HomeMy WebLinkAbout14 Attachments 1- TDPUD WMP - Veg ManagementWILDFIRE
MITIGATION
PLAN
Attachment 1
VERSION 2.1 (SECOND ANNUAL UPDATE)
May 17, 2027
TABLE OF CONTENTS
I.
vervle.................................................. .. ........................ . ........,....._,..,...................... ....... 4
A.
Introduction ........................... „ ...... ............. ..... .,_,...,..,..................................................................
,_ 4
B.
UtHay Service TedfoTy Descripiion........... .... „ ...., ........ .. .......,.,...................
4
C.
Paaocy Statement ............................. ...._....,_.._....,..,................ --- ...............................................
. 5
D,
Purpose of the ffldfise lVflligation Plan ....................... ........ . ............ .. .. _ ..,....,..,..,...,.,
6
F
Organization of the WiWre l'Vlitigaticr3 Pian _ ,..........................................................................
6
II_
Objectives of the Wildfire Mlfigafi n Plan .................................................. , , ....................
6
A.
MinimWng Sources of Ignition .. .. .. ..................... ... ,._.,..._.....................................................
6
B.
Reslwency of the Electric Grid ........................................... „ ., ...........,.,, . , ......................
6
C}
Minimizing Unnecessary or Ineffective Actions.............................................................................. 7
III.
Roles and Respons.ibili...........................................................................................--- ................ . 7
A.
District Roles and Responsiblities .......... ..... .. ................................................. ................. 7
B_
Coordination with Water UtllIty/Department.......... .. ........ ...................................„ _.................
8
C.
Coordination with Communication Infras#ructure Providers...........................................•.....•.....
9
D,
Standardized Emergency Management SWem ..... ..... .. ..... ... ..... . .....—.....................
9
IV.
Wildfire Disks and Drivers Associated witty Design, ConsWualian, Operation, and
Maintenance.................................................................................... .........................
. , 11
A.
Particular Risks and Drhrers Associated with Topographic and Climatological Factors
......11
B.
Enterprise -wide Safely Risks.-................................................................ .... ......... . ... „ ..
,. 1
Changes to CPUC Fire Threat Map ...................... ........ ..................................
12
V.
Wildfire PreventaRvo Strategies ......... ............................................ .......... ........ .. . .. ..
.. . l
A.
High Fire Tlyeat District .................................. ....... ... ........... ...,., ., „ _....... ..... ........... ..............
12
B.
Autornated Metering Irifrastnlcture (AMI)...........--.....................................................................13
.
Outage Management System (OM ) ..................................... ....... ,,.................1.-13
D-
Supevisory Control and Data Acquisition (SCADA).,-„..............................................................
13
E.
Weather Monitoring..... „ .... .. .. . .. .. .......................................................................................
14
F,
Design and Comtnictbn Standards- ..............................„ , ., ............., ........, , ,,., ..,..,..,....,...1
Vegetation Management .............................................. ,.................................., , ...
15
H.
...... ............................................. ......................... .... . . .
16
1,
FR3 lr~sUfating fluid .......................................... ... ....... ...... . ......—-............................................
17
J.
Non -expulsion Current UrnRirtg Fuses............................................................... ............. . . . ,
17
K,
Workforce Training ................................................. ..... .. .. ......... .....................
17
L.
Recloser Operafiionai Practice.......................................................................................18
M,
De-energization....................—.............................., ., ..., .. ............... , . , .- ...........................
18
Re-energization .......... ..... .. „ ..., ,....-.,-..-..-,.-...,,..,........................................,„,........ ,",
19
0-
Tree Attpchments (Legacy Attachments) ............. ......... .............................
20
P.
Proposed Service Requirerwnts........... ... .................................................. .. ............... ......
20
Q.
Covered Nmary Jumper Wire .......................................... ........ ... .... . .....................................
21
Vi.
Commun1y Outreach and Public Awaren.............................................. ............... . ...
21
Vl,.
Restoration of Service ........................................... ............... .,--.-,.-..-,...,..,...,..................
23
Vlll.
Evatuating lho Plan ...................................................,...........................,-....--.....-,
23
-
Metrics and Assurnptior s for Measuring Purr Performance......................................................
23
B.
Impact of Metd--S On Mn .. . . .. . . ..............--.......................................................................
24
C.
Mcnitor;ng and Auditing the Plan ............... ..... .... ....... . .. ............. ..,-........-............................
24
D.
Identifying and Correcting Def!ciencies in the Plan- ...................................„-..........-,,.........,.-.-
25
E-
Monitoring the Effectiveness of Inspechons..................... .........................................................
25
ix.
Independent Audllor........................................ ...... . „........... ........ ........ —................................. ,
25
X.
Appendix........................................................................... ................ .. ..... ..-.,....................... 26
X.
References ........................................ ..... ........................................................ 26
A. INTRODUCTION
The state of California has experienced some of the most devastating and catastrophic wildfires
in the nation's history. Due to the fatalities and damages resulting from the catastrophic wildfires,
the state of California signed Senate Bill (SB) No. 901 into law on September 21, 2018, which
amended Public Utilities Code (PUC) section 8387, requiring every local publicly owned electric
utility (POU) to prepare a Wildfire Mitigation Plan (WMP). To safeguard their electrical systems,
utilities are now required to implement a WMP to comply with the state's Public Utility Code
Division 4.1, Chapter 6, Section 83871 by January 1, 2020. Section 8387 requires every POU to
construct, maintain and operate its electrical facilities and equipment in ways that minimize the
risk of wildfire posed by those facilities and equipment to be adopted by January 1, 2020, and
annually thereafter.
Fire mitigation has been an integral part of Truckee Donner Public Utilities District's (District)
operational practices for years, and the District has several existing policies, programs and
procedures in place that directly or indirectly manage or reduce this risk. Over time, the District
has adopted additional fire mitigation programs to adjust for changes in fire -related conditions
as well as take advantage of technological advances and improved operational practices. The
District continues to evaluate and implement new technologies and operating practices to
further mitigate the potential for ignitions and to better respond to high wildfire risk conditions.
The strategies, programs and activities included in this WMP, with associated goals and metrics,
are an effective approach to reduce fire -related risk for the District's customers in the near term
and will allow for refinement and improvement over time. As new information is obtained, and
experience is gained by implementing the mitigation programs in this WMP, the District will
assess, evaluate, and enhance its wildfire risk mitigation strategies. This plan will also describe
vegetation management, asset inspection and maintenance, recloser setting protocols,
communication plans, as well as the restoration of service process.
B. UTILITY SERVICE TERITORY DESCRIPTION
The Truckee Donner Public Utility District (District) is a Special District of the state of California
engaged in the distribution, sale and delivery of electric power and water. The District provides
retail electric service to about 14,360 customers. The District is a Transmission -Dependent Utility
connected to NV Energy's transmission system and is located high on the eastern slope of the
Sierra Nevada. The District is not interconnected with the California transmission system or to any
California utility. The District's electric service territory is comprised of approximately 44 square
miles in eastern Nevada County and approximately 1.5 square males in adjacent Placer County.
The electric system includes approximately 225 miles total with 135 miles of 12.47 kV and 14.4 kV
Amended by Stats. 2018, Ch. 626, Sec 42. (SB 901) Effective January 1, 2019
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overhead distribution lines, and about one-half mile of 6OkV overhead transmission lines. In total,
the District has 5,490 poles in its service territory.
C.POLICY STATEMENT
The Mission of the District is to provide reliable, high quality water and electrical power services
while meeting customer demand, and to manage District resources in a safe, open, responsible,
environmentally sound manner at the lowest practical cost.
The District strives to manage and mitigate the risk of wildfire with a holistic approach to
operating its system. The outcome of this approach is diligent stewardship of customer/owner
investment in the District as it continues to construct, maintain, and operate its electric
distribution system in a manner that minimizes the risk of catastrophic wildfire posed by its
electrical lines and equipment. The District has applied careful consideration in the
development of broad strategies to mitigate utility -posed wildfire risks while remaining consistent
with the intention of Senate Bill 901 (SB 901) and other regulatory requirements.
The District utilizes the California Public Utility Commission (CPUC) state-wide Fire Threat Map
(Map) originally adopted on January 19, 2018 and revised in March of 2021 (Exhibit A), in
addition to informational fire threat maps from other state of California Government agencies to
inform and aid in the development of this Plan and its subsequent updating. The CPUC Map
designates a portion of the District's service territory (predominantly the Tahoe Donner area) as
Tier 3 (Extreme); additionally, areas circumnavigating the Tahoe Donner area are designated as
Tier 2 (Glenshire, Martis Valley, Truckee, and Donner Lake) with interspersed locations identified
as Tier 1, or exempt from the High -Fire -Threat -District (HFTD),
Although staff acknowledges different designations of Tier 3 area amongst various Fire Threat
Maps and the California Public Utilities Commission (CPUC) Fire Threat Map, for the purpose of
prioritizing and applying operational consistency, the District will apply this WMP (Plan) as though
its service area resides exclusively in Tier 3 (Exhibit A), where practicable. This methodology will
be evaluated on an annual basis and adjustments made as new or substantive information
becomes available.
The District will continue to closely coordinate with local fire and safety officials in the
development and subsequent annual review of this Plan.
D. PURPOSE OF THE WILDFIRE MITIGATION PLAN
This Wildfire Mitigation Plan (WMP or Plan) describes the range of activities and strategies the
District takes to mitigate the threat of overhead power -line ignited wildfires. It addresses the
unique features of the District's service area such as topography, weather, infrastructure, grid
configuration and potential wildfire risks.
This Plan is subject to direct approval by the District's Board of Directors and is implemented by
the General Manager. This Plan meets or exceeds the requirements of Public Utilities Code
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Section 8387 for public:y owned electric utilities to prepare a wildfire mitigation Plan by January
1, 2020, and to evaluate and update annually thereafter.
