric
Administration (NOAA)
Precipitation
Accumulated -
Observed
4000 2008 Daily NOAA
Burn Scars 10 2000 5 Days National Aeronautics and Space
Administration (NASA)/ European
Space Agency (ESA)
Weather
Observations Data
Points 1990 10 Min Synoptic
Fuel Moisture
Herbaceous Live
Fuel Moisture
250 2000 Daily / 5-Day
Forecast
Technosylva
Woody Live Fuel
Moisture
250 2000 Daily / 5-Day
Forecast
Technosylva / ADS
1-Hour Dead Fuel
Moisture
2000 1990 Hourly / 124 Hour
Forecast
Technosylva / ADS
10-Hour Dead Fuel
Moisture
2000 1990 Hourly / 124 Hour
Forecast
Technosylva / ADS
100-Hour Dead Fuel
Moisture
2000 1990 Hourly / 124 Hour
Forecast
Technosylva / ADS
Values at Risk
Buildings Polygon Footprints 2020-21 Yearly Microsoft/Technosylva
Damage Inspection
(DINS)
Points 2014-21 Yearly Cal Fire
Page | 97
Dataset Spatial Resolution
(Meters)
Start of Dataset Dataset Update
Frequency
Source
Population 90 2019 Yearly LANDSCAN, Oak Ridge National
Laboratory (ONRL)
Roads Vector Lines 2021 Yearly Caltrans
Social Vulnerability Plexels 2021 Yearly Esri Geoenrichment Service
Fire Stations Points 2021 Yearly Esri, USGS
Building Loss Factor Building Footprints 2022 Yearly Technosylva
Critical Facilities Points 2021 Yearly Fire Resource Assessment
Program (FRAP), Cal Fire
Potential Ignition Locations
Distribution &
Transmission Lines
Linear Segments 2022 Updated Quarterly Pacific Power
Poles & Equipment Points 2022 Updated Quarterly Pacific Power
Outage History Points 1989 Annual Pacific Power
Ignition History Points 2020 Annual Pacific Power
Fire Activity
Hotspots MODIS 1000 2000 Twice A Day NASA
Hotspots VIIRS 375 2014 Twice A Day NASA
Hotspots GOES
16/17
3000 2019 10 Minute NASA
Fireguard Polygons 2020 15 Minute National Guard
Fire Season
Perimeters
Polygons 2021 Daily National Incident Feature Service
(NIFS)
Historic Fire
Perimeters
Polygons 1900 Yearly Cal Fire
Alert Wildfire
Cameras
Live Feeds Real Time 1 Minute Alert Wildfire Consortium
Lighting Strikes 1000 Real Time 1 Minute Earth Networks / Others
Page | 98
APPENDIX C – ENCROACHMENT POLICY
Wildfire Encroachment
System Operations Procedure SOP-203
Document Information
Author: Erik Brookhouse
Owner (Position): VP, System Operations
Approval: SVP, Power Delivery
Authoring Department: Power Delivery
Approved Location PolicyTech
File Number-Name: SOP-203 Wildfire Encroachment
Revision Number: 2
Revision Date: 1/24/2024
Summary of Policy: Wildfire Encroachment Action Description
Affected Departments: Power Delivery
Effective Date: 1/24/2024
Document Security Category
Confidential X Internal
Restricted External
BES Cyber System Information (BCSI)

SOP-203 Page 2 of 9

Revision Log
# Date Change Tracking
0 06/2023 Preliminary Draft
1 10/24/2023 Final Draft for Approval
2 01/23/2024 New Format

SOP-203 Page 3 of 9
Wildfire Encroachment
System Operations Procedure SOP-203

Table of Contents

PURPOSE ....................................................................................................................................................... 4
IMMEDIATE ACTION: DUE TO FIRE LOCATION RELATIVE TO ASSETS ............................................................ 4
IMMEDIATE ACTION: DE-ENERGIZATION REQUESTS .................................................................................... 5
MANAGEMENT AND MONITORING .............................................................................................................. 5
INITIAL REPORTING ....................................................................................................................................... 5
WILDFIRE THREAT TRACKING ........................................................................................................................ 6
CUSTOMER AND STAKEHOLDER NOTIFICATIONS .......................................................................................... 7
APPENDIX 1 : FLOWCHART FOR FIRE ENCROACHMENT ASSESSMENTS ....................................................... 9

SOP-203 Page 4 of 9
Wildfire Encroachment
System Operations Procedure SOP-203

PURPOSE
This document defines PacifiCorp’s escalation and response protocols when a wildfire is
approaching PacifiCorp’s Transmission and/or Distribution facilities. As set forth in Section 2,
this procedure requires de-energization of power lines when a wildfire is within defined distances
to PacifiCorp assets.
IMMEDIATE ACTION: DUE TO FIRE LOCATION RELATIVE TO ASSETS
In the event of a wildfire encroachment, any subject power lines will be de-energized. A wildfire
encroachment shall have occurred if there is credible information that a wildfire has breached the
minimum distance described in the table below. Real-time weather information (wind speeds) at
the fire location will be obtained using PacificPowerWeather.com or
RockyMountainPowerWeather.com.