E. ORGANIZATION OF THE WILDFIRE MITIGATION PLAN
This Wildfire Mitigation Plan includes the following elements:
1. Overview
II. Objectives of the Plan;
III. Roles and responsibilities for executing the Plan;
IV. Identification of key wildfire risks and risk drivers;
V. Description of wildfire prevention strategies;
VI. Community outreach and education;
VII. Restoration of Service;
VIII. Metrics for measuring performance of the Plan and identifying areas for improvement;
IX. Independent Auditor;
X Appendix; and
XI. Reference material.
A. MINIMIZING SOURCES OF IGNITION
The main objective of this Plan is to implement an actionable plan what will create increased
reliability and safety while minimizing the probability the District's distribution system may be an
original or contributing factor in the ignition of a wildfire. The District has evaluated the prudent
and cost-effective improvements to its physical assets, operations, and training that can help to
meet this objective. Further, the District is updating operational practices to reflect its
commitment to prudent system management and will continue to explore new opportunities for
improving the efficacy of the Plan. This plan embraces safety, prevention, mitigation and
recovery programs that are consistent with California State Law.
B. RESILIENCY OF THE ELECTRIC GRID
The secondary objective of this Plan is to ensure and improve, where practicable, system
resiliency. System resiliency is defined by the National Infrastructure Advisory Council as the
ability to reduce the magnitude and/or duration of disruptive events. As part of the
development of this Plan, the District assesses new industry practices and technologies that will
reduce the likelihood of a disruption in service and improve the timellne for restoration of service.
To accomplish this, the District utilizes the following practices: heavy -loading construction
standards that are designed to withstand sustained heavy winds; covered jumper wire (where
practicable); FR3 insulating fluid in transformers; non -expulsion current limiting fuses; and
vegetation management, among other operational practices. The District's distribution system
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has already been designed to be sectionalized by individual circuit with open points at each tie
point.
C. MINIMIZING UNNECESSARY OR INEFFECTIVE ACTIONS
The final objective for this Plan is to measure the effectiveness of specific mitigation strategies as
they apply to the District. Where a particular action, program component, or protocol is
determined to be unnecessary or ineffective, the District will assess whether modification or
replacement is suitable. This approach will also help determine if more cost-effective measures
would produce the same or better results.
This is discussed in more depth in section Vill. D - Identifying and correction deficiencies.
A. DISTRICT ROLES AND RESPONSIBILITIES
Truckee Donner Public Utility District
The District utilizes a Public -Owned Utility Board/General Manager reporting hierarchy.
Board members are elected at large by District customers to staggered four-year terms,
representing constituents across the District's service territory. The Board President and Vice
President are in title; these positions are nominated and appointed by the Board annually. The
Board is responsible for adoption and oversight of all policy and delegates the operational
implementation of policy to the General Manager.
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The General Manager has full operational authority of the District and operates as the Chief
Executive, reporting directly to the Board. The General Manager provides direction and
management to all District staff while implementing Board adopted policy.
The Public Information Officer (PIO) / Strategic Affairs Director, serves as the District's public
liaison to customers and outside agencies as well as responding to requests for information,
including proactively promulgating public awareness outreach or emergency information.
The Electric Utility Director / Assistant General Manager (AGM) has overall functional
management of the Electric Utility and provides day-to-day oversight of the Electric Utility. The
Electric Utility Director utilizes the Electric Operations Manager and Electric Engineering Manager
for division oversight. The AGM also assumes the operational authority of General Manager in
the absence of the General Manager.
The Electric Operations Manager oversees the daily electric utility operations, including:
construction; maintenance; energy control; fleet; facilities; vegetation management; and other
ancillary daily duties. The Electric Operations Manager maintains functional management of
assigned divisions within the Electric Utility and reports to the Electric Utility Director/AGM.
The Electric Engineering Manager oversees the design/engineering tasks associated with
distribution system modification and development/maintenance of material specifications. The
Electric Engineering Manager maintains functional management over the electric engineering
related tasks within the Electric Utility and reports directly to the Electric Utility Director/AGM.
District staff have the following responsibilities regarding fire prevention, response and
investigation:
• Conduct work in a manner that will minimize potential fire dangers;
• Take all reasonable and practicable actions to prevent and suppress fires resulting from
District electric facilities,
• Coordinate with Federal, State, and Local fire management personnel to ensure that
appropriate preventative measures are in place;
• Immediately report fires, pursuant to specified procedures,
• Take corrective action when observing or having been notified that fire protection
measures have not been properly installed or maintained;
• Ensure compliance with relevant Federal, State, and industry standard requirements;
• Ensure that wildfire data is appropriately collected; and
• Maintain adequate training programs for all relevant employees.
B. COORDINATION WITH WATER UTILITIES/DEPARTMENT
The District owns and operates a Water Utility within its service territory, providing retail service to
approximately 13,D00 customers. The Electric Utility Director's office is literally adjacent to the
Water Utility Director's office. When electric operations could or are known to impact the water
utility, District electric and water staff will coordinate so as to mitigate, or where practicable,
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eliminate impact to electric and/or water service continuity. District electric staff collaborates
proactively to notify District water staff of planned outages and communicate as quickly as
practicable during emergency power outages that impact one or both enterprises. This
emergency notification will be extended to the Truckee Fire District and other agencies as
needed.
C. COORDINATION WITH COMMUNICATION INFRASTRUCTURE PROVIDERS
Communications providers are notified via the District's reverse auto -dial system for planned
service disruptions. Further, during emergency operations, District staff update the customer -
facing information website dashboard at hops://arc4.is/19HXSS. Local communication service
providers are included in our NV Energy Public Safety Outage Management (PSOM) notification
process. Local communication service providers are:
Verizon, Suddenlink, AT&T, Plumas Sierra Telecom
D, STANDARDIZED EMERGENCY MANAGEMENT SYSTEM
As a local governmental agency,2 the District has planning, communication, and coordination
obligations pursuant to the California Office of Emergency Services' Standardized Emergency
Management System ("SEMS") Regulations,3 adopted in accordance with Government Code
section 8607, The SEMS Regulations specify roles, responsibilities, and structures of
communications at five different levels: field response, local government, operational area,
regional, and state.4 Pursuant to this structure, the District regularly coordinates and
communicates with the relevant safety agencies as well as other relevant local and State
agencies.
2As defined in Cal. Gov, Code § 8680.2.
3 19 CCR § 2407.
4 Cal. Gov. Code § 2403(b):
(1) "Field response level" commands emergency response personnel and resources to carry out
tactical decisions and activities in direct response to an incident or threat.
(2) "Local government level" manages and coordinates the overall emergency response and
recovery activities within their jurisdiction.
(3) "Operational area level" manages and/or coordinates information, resources, and priorities
among local governments within the operational area and serves as the coordination and
communication link between the local government level and the regional level,
(4) "Regional level" manages and coordinates information and resources among operational
areas within the mutual aid region designated pursuant to Government Code §8600 and between
the operational areas and the state level. This level along w'th the state level coordinates overall
state agency support for emergency response activities-
(5) "State level" manages state resources in response to the emergency needs of the other levels,
manages and coordinates mutual aid among the mutual aid regions and between the regional
level and state level, and serves as the coordination and communication link with the federal
d saster response system.
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The District will support Emergency Operation Center (EOC) operations, when requested by an
emergency manager representing local or State agencies. Support could include the
exchange of information, supplying resources, or staffing an EOC.
Under the SEMS structure, a significant amount of preparation is done through advanced
planning at the county level, including the coordination of effort of public, private, and nonprofit
organizations. Generally, the majority of the District's service territory resides in Nevada County.
When Nevada County serves as the Operational Area, which is guided by the Operational Area
Emergency Service Council (Nevada County) and is headed by the Chairman of the Board of
Supervisors (or designee). The Operational Area includes local and regional organizations that
bring relevant expertise to the wildfire prevention and recovery planning process. These
participants include:
• Director of Emergency Services; Nevada County. Stephen Monaghan
(steve.monaghan@co.nevada.ca.us, 530-265-1238) City of Nevada City (or designee);
• City of Grass Valley (or designee);
• Town of Truckee (or designee);
• Nevada Irrigation District (or designee);
• Nevada County Fire Chief's Association (or designee);
• Nevada County Sheriff (or designee);
• American Red Cross (or designee);
• Tahoe National Forest (or designee);
• California Department of Forestry & Fire Protection (or designee);
• Sierra Nevada Memorial Hospital (or designee);
• Pacific Gas & Electric (or designee);
• Nevada County Public Health Administrator (or designee)
• Placer County Public Health Administrator (or designee); and
• Such others as the Council requests be in attendance.
Additionally, a small portion of the District's service territory resides in Placer County, overseen by
the Placer County Office of Emergency Services Council (PCOES). The PCOES Operational Area
includes local and regional organizations that bring relevant expertise to the wildfire prevention
and recovery planning process. The District will support Emergency Operation Center (EOC)
operations for the PCOES, when requested by an emergency manager representing local or
State agencies. Support could include the exchange of information, supplying resources or
staffing an EOC. Pursuant to the SEMS structure, the District participates in training exercises with
its counterparts both in field drills and tabletop exercises.
The District is a member of the California Utility Emergency Association (CUEA), which plays a key
role in ensuring communications between utilities and emergency responders during
emergencies. The District also participate in the Western Energy Institute's Western Region
Mutual Assistance Agreement (WRMAG), which is a mutual assistance agreement covering
utilities across a number of western states. In addition to those agreements, the District is also
signatory to the American Public Power Association (APPA) mutual aid agreement, providing
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nationwide access to resources for system restoration and support after a major event that
exhausts District resources.
A. PARTICULAR RISKS AND DRIVERS ASSOCIATED WITH TOPOGRAPHIC AND
CLIMATOLOGICAL FACTORS
Per PUC 8387 (C) (as amended on 7/12/19): "A description of the preventive strategies and
programs to be adopted by the local publicly owned electric utility or electrical cooperative to
minimize the risk of its electrical lines and equipment causing catastrophic wildfires, including
consideration of dynamic climate change risks."
The fourth California Climate Change Assessment has concluded that climate change will make
forests more susceptible to extreme wildfires. One study has found that the frequency of fires
over 25,000 acres would increase by nearly 50 percent and that the average area burned
would increase by 77 percent by the end of the century if greenhouse gas levels continue to
rise. Increasing temperatures and rising sea -levels will have direct impacts on public health and
infrastructure. Drought, coastal and inland flooding and wildfire will continue to affect people's
livelihoods and local economies. The District will continue to respond to the existing and
potential impacts of climate change including projected increases in temperature, severe
storms, flooding, and climate -related increases in population.
Increased population is possible due to `climate refuges' leading to increases in both full-time
and transient population, more traffic, etc. This concept is part of Truckee's Climate Adaptation
and Mitigation Plan.
Within the District's service territory and the surrounding areas, the primary risk drivers for wildfire
are the following:
• Human behavior;
• Lightning;
• Climate change;
• Extended drought;
• Vegetation type;
• High winds;
• Mountainous terrain/accessibility;
• Tree mortality;
• Increased population; and
• Lack of early fall precipitation.
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B. ENTERPRISE -WIDE SAFETY RISKS
The District will use a methodical approach to address/mitigate enterprise safety risks. This
approach will utilize both Risk Assessment (RA) and intimate knowledge of our operational
practices. RA is a process to identify and manage potential risks that could undermine core
business functions, threaten business continuity or impact recover. RA will be used to analyze
safety risks, which include:
• Pole Replacement Ranking Tool (Attachment 2);
• Unavailability of NV Energy's transmission due to an outage or planned Public Safety
Outage Management (PSOM) fire de-energization event (Donner Lake Substation &
Tahoe Donner Substation) interconnection & its distribution interconnection (Glenshire);
• Unavailability of CalPeco / Liberty Utilities' alternate distribution feed (Glenshire);
• Loss of Internet connectivity;
• Loss of radio communications;
• Loss of cellular communications;
• Impacts of system de-energization; and
• Impacted roadways limiting movement of personnel and equipment.
C. CHANGES TO CPUC FIRE THREAT MAP
At this time, the District does not recommend any changes to the CPUC state-wide Fire Threat
Map, originally adopted on January 19, 2018 and revised in March of 2021. Future changes in
District knowledge or recommendations going forward will be communicated as required by
statute.
A. HIGH FIRE THREAT DISTRICT
The District participated in the development of the California Public Utilities Commission's (CPUC)
Fire -Threat Map,S which designates the High Fire Threat Districts (HFTD) across California. In the
map development process, the District served as a territory lead, and worked with Cal Fire,
CPUC staff and local fire officials to identify areas of the District's service territory which are at an
elevated or extreme risk of power line ignited wildfire. The District incorporated the HFTD
mapping into its construction, inspection, operation, maintenance, repair, and vegetation
management practices,
The Fire Threat Areas as designated by both Cal Fire and the CPUC have been incorporated into
the District's Geographic Information System (GIS) in order to overlay with District Water and
Electric facilities and identify any infrastructure within areas of high fire threat,
` Adopted by CPUC Decision 17-12-024,
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B. AUTOMATED METERING INFRASTRUCTURE (AMI)
The District has invested in and deployed advanced metering infrastructure within our service
territory. AMI is an integrated system of smart meters, communications networks, and data
management systems that enable two-way communication between utilities and customers.
The system provides a number of important functions that were not previously possible or had to
be performed manually, such as the ability to automatically send an outage notification to the
District's OMS, the ability to automatically and remotely measure electricity use, connect and
disconnect services, detect tampering, identify and isolate outages, and monitor voltages.
C. OUTAGE MANAGEMENT SYSTEM (OMS)
Since 2007, the District has utilized Schneider Electric's Responder Outage Management System
(OMS) within the GIS for tracking and responding to electric outages and system hazards. The
OMS automatically captures outage information in real time from all AMI meters and also
captures incoming phone calls from the public and District customers. The OMS very quickly
consolidates field events and alerts staff to potential issues impacting the electric system. In
2019, the District extended categorizing incidents to include Fires, Hazard Trees, or branches in
proximity of electric lines, The Wires Down category has been tracked since the program's
inception in 2007.
In addition to tracking active hazards to the system, all calls entered into the OMS can later be
used for reporting based on Outage Cause, Duration, System Device, and number of customers
affected. This information is used by District engineers to plan electric system upgrades and
device replacements. Events recorded in the OMS are stored in the Responder Archives and are
available for engineering and operations staff upon request and made available to public
agencies as part of yearly CPUC reporting requirements on reliability indices.
D. SUPERVISORY CONTROL AND DATA ACQUISITION (SCADA)
The District has invested in a robust fiber -based SCADA system that provides staff the capability
to operate the substation reclosers on supervisory control from the District office or remotely
through a secure VPN connection.
The District is investigating an upgrade to the system to allow for supervisory control of all critical
field reclosures, a function which is currently unavailable. This function would allow District staff to
remotely enable or disable all reclosure settings, including setting all reclosures to non-reclose
mode (i,e. one-shot operation) annually from early June to early November to minimize the risk
of fires caused by arcing or faults. Currently we need to manually place these reclosures on non
reclose.
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E. WEATHER MONITORING
The District, due to our very small geographic service territory, monitors current and forecasted
weather data from a variety of sources including;
• The National Oceanic and Atmospheric Administration (NOAA);
• United States National Weather Service (NWS);
• United States Forest Service Wildland Fire Assessment System;
• National Fire Danger Rating System;
• National Interagency Fire Center - Predictive Services for Northern and Southern
California;
• Internal knowledge of local conditions.
Each day, the District will assign one of four operating conditions based on the relevant weather
data and knowledge of local conditions:
(1) Normal: During normal conditions, no changes are made to operations or work
procedures.
(2) Elevated: During elevated fire -risk conditions, District staff will perform normal work with
an elevated level of observation for environmental factors that could lead to an ignition.
(3) Extreme: During extreme fire -risk conditions, the District may delay routine work on
energized primary lines (12.47kV & 14.4kV), The District may perform necessary work to
preserve facilities or property. Extreme weather is defined as: weather phenomena that
are at the extremes of the historical distribution and are rare for a particular place and/or
time, especially severe or unseasonal weather. Such extremes include severe
thunderstorms; severe snowstorms; ice storms; blizzards; flooding; high winds; or heat
waves.
(4) Red Flag: The National Weather Service issues Red Flag Warnings (RFW) & Fire Weather
Watches to alert fire departments of the onset, or possible onset of critical weather and
dry conditions that could lead to rapid or dramatic increases in wildfire activityb. An RFW
is issued for weather events which may result in extreme fire behavior that will occur
within 24 hours. An RFW is the highest alert. While an RFW is in effect, the District's crews
limit hot -work such as welding, grinding, cutting and the District will delay all routine work
on energized primary lines (12.47kV & 14.4kV). The District may perform necessary work
to preserve facilities or property. Vegetation Management and line crews have on -site
fire suppression equipment and conduct tailboard meetings to confirm the location and
read ness of the fire suppression equipment.
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F. DESIGN AND CONSTRUCTION STANDARDS
District electric facilities are designed and constructed to meet or exceed relevant Federal,
State, and industry standards. The District treats State of California, General Order 95 (GO 95) as
guiding standard for design and construction of overhead electrical facilities. The District
meets or exceeds all standards in GO 95 and constructs its facilities consistent with the "heavy -
loading" district as defined by the CPUC (Exhibit B). In short, the District's overhead electric
system is designed to withstand severe winter storms; including extreme wind and snow events.
These atmospheric conditions are well in excess of what occurs during typical RFW's. As a result
of this approach, the District's system is hardened and more resilient to extreme weather events
than systems that do not build to a heavy -loading district standard.
The District monitors trends in materials, technology and work methods to evaluate prudent
operational changes to enhance the efficacy of wildfire mitigation. These evaluations include:
• Engineering Pole Ranking Tools;
• Intrusive Pole Inspections;
• New Construction Methods/Materials;
• Undergrounding New Construction; and
• Tree Wire (covered wire) Use, where applicable.
G. VEGETATION MANAGEMENT
The District meets or exceeds minimum State standard(s) for vegetation management practices
by maintaining a five year trim cycle. For distribution level facilities, the District meets: (1) Public
Resources Code section 4292, (2) Public Resources Code section 4293; (3) GO 95 Rule 35 (Exhibit
C); and (4) the GO 95 Appendix E Guidelines to Rule 35 (Exhibit D). These standards require
significantly increased clearances in a HFTD area. The time -of -trim guidelines do not establish a
mandatory standard, but instead provide guidance to utilities. The District will use specific
knowledge of growing conditions and tree species to determine the appropriate time of trim
clearance in each circumstance.
The District has developed a comprehensive Vegetation Management Plan (VMP) (References -
Attachment 1) that complies with the aforementioned statues. In addition, the VMP is subject to
periodic updates as practices and technology evolve.
As part of the District's Vegetation Management Plan, contractors and internal District staff are
equipped with District provided mobile devices to record the location and dates of vegetation
management related activities. Vegetation management generally consists of removing,
cutting, trimming, and clearing away of trees, tops, limbs, branches, bushes, vines, foliage, the
removal of hazard trees and inspection of legacy tree attachments in proximity to District
electrical lines, stations, and property within overhead electric rights -of -way. All tree trimming
inspection records are stored in the District's Geographic Information System (GIS) and are used
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for reporting yearly tree trimming progress and planning future tree trimming routes and
locations.
In addition to planned Tree Trimming, the District's Customer Information System (CIS) also
records customer calls regarding concern for potential tree hazards in proximity to electric lines.
Service Orders are created for crews to respond to and correct hazard tree reports, as well as
record the outcome of the hazard. This information can also be used for reporting the number of
customer calls regarding hazard trees, number of hazard tree removals, and number of
occurrences by location. This program began in 2005 and, continuing for 2021, the District will
be on a five year cutting cycle.
(Vegetation management practices within the District's service territory are governed by: Public
Resource Code 4292; Public Resource Code 4293; and, California General Order 95, Rule 35.)
The District meets or exceeds the minimum inspection requirements provided in CPUC GO 165,
Table 1 (Exhibit E) and CPUC GO 95, Rule 18 (Exhibit F). Pursuant to these rules, the District
inspects electric facilities in the High Fire Threat District areas more frequently than its
counterparts in non-HFTD areas. Additionally, District staff use their knowledge of the specific
environmental and geographical conditions to determine when areas may require more
frequent inspections. The District utilizes GO 95 and GO 165 as its guiding document, as part of a
robust asset manogement/maintenance program.
The District's GIS contains records for electric system inspections performed as part of the
General Order (G.0) Inspection program. District Crews are equipped with mobile devices with
access to the District's GIS data in order to record inspections and report any potential issues to
be corrected. Beginning in 2019, this inspection program was extended to capture potential tree
hazards in proximity to electric infrastructure. Corrections and repairs to the system are also
recorded as part of this program, and data is available to the District's engineering and
operations staff in order to plan repairs and upgrades to the electric system. This program began
in 2011.
The District's goal is to ensure that all inspections performed within its service territory are
complete before the beginning of the historic fire season, typically by June 1. The District
monitors drought conditions and other relevant factors throughout the year to determine if
inspections should be completed on an adjusted timeline.