Voltage System Design Weather*
Minimum Distance (miles)
for given Wind Gusts (mph)**
< 15
mph Gusts 15 to 30
mph Gusts > 30
mph Gusts
Bulk Electric
Transmission
- or -
Sub-
transmission
Radial Wood Elevated fire weather (yellow or greater) 1/2 1 2
Non-elevated fire weather (green) 1/4 1/2 1
Steel Non-elevated fire weather (green or
greater) 1/4 1/2 1
Loop All All 2 2 2
Distribution All All Elevated fire weather (yellow or greater) 1/2 1 2
Non-elevated fire weather (green) 1/4 1/2 1
Note: Distances and wind speed combinations provide a 2-hour buffer for de-energizing before the fire reaches assets
* As defined on the daily weather risk matrix
** Utilize PacificPowerWeather.com and RockyMountainPower.com to determine real-time wind gusts

The system operator is authorized to take action and shall de-energize any power line within the
wildfire encroachment area. If there has been sufficient time to complete a Wildfire Threat
Tracking Form, etc., the T&D Operations Director (or an authorized delegate) may issue other
specific instructions related to a de-energization, such as the specific time or sequence of de-
energization. In the absence of a contrary instruction from management, however, a system
operator is authorized to de-energize under this section and shall complete the de-energization
required in the event of a wildfire encroachment.

Depending on the specific circumstances of an event, the T&D Operations Director (or an
authorized delegate) may seek approval from executive management to keep a line in service
despite a wildfire encroachment. The approval of the chief executive officer (CEO) of

SOP-203 Page 5 of 9
PacifiCorp, or an authorized delegate, is required to keep a power line energized if a wildfire
encroachment has occurred.
IMMEDIATE ACTION: DE-ENERGIZATION REQUESTS
In the event local fire personnel or incident command request the de-energization of assets, the
system operator will clarify the timeframe requested (i.e. immediate, 15 minutes, 1 hour, etc.). If
fire suppression authorities request an immediate de-energization, the line should be de-
energized immediately. In such case, the de-energization will be promptly reported to the
Reliability Coordinator (RC), along with additional system analysis and resolution of post
contingency issues. If time allows, the system operator will notify the RC of the impending
action, complete a RTCA analysis and plan post contingency actions.
MANAGEMENT AND MONITORING
For multiple safety reasons, a power line should generally be de-energized if there is an active
wildfire in the right-of-way. A wildfire can spread and move quickly. These procedures are
designed to provide a safety buffer and to facilitate de-energization before a wildfire grows into
the actual right-of-way. A wildfire encroachment occurs when a wildfire moves into a defined
buffer space and threatens PacifiCorp-owned assets. Some of the parameters that affect the
decision-making and response actions to a potential encroachment scenario include:

 Voltage classification(s)
 Asset type and construction material
 Stability of the system
 System configuration (loop or radial)
 Current fire suppression efforts
 Fire spread and weather forecast models
 Timeframe for potential asset impacts

These procedures provide specific buffer distances for different scenarios. If an active wildfire is
encroaching a buffer distance, the line will be de-energized. While it can be difficult to obtain
accurate real-time information about an active wildfire, PacifiCorp will act on the best available
information.
INITIAL REPORTING
During normal business hours, PacifiCorp Emergency Management, in consultation with
PacifiCorp Meteorology, is primarily responsible for monitoring any wildfires. Emergency
Management may learn of new wildfires, and monitor known wildfires, through reporting from
external sources and through monitoring of internal tools (i.e., wildfire cameras, satellite wildfire
hot spot warning, or other application alerts).
Outside of normal business hours, System Operations is primarily responsible for monitoring
wildfire activity and shall immediately notify the on-duty Emergency Manager by telephone
upon receiving notice of any new wildfire within 10 miles of any PacifiCorp assets.