If District staff discovers a facility in need of repair that is owned by an entity other than the
District, the District will notify the facility owner in writing, as well as notify the agency having
jurisdiction.
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I, FR3 INSULATING FLUID
Envirotemp FR3 fluid is a dielectric insulating fluid that is a natural ester derived from vegetable
oils. FR3 has an extremely high flashpoint, in excess of two times that of its traditional mineral oil
counterpart (360 degrees vs 160 degree Celsius). The District switched exclusively to FR3
dielectric insulating fluid in 2008 and it is now a requirement for all new oil insulated equipment,
including: transformers (pole bolted & pad -mounted); substation transformers; and substation
voltage regulators. Staff will evaluate the appropriateness of FR3 insulating fluid in its future
procurement of pad -mounted switchgear.
J. NON -EXPULSION CURRENT LIMITING FUSES
In 2019, the District started a pilot project in a Tier 3 neighborhood to evaluate the suitability of
non-expulsionary or current limiting fuses on its overhead system. Typical utility industry practice
is to install expulsion fuses on transformer and tap -lines as a means of protecting and isolating
parts of the system that have experienced a faulted condition.
Expulsion fuses utilize a silver -link element in an arc -tube that vents gas and potentially molten
metal to atmosphere as a means of extinguishing an arc created by a faulted condition. The
molten metal, however, can be a source of ignition for fire.
In contrast, while significantly more expensive, non-expulsionary current -limiting fuses are a non -
venting fuse encapsulated within a tube to contain the arc and gases, which minimizes the
potential for molten metals to be expelled. The District selected Eaton's Cooper Power full range
current limiting dropout ELF fuse for the Pilot project. The ELF fuse has been granted permanent
exemption by Cal Fire from pole clearance requirements as specifically listed in CCR Title 14,
section 1255.10.
As part of the District's ELF Fuse Pilot Project, all in -line and transformer fuse locations where an
ELF fuse has been installed is tracked in the GIS and tagged with ELF identifier. This allows the
District to track and report any outage or hazard occurrences on ELF fuses through the District's
Responder OMS. This program began in early 2019.
Staff completed the evaluation of the ELF fuses, validating and confirming their suitability and
effectiveness for the District's electric system. Beginning 2021, staff implemented a three year
capital improvement project and funding to replace all overhead fuses in the distribution system
with ELF fuses and non -load break cut-outs.
K. WORKFORCE TRAINING
The District has developed rules and complementary training programs for its workforce to
reduce the likelihood of an ignition. All field staff will be trained annually in the following areas: in
the content of the WMP; in proper use and storage of fire extinguishers; in required pre -job
briefings to discuss the potentials) for ignition, environmental conditions (current and forecasted
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weather that coincides with the duration of work for the day); and in identifying the closest fire
extinguisher.
L. RECLOSER OPERATIONAL PRACTICE
Annually, the District disables all automatic reclosing function for all Automatic Circuit Reclosers
(ACRs or reclosers) on its system, (i.e. one-shot operation). This ensures there will be no
automatic circuit reclosing during the fire season. Fire season is typically defined as early June
through early November but may be extended based on actual fire danger.
Operational needs may change due to extended/early winter conditions within the service
territory of the District. During these types of weather events the Electric Operations Manager or
his designee may suspend the summer one shot operation practice and return the automatic
system reclosers to normal operation. In the event there was the lack of winter precipitation,
reclosers may be placed on one shot early ahead of the summer months due to the dry
conditions.
M, DE-ENERGIZATiON
The District, in consultation with the local Truckee Fire District and water utility staff, has
evaluated the efficacy of a Public Safety Power Shutdown (PSPS) type of de-energization
program. Major considerations included: the Districts heavy -loading construction standards
which are hardened to withstand high wind, snow loading, and ice formation; the offset
between when the District's overhead electric distribution system experiences its most severe
weather threats (Le, severe winter storm(s) and the weather conditions during red -flag warnings
(i.e. typically in late Summer/Fall with only moderate weather threats); and the potential
negative impacts to fire response, water supply, public safety, and emergency communications
should a fire occur while the District de -energized a portion or all of its system.
The District, due to its location from 6,000 to 8,500 feet altitude, experiences severe winter
weather including blizzards and atmospheric river precipitation events. It is not uncommon for
these extreme weather events to include, in addition to rain, snow, and ice, winds in excess of
100 miles per hour. For these reasons, the District's overhead electric system is built to a heavy -
loading construction standard. In addition, during these extreme winter events the wildfire
threat is minimal.
During red flag warnings however, which again occur in late Summer/Fall, the winds that
accompany these events are typically a fraction of what the District's overhead electric
distribution system experiences in the winter and what our predominately pine forests can
withstand. During red flag warnings, the most likely cause of wildfire ignition is lightning strikes,
transportation, illegal fireworks, or recreation.
While the District is willing to take whatever steps are necessary to protect our community and
the public that we serve, the risks and potential consequences of initiating a PSPS-type event
are significant and extremely complex. Foremost concerns include: potential loss of water
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supply to fight wildfires due to loss of production wells and pumping facilities, negative impacts
to emergency response and public safety due to the historic disruptions in Internet and cell
phone service during periods of extended power outages, and the loss of key community
infrastructure and operational efficiency that occurs during power outages.
Based on the above considerations, the risks of implementing a PSPS-type program seem to for
outweigh the chances that the District's electric overhead distribution system would cause a
catastrophic wildfire. The District, on a case -by -case basis, has historically and will continue to
consider de -energizing a portion of its system in response to a known public safety issue or in
response to a request from an outside emergency management/response agency. Any de -
energizing will be performed in coordination with District water utility staff and key local partner
agencies. The District will also monitor the evolution of PSPS implementation by other California
electric utilities to continue to refine its evaluation of this important topic.
While the District has not implemented PSPS-type program for its system, the District's is a
Transmission Dependent Utility of NV Energy who, shortly after the District adopted the original
WMP, announced their own de -energizing program called Public Safety Outage Management
(PSOM). NV Energy originally included the District's service territory in their original program, later
removed the District's service territory from the program, for the 2019 and 2020 fire seasons, and
then included the District's service territory again in the program for the 2021 fire season. It is
again possible that, during extreme fire danger, the District could experience a system -wide
outage due to a loss of transmission from NV Energy which will likely be from a PSOM event.
As a result the District, and other key local agencies, held a series of meetings with NV Energy to
back in 2019 and again in 2021 to fully understand the conditions under which NV Energy would
de -energize transmission and to develop communication protocols so that NV Energy could
notify the District and the District could notify key agencies and our customers. The District has
developed a list of critical agencies/emergency responders with a commitment to make direct
contact should NV Energy announce a potential PSOM. The District has also conducted
extensive customer outreach to encourage customers to sign up for PSOM alerts. It should be
noted that NV Energy has not had any PSOM events in to date.
N. RE-ENERGIZATION
District staff, using the GIS system, have created Re-energization route maps to identify and
prioritize circuits for re-energization. In order to patrol the District's primary overhead lines in a
timely manner prior to re -energizing after an outage event, District staff have identified and
categorized patrol routes by access type for the electric system. This includes overhead lines
that can be patrolled by driving, walking, ATV, or helicopter.
These routes have also been created for patrolling District feeders in order to complete patrols in
the most efficient and timely manner possible. Driving routes for electric lines along roadways
have been created in order to eliminate or reduce back -tracking. In addition, drop off and pick
up locations for lines requiring walking or snow -shoeing have been identified in order to utilize
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electric crew time during an outage in the most efficient way possible and ensure that power is
restored both safely and quickly.
District staff used the GIS system to identify and create restoration maps based on priorities.
These include:
• Critical loads, (District Office, Fire, Police, Hospital, Telecom)
• TDPUD water facilities
• Circuit loading, (Customers per circuit)
• Residential vs. Commercial
Each feeder was ranked with a score of 1-17 based on the number of Total Customers (TC),
Critical Customer Count (CC), Residential Customer Count (RC), Commercial Customer Count
(CM), and number of TDPUD Water Faculties served (WF). The ranking score was then totaled to
determine a Total Priority Ranking (TC+CC+RC+CM+WF = Total Priority Ranking). This would be
the basis for restoration order, then physical circuit layout within the District was factored in to
determine the shortest patrol route and fastest restoration time.
This program began in the summer of 2019.
O. TREE ATTACHMENTS (LEGACY ATTACHMENTS)
The District has legacy attachments to trees that consist of: service drop(s); secondary
conductor(s); or, security lighting. Although these installations are permitted pursuant to Title 14
CCR § 1257, the District does not, and has not for nearly two decades, engage in this practice for
new installations,
Existing tree attachment service drops are tracked within the GIS in order to identify locations
where trees and branches may be a potential hazards to electric infrastructure and provide
District crews with location information for inspecting tree attachments. Legacy tree
attachments are no longer allowed. When an existing tree attachment fails or is damaged, a
new utility pole is installed and used for securing all secondary attachments.
Pursuant to Title 14 CCR § 1257; annually starting in 2020, contract tree crews are trimming the
area of the attachments and performing an inspection. Any hazard found is immediately
reported to District staff for mitigation. All new service installations will be fed from an
underground source and comply with Article P - Proposed Service Requirements.
P, PROPOSED SERVICE REQUIREMENTS
Since 1995, District code has required all new or reconstructed developments to take service
from the District via an underground system; however, limited exceptions exist in current District
Code for some single family residences. The District seeks to minimize the installation of
overhead power lines where practicable and will therefore, recommend an underground
requirement for all electric services and consider the following:
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• All new installations will be required to take service from an underground source;
• Like -for -like panel replacements will be required to convert to underground service;
• Upgraded panel replacements will be required to convert to underground service;
• The District will not attach to trees for any reason;
• The District may consider a cost -sharing program for customers that desire to convert an
existing overhead service to an underground service; and
• Customer(s) receiving service via legacy tree attachment(s) will be required to comply
with Article P - Proposed Service Requirements.
Q. COVERED PRIMARY JUMPER WIRE
The District is implementing the use of covered (i.e. Tree wire) primary jumper wire in place of
bare wire. Primary jumpers are used to connect transformers, UG risers and fuse cutouts to main
overhead circuit conductors. The use of covered primary jumper wires helps to minimize the
unintentional contact with wildlife and windblown debris. This practice will also help mitigate the
possibility of a flashover that may result in ignition of electrical facilities and the surrounding
areas. The District has also evaluated the use of covered conductors for the overhead
distribution system but, due mostly to the heavy loading district construction standards discussed
in the document, this option is not feasible.
VI. COMMUNITY OUTREACH AND PUBLIC AWARENESS
As a key public agency, the District has extensive relationships across all organizations in the
community. This includes direct interactions with the agencies directly responsible to fight fires
(Truckee Fire District and Cal Fire), agencies leading emergency response efforts (Town of
Truckee, Nevada County, and Placer County), along with key public and private land -owners
(United States Forest Service, California State Parks, Tahoe Donner Association, Tahoe -Truckee
Airport District, etc.). The local agencies and land -owners work collaboratively together to
educate each other and the community. District staff regularly provide information to these
agencies including updates on fire, vegetation management requirements, and District
programs.
It should be noted that, based on the above and due to the District's integral role in local
government, the District also does extensive communication and outreach regarding
vegetation management practices. This includes direct communication with property owners
and quick resolution of any concerns or disputes.
As the local electric and water utility, the District has robust community outreach and marketing
programs to effectively communicate with our customers and community. All Board meetings
are publicly agendized and the regularly scheduled Board meetings are broadcast live on local
TV (Truckee Tahoe Community Television), streamed live from the District's website
(www.tdl.,)ud _ r; ), and archived on District's website for access after the meeting.
The District is active in the community, typically attending dozens of community events each
year including: Truckee Day; Truckee Thursday's; Tahoe Truckee Earth Day; Truckee Home Show;
Truckee Farmers Market; Truckee Block Party; and Big Truck Day. The District staffs booths, has
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staff available to interact with the community, and delivers energy, water, and customer
programs directly to our customers. This includes providing information on the Districts
Vegetation Management Program, free de -energizing of customers overhead service
connections to allow them to clear defensible space while working safely, and educating the
community on the District's overall efforts to respond to catastrophic wildfires. While some of
these activities have been suspended during the COVID-19 pandemic, the District intends to
continue this effective engagement in the future.
The District also has robust marketing and communication efforts leveraging the website
(www.tdpud.gr), social medial (Facebook/Twitter/YouTube), bill stuffers, print ads, and digital
marketing. The District is a regular advertiser in the Sierra Sun, Moonshine Ink, Truckee Chamber
of Commerce, Tahoe Donner News, The Shire, and on KTKE 101.5 local radio. In addition, the
District hos an informative customer lobby designed to enhance customer engagement with
ready access to customers service representatives, extensive digital media to educate
customers, and engaging displays to capture the visitors attention.
With regards to fire -related community outreach, the District has been very active promoting the
Vegetation Management Program; including regulatory changes increasing the vegetation
clearances. The District sends out an annual bill insert to all customers along with information on
the website, social media, digital media, print advertising, and radio. The District has worked
with Tahoe Donner Association, which is located in a Tier 3 area and has almost half of the
District's residential connections, to include an extensive article in the monthly Tahoe Donner
News regarding fire, vegetation management, and everyone doing their part.
District staff previously participated in a local event (Wildfire Prevention and Preparedness Town
Hall) hosted in partnership by the Nevada County Office of Emergency Services, Truckee Police
Department & Emergency Services, and Truckee Fire Protection District. District staff set up a
table -top at the event to share information and participated in a panel discussion. Other
participants included: CAL FIRE, Placer County Office of Emergency Services, Fire Safe Council
of Nevada County, Placer County Fire Safe Alliance, Truckee Tahoe Unified School District,
Tahoe National Forest, Tahoe Forest Hospital, and California Highway Patrol, Participation in
similar events is expected for 2021.
For preparation of the original SB 901 Wildfire Mitigation Plan, District staff worked extensively with
Truckee Fire Protection District, CAL FIRE, Town of Truckee, Nevada & Placer Counties, and many
other local agencies and stakeholders. For the adoption of the original Plan, the District
conducted a publically agendized Board Workshop on wildfire, March 6, 2019, a second
Workshop specifically on the WMP in June 5, 2019, followed by formal adoption of the WMP by
the District's Board in July 17, 2019.
Since adoption of the plan by the District's Board in July of 2019, the WMP was reviewed by an
independent, third -party expert (Navigant Consultant) who confirmed that the District's WMP
meets the requirements of SB901. Novigant made a presentation to the District's Board in
December of 2019.
Annually the District presents WMP revisions to the Board for approval in June of each year prior
to submitting the WMP to the Wildfire Safety Advisory Board in July of the some year. Adoption
of the updated Plan will also be done via publically agendized meetings with final Adoption by
the District's Board on June 2, 2021,
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Although the District does not have a PSPS-type operational practice, it may de -energize a
portion or all of the overhead electric system for one of the following reasons:
• If an outside emergency management/emergency response agency request a power
shutdown;
• If the District elects to de -energize segments of its system due to extreme weather or
other safety consideration; or
• As a result of a NV Energy Public Safety Power Shut Off (PSOM) event or transmission
outage.
In such events that occur during wildfire season, the District staff will patrol the affected portions
of the system before the system can be re -energized. Suspect equipment or distribution lines
that cannot be patrolled will remain de -energized. In addition, system performance
abnormalities will be monitored via the District's SCADA system and its AMI/OMS systems. For
more information please see Re-energization on page 19.
In addition, TDPUD participates with California Emergency Management Agency (CEMA) and
California Utilities Emergency Association (CUEA). CEMA is a California agency responsible for
overseeing and coordinating emergency preparedness, response, recovery and homeland
security activities while CUEA serves as a point -of -contact for critical infrastructure utilities and
Cal OES before, during and after an event to facilitate communications, provide emergency
response and support emergency planning, mitigation, training, exercises and education.
A. METRICS AND ASSUMPTIONS FOR MEASURING PLAN PERFORMANCE
The District is tracking two metrics to measure the performance of this Plan:
(1) Number of fire ignitions; and
(2) Wire down events within the service territory
In 2019, District staff started capturing wire down and fires caused by District facilities in GIS. This
will help with reporting and identifying trouble areas in the future Metric
Metric 1: Fire Ignitions
For purposes of this metric, a fire ignition is defined as follows:
• The District's electrical infrastructure was associated with the fire;
• The fire was self -propagating and of a material other than electrical;
• The resulting fire traveled greater than one linear meter from the ignition point; and
• The District has knowledge that the fire occurred_
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To evaluate this metric, the District reports the number of fires that occurred that were less than
10 acres in size. Any fires greater than 10 acres will be individually described. Any ignition will be
reported to management and firefighting agencies.
In 2020, the District recorded two fire ignition events both of which resulted in the burning of the
cross arm and pole top. Neither event resulted in the ignition of vegetation.
Metric 2; Wires Down
The second metric is the number of wire -down events within the District's service territory. For
purposes of this metric, a wire -down event includes any instance where primary distribution
conductor falls to the ground or on to a foreign object, defined as: any object not specifically
an asset of the District (i.e. phone, cable, trees, etc.).
The District will not normalize this metric by excluding unusual events, (i.e. severe storms, car
versus pole incidents, or snow unloading). However, the District will supplement this metric with a
qualitative description of any such unusual events.
In 2020 the District recorded two wire down events.
The first was due to a hazard tree falling though primary. It should be noted that these lines were
de -energized prior to the tree falling and immediately upon discovery.
The second was due to a failed connection sleeve resulting in the line falling to the ground and
activating protective devices to de -energize the circuit.
B. IMPACT OF METRICS ON PLAN
It is important to note that the District anticipates relatively limited data will be gathered through
these metrics, particularly in the initial years. Therefore, it will be difficult to draw meaningful
conclusions based on this data. The District will evaluate modifying these metrics or adding
additional metrics in future years as more data becomes available and situational awareness
continues to improve.
C. MONITORING AND AUDITING THE PLAN
This Wildfire Mitigation Plan is subject to review by the District's Board of Directors. The District will
present this Plan to its Board on an annual basis.
The Electric Utility Director, or designee, will at least, on a semi-annual basis, update the General
Manager regarding the Plan's implementation, identified deficiencies or recommendations for
updating. Any critical or immediate concerns will be brought to the District's Board of Directors.
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D. IDENTIFYING AND CORRECTING DEFICIENCIES IN THE PLAN
Achieving a robust, all -encompassing plan to mitigate wildfire risk is the primary objective of this
document. Staff have the role of vetting current procedures and recommending changes or
enhancements to build upon non -optimized strategies in the Plan. Either due to unforeseen
circumstances, regulatory changes, emerging technologies, or other rationales, deficiencies
within the Plan will be sought out and reported to the Board, at a minimum, in the form of an
updated Plan on an annual basis.
The Electric Utility Director, or their designee, will be responsible for spearheading discussions on
correcting deficiencies when updating the Plan for its annual presentation to the Board. All
stakeholders are empowered to suggest improvement opportunities, including, but not limited
to: field crews; management; auditors; fire safety professionals; and, members of the public.
E. MONITORING THE EFFECTIVENESS OF INSPECTIONS
The District currently utilizes General Orders 95 (G095) and 165 (GO 165), respectively, as its guide
to inspect its system. Field staff routinely patrol the service territory and correct deficiencies as
they are encountered. The District tracks deficiencies that are repaired upon discovery within its
Geographical Information System (GIS) and consistent with the guidelines of GO 95 and 165,
respectively. Further, for deficiencies that cannot be repaired upon discovery, they are
assigned a priority level. The repairs are defined as Level 1 (highest), Level 2 (moderate), or
Level 3 (lowest) as defined by GO 95, Rule 18 (Exhibit F), with the discovery, remedy and
supporting documentation being tracked within the District's Geographical Information System
(GIS).
Monitoring the effectiveness of inspection practices will occur through ongoing tracking and
annual review of its findings including deficiencies found and corrective actions taken. The
Electric Operations Manager or their designee supervises the Vegetation Management Plan as
well as all routine field work and equipment and line inspections. Related strategies that mitigate
wildfire risk will be identified and proposed within the next iteration of the Plan. Aggregating this
data will guide future decision -making on the direction of the wildfire mitigation strategy with the
intention that incidents will become less frequent or less hazardous system wide.
District staff will report as part of its annual WMP presentation to the Board, the number of
deficiencies found; the number of deficiencies repaired within the defined priority timeline and
the number of outstanding deficiencies that were not repaired within the defined timeline.