SOP-203 Page 6 of 9
 More than 10 miles. Wildfires more than 10 miles from the nearest PacifiCorp assets
are monitored for potential growth and potential impact by Emergency Management.

 Within 10 miles. The on-duty Emergency Manager shall notify by email the T&D
Operations Director or an authorized delegate (who may escalate such information
through normal channels) of any new wildfire within 10 miles of PacifiCorp assets.

o Preliminary Spread Assessment. Upon receiving notice of a new wildfire, the
on-duty Emergency Manager will promptly obtain a preliminary spread
assessment from the on-duty meteorologist regarding the probability of the fire
damaging PacifiCorp assets and shall supplement the original email notification to
the T&D Operations Director or an authorized delegate with the preliminary
spread assessment, as soon as it is available. If the preliminary spread assessment
indicates that the fire will likely reach PacifiCorp assets at any time prior to the
end of the next business day, the on-duty Emergency Manager will immediately
telephone the T&D Operations Director or an authorized delegate to confirm
receipt of the preliminary spread assessment. Otherwise, the on-duty Emergency
Manager may telephone the T&D Operations Director or an authorized delegate
to confirm receipt at the beginning of the next business day.
WILDFIRE THREAT TRACKING
If a preliminary spread assessment concludes that a wildfire will likely grow into PacifiCorp
assets within 48 hours, the on-duty Emergency Manager, in consultation with the on-duty
meteorologist, shall promptly complete a Wildfire Threat Tracking Form. If a preliminary spread
assessment concludes that wildfire contact with PacifiCorp assets is not likely to occur within 48
hours, the on-duty Emergency Manager shall continue to monitor the new wildfire and request a
new preliminary assessment if there are any material changes in the fire. The Wildfire Threat
Tracking Form includes the following information:
 Name of the Emergency Manager submitting the report and the time of the report
 Fire location, including a description of the source of such information;
 Fire size, including a description of the source of such information;
 Proximity to nearest PacifiCorp asset(s), with mapping as appropriate;
 Fire growth assessment by PacifiCorp Meteorology, including:
 Estimated fire growth rate and pattern;
 Forecasted weather conditions which may impact fire spread;
 Physical terrain between the fire and the assets; and
 Estimated duration regarding when fire may reach company assets; and
 Other information regarding the fire and the company’s potential response,
including:
 Physical status of company field personnel;
 Monitoring capabilities of field personnel; and any communications with fire
incident command.

The on-duty Emergency Manager will promptly transmit the completed Wildfire Threat
Tracking Form to the T&D Operations Director or an authorized delegate. After confirming

SOP-203 Page 7 of 9
receipt by telephone, the on-duty Emergency Manager will continue to monitor the wildfire. In
conjunction with ongoing monitoring, the on-duty Emergency Manager shall:
 Open communications regarding fire status with local officials;
 Coordinate with the on-scene field personnel;
 Confer with the on-duty Meteorologist to evaluate fire conditions and update fire
spread assessments;
 Update the Wildfire Threat Tracking Form as needed; and
 Manage an ongoing exchange of information exchange between System Operations,
Emergency Management, and Meteorology until there is no threat to PacifiCorp
assets.
CUSTOMER AND STAKEHOLDER NOTIFICATIONS
In all cases, system operations, under the direction of the network operators, will provide notice
to on-call region or grid system operations management and the on-call emergency management
manager, who will begin coordination with Meteorology, Executive Management, Corporate
Communication, Customer service, Regional Business Managers, and Field Operations.

System Operations
Department Contact Number
Emergency Management 24/7 Hotline – Pacific Power 503-331-4498
24/7 Hotline – Rocky Mountain Power 801-220-2057

Emergency Management Contacts
Department Contact Number
Executive Management
Vice President, System Operations
Vice President, T&D Operations
Senior Vice President, Power Delivery
T&D Field Operations Area Director Based on location
Corporate Communications 24/7 Hotline – Pacific Power 503-813-6018
24/7 Hotline – Rocky Mountain Power 801-220-5018
Customer Service Manager, Customer Service Mission Control 503-813-5087
Regional Business Manager(s) Area Regional Business Manager Based on location

If time allows before de-energization, the customer and stakeholder notification process will be
executed by the appropriate departments. If time does not allow, a post event customer
notification strategy will be developed. Stakeholders include other utilities, the reliability
coordinator, the state commission, and other government authorities.

SOP-203 Page 8 of 9

SOP-203 Page 9 of 9
APPENDIX 1 : FLOWCHART FOR FIRE ENCROACHMENT ASSESSMENTS