In 2020, approximately 1300 deficiencies were identified and all deficiencies were corrected.
Public Utilities Code section 8387(c) requires the District to contract with a qualified independent
evaluator with experience in assessing the safe operation of electrical infrastructure to review
and assess the comprehensiveness of this Plan. The independent evaluator must issue a report
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to be posted on the District's website. This report must also be presented to the District's Board at
a public meeting. The District hired Navigant Consulting in 2019 to conduct the independent
audit. Navigant presented their finding to the District Board on December 4, 2019 and
concluded that:
1. TDPUD's WMP aligns appropriately with PUC Section 8387 and includes all required
elements
2. TDPUD's Plan is determined to be comprehensive
The District's WMP satisfied the requirements of SB 901 and this updated WMP considers the
recommendations of the independent auditor.
Exhibit A - California Public Utilities Commission Fire Threat Map, Adopted January 19, 2018/
Revised March 2021
Exhibit B - California Public Utilities Commission, Heavy loading district Map
Exhibit C - California Public Utilities Commission, General Order 95, Rule 35
Exhibit D - California Public Utilities Commission, General Order 95, Appendix E
Exhibit E - California Public Utilities Commission, General Order 165, Table 1, Distribution
Inspection cycles
Exhibit F - California Public Utilities Commission, General Order 95, Rule 18
14CCR § 1257
July 9, 2019 Memorandum, RE: Current Limiting Fuses
July 9, 2019 Memorandum, RE: Disabling of Automatic Circuit Reclosers (ACRs)
July 9, 2019 Memorandum, RE: Hotline Work during Extreme Weather or RFW Events
July 9, 2019 Memorandum, RE: Mandatory Reporting Requirements - Fire Ignition
July 9, 2019 Memorandum, RE: Mandatory Reporting Requirements - Wire Down
July 9, 2019 Memorandum, RE Re-Energization of Lines
July 9, 2019 Memorandum, RE: Tree Attachments
March 16, 2020 Memorandum 2020. 001, RE: Use of Bare # 6 Copper
March 16, 2020 Memorandum 2020-002, RE: Use of Hendrix Insulators
Public Resources Code section 4292
Public Resources Code section 4293
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Public Utilities Code Section 8387
State of California, General Order 95
State of California, General Order 165
Vegetation Management Plan (VMP), Attachment 1
Pole Replacement Ranking Tool, Attachment 2
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CPUC Fire -Threat Map
Adopted by the California Public Utilities Commission
(Revised in March 2021)
e data portrayed in the CPUC Fire -Threat Map were developed under Rulemaking 15-05-006, following
procedures in Decision (D.) 17-01-009, revised by D.17-06-024, which adopted a work plan for the
n development of a utility High Fire -Threat District (HFTD) for application of enhanced Fire safety regulations.
In accordance with the above -decisions, the HFTD Map is a composite of two map products. One of those
map products is this CPUC Fire -Threat Map. The CPUC Fire -Threat Map depicts areas where enhanced Fire
S. safety regulations found in Decision 17-12-024 will apply. The final CPUC Fire Threat Map was submitted to
the Commission via a Tier 1 Advice Letter that was adopted by the Commission's Safety and Enforcement
Division (SED) with a disposition letter on January 19, 2018. Subsequently, the Final CPUC Fire Threat Map
has been modified by the Commission. All data and information portrayed on the CPUC Fire -Threat Map are
for the expressed use called out in D.17-12 024, and any other use of this map is not the responsibility or
endorsed by the Commission or its supporting Independent Review Team.
W
Fire -Threat Areas
40 Tier 2 - Elevated
♦ Tier 3 - Extreme
Counties
0 1.5 30} * 60 90 120 a '"x N4
Miles
S
See Rules • 43.1 And 0 43.2
Exhibit C
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Pa a
General Order 95
Section III
Requirements for All Lines
35 Vegetation Management
Where overhead conductors traverse trees and vegetation, safety and reliability of
service demand that certain vegetation management activities be performed in order
to establish necessary and reasonable clearances the minimum clearances set forth in
Table I, Cases 13 and 14, measured between line conductors and vegetation under
normal conditions; shall be maintained. (Also see Appendix E for tree trimming
guidelines.) These requirements apply to all overhead electrical supply and
communication facilities that are covered by this General Order, including facilities on
lands owned and maintained by California state and local agencies.
When a supply or communication company has actual knowledge, obtained either
through normal operating practices or notification to the company, that dead, rotten
or diseased trees or dead, rotten or diseased portions of otherwise healthy trees
overhang or lean toward and may fall into a span of supply or communication lines,
said trees or portions thereof should be removed.
Communication and electric supply circuits, energized at 750 volts or less, including
their service drops, should be kept clear of vegetation in new construction and when
circuits are reconstructed or repaired, whenever practicable. When a supply or
communication company has actual knowledge, obtained either through normal
operating practices or notification to the company, that its circuit energized at 750
volts or less shows strain or evidences abrasion from vegetation contact, the
condition shall be corrected by reducing conductor tension, rearranging or replacing
the conductor, pruning the vegetation, or placing mechanical protection on the
conductor(s). For the purpose of this rule, abrasion is defined as damage to the
insulation resulting from the friction between the vegetation and conductor. Scuffing
or polishing of the insulation or covering is not considered abrasion. Strain on a
conductor is present when vegetation contact significantly compromises the structural
integrity of supply or communication facilities. Contact between vegetation and
conductors, in and of itself, does not constitute a nonconformance with the rule.
r - " - - r 1 1 • r, k • 1 1 1111111
1 ,r 1 lily r} .
1• r 4 r �- r r 1 1
EXCEPTIONS:
(1) Rule 35 requirements do not apply to conductors, or aerial cable that complies
with Rule 57.4-C, energized at less than 60,000 volts, where trimming or
removal is not practicable and the conductor is separated from the tree with
suitable materials or devices to avoid conductor damage by abrasion and
grounding of the circuit through the tree.
(2) Rule 35 requirements do not apply where the supply or communication
company has made a "good faith effort to obtain permission to trim or remove
vegetation but permission was refused or unobtainable. A "good faith" effort
shall consist of current documentation of a minimum of an attempted personal
contact and a written communication, including documentation of mailing or
delivery. The written communication may include a statement that the
company may seek to recover any costs and liabilities incurred by the company
due to its inability to trim or remove vegetation. However, this does not
preclude other action or actions from demonstrating "food faith". If permission
to trim or remove vegetation is unobtainable and requirements of exception 2
are met, the company is not compelled to comply with the requirements of
exception 1.
(3) The Commission recognizes that unusual circumstances beyond the control of
the utility may result in nonconformance with the rules. In such cases, the utility
may be directed by the Commission to take prompt remedial action to come
into conformance, whether or not the nonconformance gives rise to penalties or
is alleged to fall within permitted exceptions or phase —in requirements.
Note: Revised November 6.1992 by Resolution No. SU-15, Seaternber 20, 1996 by Derision No. 96-09-097
and January+ 23, 1997 W Uecis;ors No. 91-01-044.
(4) Mature trees whose trunks and major limbs are located more than six inches,
but less than the clearance required by Tablet. Caste 13E and14E, from
primary distribution conductors are exempt from the minimum clearance
requirement under this rule. The trunks and limbs to which this exemption
applies shall only be those of sufficient strength and rigidity to prevent the trunk
or limb from encroaching upon the six—inch minimum clearance under
reasonably foreseeable local wind and weather conditions. The utility shall bear
the risk of determining whether this exemption applies, and the Commission
shall have final authority to determine whether the exemption applies in any
specific instance, and to order that corrective action be taken in accordance
with this rule, if it determines that the exemption does not apply.
Note: Added October 22, 1991 by Uec7siun No. 97-10-056
Exhibit D
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General Order 95
Appendix E
Clearance of Poles, Towers and Structures from Railroad Tracks
The following are guidelines to Rule 35 .
The radial clearances shown below are recommended minimum clearances that
should be established, at time of trimming, between the vegetation and the energized
conductors and associated live parts where practicable. Reasonable vegetation
management practices may make it advantageous for the purposes of public safety
or service reliability to obtain greater clearances than those listed below to ensure
compliance until the next scheduled maintenance. Each utility may determine and
apply additional appropriate clearances beyond clearances listed below, which take
into consideration various factors, including: line operating voltage, length of span,
line sag, planned maintenance cycles, location of vegetation within the span, species
type, experience with particular species, vegetation growth rate and characteristics,
vegetation management standards and best practices, local climate, elevation, fire
risk, and vegetation trimming requirements that are applicable to State Responsibility
Area lands pursuant to Public Resource Code Sections 4102 and 4293.
Case
Case
Voltage of Lines
13 of
14 of
Table
Table
1
1
Radial clearances for any conductor of a line
operating at 2,400 or more volts, but less than
4 feet
12
feet
72,000 volt
Radial clearances for any conductor of a line
operating at 72,000 or more volts, but less than
6 feet
20
feet
110,000 volts
Radial clearances for any conductor of a line
operating at 110,000 or more volts but less than
10
feet
30
feet
300,000 volts
Radial clearance for any conductor of a line operating
15
30
at 300,000 or more volts
feet
feet
Note: Added November 6 1992 by Bg5olution -1 and revised September 20, 1996 by Decision No. 96
--09-097,. August 20 �004 by CkWsignN 2 January 12. 2012 by Decision No. 12-01-032,
December 21. 2017 by Decision 17-12-024.
Exhibit E
Table I
Distribution Inspection Cycles (Maximum Intervals in Years)
transformers _
Overhead 1 1 21 5 5 ---—
Underground 2 1�11 3
Padmounted 1 2 5 5 f_-- --
Switching/ Protective Devices
.-..Overhead ...- - 21 r 5 5 1---
Underground 1 �� 3 3 ---
Padmounted I 1 1 2 T! 5 ---
lRegulators/Capacitors
Overhead
Underground
Padmounted
1 I 2II
�1 mo�5 '7- F
1 I L I 3 F 3 I--- -__
Overhead Conductor and Cables F 21 5 5—�-j
Streetlighting V 1 1 L ���T--
Wood Poles under 15 years I l iF 2 x YF F ---
Wood Pales over 15 years which
have not been subject to intrusive 1 2 x Fx
10 10
inspection
Wood poles which passed intrusive , ___ ___ 20 20
inspection T
(1) Patrol inspections in rural areas shal be increased to once per year in Extreme and Very High Fire Threat Zones
in the following counties Imperial, Los Angeles, Orange, R verside, Santa Barbara, San Bernardino, San DGego,
and Ventura. Extreme and Very High Fire Threat Zones are designated on the Fire and Resource Assessment
Program (FRAP) Map prepared by the California Department of Forestry and Fire Protection or the modified
FRAP Map prepared by San Diego Gas & Electr c Company (SDG&E) and adopted by Decision 12-01-032 in
Phase 2 of Rulemak,ng 08.11-005. The fire -threat map is to be used to establish approximate boundaries and
Utdities should use thew own expertise and judgment to determine if local conditions require them to adjust the
boundar es of the map.
Note: This Generat Order does not apply to cathodic protection systems associated with natural gas facilities.
Note- For the purpose of implementing the patrol and detailed inspection intervals in Table i above, the term "year"
is defned as 12 consecutive calendar months starting the first fu'I calendar month after an inspection :s
performed, plus or minus two fu,l calendar months, not to exceed the end of the calendar year in which the
next inspection is due.
Exhibit F
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General Order 95
Section I
General Provisions
18 Reporting and Resolution of Safety Hazards Discovered by Utilities
For purposes of this rule, "Safety Hazard" means a condition that poses a significant
threat to human life or property.
A. Resolution of Safety Hazards And General Order 95 Nonconformances
(1) a) Each company (including utilities and CIPs) is responsible for taking
appropriate corrective action to remedy Safety Hazards and GO 9
nonconformances posed by its facilities.
b) Upon completion of the corrective action, the company's records shall
show, with sufficient detail, the nature of the work, the date, and the
identity of persons performing the work. These records shall be preserved
by the company for at least ten (10) years and shall be made available to
Commission staff upon 30 days notice.
c) Where a communications company's or an electric utility's actions result
in GO nonconformances for another entity, that entity's remedial action will
be to transmit a single documented notice of identified nonconformances to
the communications company or electric utility for compliance.
(2) a) All companies shall establish an auditable maintenance program for their
facilities and lines. All companies must include a timeline for corrective
actions to be taken following the identification of a Safety Hazard or
nonconformances with General Order 95 on the company's facilities.
The auditable maintenance program shall prioritize corrective actions
consistent with the priority levels set forth below and based on the
following factors, as appropriate:
• Safety and reliability as specified in the priority levels below;
• Type of facility or equipment;
• Location, including whether the Safety Hazard or nonconformance is
located in the High Fire -Threat District;
• Accessibility;
• Climate;
• Direct or potential impact on operations, customers, electrical
company workers, communications workers, and the general public.
There shall be 3 priority levels.
(i) Level1:
• Immediate safety and/or reliability risk with high probability
for significant impact.
• Take action immediately, either by fully repairing the
condition, or by temporarily repairing and reclassifying the
condition to a lower priority.
(ii) Level 2:
• Variable (non -immediate high to low) safety and/or reliability
risk.
• Take action to correct within specified time period (fully
repair, or by temporarily repairing and reclassifying the
condition to a lower priority).
Time period for correction to be determined at the time of
identification by a qualified company representative, but not to
exceed: (1) six months for nonconformances that create a fire
risk located in Tier 3 of the High Fire -Threat District; (2) 12
months for nonconformances that create a fire risk located in
Tier 2 of the High Fire -Threat District; (3) 12 months for
nonconformances that compromise worker safety; and (4) 59
months for all other Level 2 nonconformances.
(iii) Level 3:
• Acceptable safety and/or reliability risk.
• Take action (re -inspect, re-evaluate, or repair) as
appropriate.
b) Correction times may be extended under reasonable circumstances,
such as:
• Third party refusal
• Customer issue
• No access
• Permits required
• System emergencies (e.g. fires, severe weather conditions)
(3) Companies that have existing General Order 165 auditable inspection and
maintenance programs that are consistent with the purpose of Rule 18A
shall continue to follow their General Order 165 programs.
B. Notification of Safety Hazards
If a company, while performing inspections of its facilities, discovers a safety
hazards) on or near a communications facility or electric facility involving another
company, the inspecting company shall notify the other company and/or facility
owner of such safety hazard(s) no later than 10 business days after the discovery.
To the extent the inspecting company cannot determine the facility
owner/operator, it shall contact the pole owner(s), who shall be responsible for
promptly notifying the company owning/operating the facility with the safety
hazard(s), normally not to exceed five business days after being notified of the
safety hazard. The notification shall be documented and such documentation must
be preserved by all parties for at least ten years.
Note: Each pole owner must be able to determine all other pole owners on poles
it owns. Each pole owner must be able to determine all authorized entities that
attach equipment on its portion of a pole.
Note: Added August 20, 2009 by Decision No. 09-08-029 and revised January 12, 2012 by Decision No. 12-01-
032, gqr der 21, 2017 her p-cislan No. 17-12-024.
Vegetation
Management Plan
Revised: February 19, 2021
INDEX
Section
Page
Introduction 3
Service Area 3
Plan Description 3
Plan Personnel 4
Plan Operation Elements 5
Clearance Requirements 8
Regulatory Requirements 9
Exhibits 11
VEGETATION MANAGEMENT PLAN
Truckee Donner Public Utility District
Mission Statement — District Code, Title 1, Section 1.05.010
The Mission of Truckee Donner Public Utility District is to provide reliable, high quality water and
electrical power services while meeting customer demand, and to manage District resources in a
safe, open, responsible, environmentally sound manner at the lowest practical cost.
Introduction
The Truckee Donner Public Utility District (the District) has a responsibility to maintain vegetation so
as not to threaten the safety and integrity of electric facilities. The District's Vegetation Management
Plan (the Plan) is an important part of the District's effort to deliver safe, reliable and cost-effective
electric service to customers. The goals of the Vegetation Management Plan include: (1) ensuring
the safety of District Personnel and the public, (2) reduction of fire risks due to tree contacts or
electrical sparks igniting vegetation (3) the prevention of customer outages due to tree contacts, and
(4) aesthetics. The Plan is designed to meet the goals and objectives of the District, as well as State
and Federal requirements, as they relate to electric utility right-of-way maintenance.
Service Area
The District is a Public Utility District of the State of California engaged in the distribution, sale and
delivery of electric power and energy. The District is a transmission -dependent utility connected to
NV Energy's transmission system and is located high on the eastern slope of the Sierra Nevada. The
District is not interconnected with any other utility. The District's electric service territory is comprised
of approximately 44 square miles in eastern Nevada County and approximately 1.5 square miles in
adjacent Placer County. The electric system includes approximately 135 miles of 12.47 kV and 14.4
kV overhead distribution lines, and about one-half mile of 60kV overhead transmission lines. The
District has approximately 5,490 poles in its service territory, making the tree trimming budget one of
the largest annual operational expenses for the District.
Plan Description
The District is required by State and Federal law to prune or remove vegetation close to energized
electrical facilites for public safety and electric system reliability. The District adheres to all applicable
vegetation clearance requirements and performs regular vegetation managment in accordance with
State and Federal requirements, industry standards, and other procedures that help to prevent
outages and fires due to tree contact.
District staff are responsible for preparing work plans for annual vegetation management operations.
In addition, staff routinely performs quality control (QC) audits for ongoing work for adherance to
clearance requirements and to track progress throughout the year. Circuits are patrolled and
maintained on an ongoing basis, enabling the District to cover all overhead electiric lines on a
rotating five-year cycle.
While conducting routine vegetation management operations, the District responds to remove
identified high -risk fuel source vegetation, as needed. The District also performs inspections of
vegetation concerns for customers or when vegetation management contractors identify at -risk
vegetation while performing day-to-day operations. Staff is constently evaluating methods to improve
and enhance inspection procedures and vegetation operations.
Vegetation management generally consists of removing, cutting, trimming, and clearing away of
trees, tops, limbs, branches, bushes, vines, foliage, the removal of hazard trees and inspection of
legacy tree attachments in proximity to District electrical lines, stations, and property within overhead
electric rights -of -way.
Vegetation removal is performed by mechanical trimming in and around transmission and distribution
line circuits rights -of -way, from substations to the end of the circuits. An emphasis is placed on the
removal of tree branches and trees that are located within clearance limits, ground -level clearing
around poles, right-of-way vegetation clearance plus the removal of hazard trees that may be located
inside or outside of the right-of-way. The District does not perform vegetation removal operations in
the following areas:
Supply Service Drops
Supply service drops, or service wires, are defined as the overhead conductor from the
District's distribution pole line to the customers' service entrance or meter base
equipment. These overhead supply lines are generally energized at 240 volts. The District
does not perform vegetation management operaions along customer supply service
drops. Tree triming and maintaining the health of trees on private property is the
customer's or property owner's responsibility. The customer or property owner shall
maintain a 4 foot clearance at time of trim and a minimum 2 foot clearance from supply
service drops to trees and other vegetation at all times. Upon request, and during normal
business hours, the District will temporarily de -energize or remove the customer's
overhead secondary service line at no charge to the customer, thereby allowing for tree
trimming or maintenance work to be performed safely.
2. Padmounted Equipment
In areas served by underground electric facilities, padmounted equipment, including
transformers and switchgear, are placed at customer locations or select intervals along
main electric lines near streets and roads. Per District code, employees must be able to
access this equipment at any time for routine maintenance, troubleshooting, or emergency
repairs. This equipment must be visually and phylsically accessable to District crews at all
times. A clear working area must be maintained on all sides of padmounted equipment.
The door side shall have a 10 foor minimum clear working area. The non -door sides shall
have 3 foot minimum clear working area. Clear working area shall mean no fences,
shrubs, trees, landscape rocks or other obstructions. The customer or property owner
shall maintain these clear working areas for District access.
Plan Personnel
District crews consisting of licensed Journeymen Linemen perform tree trimming operations on an
as -needed basis. The majority of the Plan work is performed by licensed tree contractors specializing
in vegetation management operations for electric utiltities. Contracts for Vegetation Management are
signed for one year, with up to three, one year extensions.The District has very strict requirements
for selecting a tree contractor following the public procurement process. The contractor's field
supervisor must be a certified arborist with the International Society of Arboriculture. The Contractor
must employ only qualified line clearance tree trimming personnel meeting the requirements of
OSHA 29 CFR 1910.269, ANSI Standard Z133.1, and California Code of Regulation Title 8 Article
38 standards and requirements. In addition, the contractor must have a category D-49 Tree Service
Contractor license issued by the California Contractors State License Board and be a State of
California issued Licensed Timber Operator (LTO).
Plan Operation Elements
1. General
Vegetation management operations are performed by mechanical trimming or removal of trees and
other vegetation along distribution and transmission line circuits. These operations are performed in
a manner which creates minimum damage to the surrounding natural vegetation and landscape not
directly involved in the work. Ingress and egress to work areas are via existing roads, driveways,
access roads, etc. The work is performed so as to cause the least possible obstruction and
inconvenience to public traffic. Public vehicular and pedestrian traffic is allowed to travel through the
work area with a minimum of interruption or impedance unless otherwise required by safety
concerns. All traffic control and related devices conform to requirements set forth by the Town of
Truckee.
2. Scheduled Maintaince Cycle
Trees and vegetation are cleared from District facilities on a scheduled maintenance cycle. The
District's maintenance cycle goal is 5 years for all facilites. This means that trimming operations are
performed on the same portion of a distribution or transmission line typically once every 5 years. The
intent of the scheduled maintenance cycle is to perform trimming necessary to obtain clearance that
will last for the duration of the cycle. Other benefits include improved access to electric facilities and
reduced future maintenance costs. Facilities are worked in a systematic approach. Operations are
recorded by staff on the District's Geographical Information Systems (GIS) mapping database to
track maintenance cycle goals.
3. Right of Way Clearing
The District's right-of-way (ROW) includes public utility easements and electric service easements.
The District has the right of access to public utility easements and electric service easements for
purposes related to vegetation management including tree trimming, tree removal, right of way and
easement clearing. In the event a recorded easement does not exist, easements by prescription,
also called prescriptive easements, still exist, and under California Law give the District the same
rights as recorded easements for access to District facilities. The District has a 20 foot wide
prescriptive easement centered on all overhead and underground electric distribution facilities, and a
40 foot wide prescriptive easement centered on all overhead transmission (60kV) facilities. Any tree
regardless of size, that's located in the ROW may be removed due to present or future conflicts with
electrical facilities as determined by District staff. Best management practices (BMP) will be used on
ROW maintenance including cutting and trimming of all trees and shrubs to the extent necessary to
keep electric facilities clear of vegetation and to provide access for electric system operations and
maintenance. Refer to Exhibits for a graphical depiction of clearance requirements and ROW
clearing activities.
4. Notification of Customers and/or Property Owners
Customers and/or property owners are notified a minimum of twenty-four hours prior to any
scheduled vegetation management operations adjacent to private property. The notificaion includes
the type of work to be performed, including the trimming or removal of trees and the disposal of logs
and/or brush. This is typically done by placing "door hangers" or using other communication methods
to notify customers of impending work.
The work may also require temporary power interrruptions or planned outages to be performed
safely. This work shall be reviewed and authorized by the Electric Operations Manager or their
designee prior to the commencment of work. The customer notification contains information such as
contractor name, address, contact name, phone number, approximate time and duration of planned
outage, etc. including District contact information.
5. Types of Trimming
Natural pruning techniques are performed as recommended by the International Society of
Arboriculture and ANSI Standard A300.Operations avoid practices that can cause damage or injury
to the tree while achieving the required clearance objectives. Wherever possible, natural pruning
cuts are made to direct future growth and sprouting away from electric facilities.
a. Pruning: Tree pruning is performed so as to maintain the minimum clearance requirements
from electric conductors as shown in the Clearances section of this document. Dead
branches overhanging conductors are removed. Portions of dead or decaying trees or
portions of trees weakened by decay or disease that may contact conductors from the side or
by falling are pruned to eliminate the hazard.
b. Crown Reduction: Trees directly under conductors are pruned and shaped. The tree crown
is typically reduced and rounded into a symmetrical appearance as much as possible.
Conifers are pruned in a natural manner that allows them to retain as much of their natural
shape as possible.
c. Side Prunes: Where line clearance tree pruning adversely alters the shape of a tree,
additional pruning is performed to give such trees a better shape and appearance.
6. Tree Removal
s
Tree removal is performed for all trees that do not meet the clearance requirement from the tree
trunk to energized conductors and also for hazard trees. Hazard trees are trees with the potential to
fail and threaten the reliability of the District's overhead electric facilities. Hazard trees may be
located inside or outside of the District's right-of-way or easement. Hazard trees are defined as any
tree or portion of a tree that is dead, split, rotten, decayed or diseased and which may fall into or
onto electric facilities or trees leaning towards lines. Tree removal includes the falling of the entire
tree or crane removal. It also consists of the removal and disposal of trunks, limbs and branches.
Following best forest management practices, trees are cut off at ground level to leave a stump height
of no more then 3 inches to promote natural decay. The District is not responsible for the removal of
stumps.
7. Pole Clearing
The pole clearing program is an annual requirement to clear vegetation around poles that contain
electric apparatus in addition to wires in compliance with California Public Resources Code Section
4292. This Code applies to a majority of District poles.
In addition, ground level vegetation clearance and removal is performed to provide the required
firebreaks and to minimize new spring growth which are essential steps in reducing impacts to the
electrical distribution system due to wildland fires. Refer to Exhibits for a graphical depiction of
clearance requirements and ROW clearing activities.
8. Tree Attachments (Legacy Attachments)
The District has legacy attachments to trees that consist of: service drop(s); secondary conductor(s);
or, security lighting. Although these installations are permitted pursuant to California Code 14CCR §
1257, the District does not engage in this practice for new installations.
In order to ensure the integrity of these attachments, the District performs the following:
• Inspect legacy tree attachments and correct any hazardous condition found such as tree
growth around conductors, physical signs of damage, etc;
• Remove tree limbs on trees used as an attachment point(s) consistent with 14CCR §
1257;
• Accurately record attachment point(s) on GIS mapping database for audit purposes.
9. Control of Material and Clean Up
Tree branches and other vegetation less than 5 inches in diameter are chipped and removed from
the work area. Wood larger than 5 inches in diameter is cut into lengths for safe lifting purposes.
Wood larger than 5 inches in diameter is made available to District customers before removal by the
contractor. Customers on whose property a tree or trees have been removed or who are adjacent to
such work will have the first opportunity to use the wood collected from such trees before removal by
the contractor. The work is performed in an environmentally responsible manner with regards to any
and all material generated by the work.
The District may store timber logs temporaraly at the work site while efforts are made to arrange for
removal and transport to the mill or final storage facility. Upon completion of the work, the area is
cleaned to a condition at least equal to that which existed prior to the commencement of the work_
Clearance Requirements
The following table reflects the District's current minimum clearances required between conductors
and vegetation:
Clearance of Conductors to Vegetation
Trimmed
Minimum
Type of Clearance Clearance
Conductor Voltage .
Secondary 0 to 750v 4 ft. 2 ft.
Supply
Conductors
Primary 750v to 12 ft. (1, 3) 4 ft. (2,3,4&5)
Supply 22,500v
Conductors
Primary 22.5kV to 12 ft. (1, 3) 4 ft. (2,3& 4)
Supply 72.5kV
Conductors
Notes:
1. GO 95 Appendix E, Guidelines to Rule 35, Case 14, High Fire Threats
2. GO 95 Rule 35, Vegetation Management; Table 1, Case 14, High Fire Threats
3. CPUC Fire Threat Map: The CPUC has identified the District's service territory as a Tier 2
High Fire Threat District (HFTD), with the Tahoe Donner Subdivision identified as a Tier 3,
HFTD. Therefore, greater clearance requirements apply as compared to being in a non -fire
threat area.
4. California PRC Section 4293
5. The minimum clearance may be reduced to 6 inches for tree trunks and major limbs "of
sufficient strength and rigidity to prevent the trunk or limb from encroaching upon the 6 inch
minimum clearance under reasonable foreseeable wind and weather conditions'; GO 95
Rule 35, Tree Trimming, Exception No. 4.
Regulatory Requirements
The District performs vegetation managment in accordance with State and Federal requirements. In
addition, the District follows industry standards, and other procedures that help to prevent outages
and fires due to tree contact. These requirements, standards, and procedures include:
• California General Order No. 95, Rule 35 — Vegetation Management
This rule specifies the minimum radial clearance that must be maintained at all times from
energized conductors to vegetation.
• California General Order No. 95, Appendix E — Guidelines to Rule 35
This rule specifies the minimum radial clearance that must be maintained from energized
conductors to vegetation at time of trimming.
• California General Order No. 95, Rule 21.2 D — High Fire Threat District
This rule specifies the use of California Public Utility Commission (CPUC) Fire Threat Map
to identify fire threat level zones.
• GO 95 Rule 35, Vegetation Management; Table 1, Case 13, Radial Clearance
requirments
Radial clearance of bare line conductors from tree branches or foliage.
• GO 95 Rule 35, Vegetation Management; Table 1, Case 14, High Fire Threats
Radial clearance of bare line conductors from vegetation in Extreme and Very High Fire Threat
Zones.
• CPUC Fire Threat Map
This is the CPUC's statewide Fire Threat Map identifing areas of the state at an elevated
(Tier 2) or extreme (Tier 3) risk of power line ignitied wildfire.
• California Public Resources Code Section 4292
This law is administered by the California Department of Forestry and Fire Protection
(CALFIRE). The law requires the maintenance of a 10 foot radial firebreak around electric
utility poles that contain switches, fuses, transformers, or other electric equipment.
• California Public Resources Code Section 4293
This law is administered by CALFIRE. The law specifies the minimum clearance between
energized conductors and vegetation. It also requires the removal of dead, deseased, or
dying trees, or trees that could fall into electric lines. Such trees may be located inside or
outside of the right-of-way or easement areas.
• California Administrative Code, Title 8, Article 37 - Proximity to Overhead Lines
This code specifies minimum clearances between personnel and equipment working in
close proximity to overhear electric facilities.
• California Administrative Code, Title 8, Article 38 - Line Clearance Tree Trimming
Operations
This code specifies requirements for personnel performing line clearance tree trimming
operations.
• California General Order No. 165 — Inspection Requirements for Electric
Distribution and Transmission Facilities
This rule specifies the minimum cycle times for inspection of electric distribution and
transmission lines.
• ANSI A300.1 — Tree Care Operations - Pruning
This national standard addresses pruning practices for tree trimming operations.
• ANSI Z133 -Standard for Safety Requirements in Arboricultural Operations
This national standard addresses arboriculture safety requirements for pruning, repairing,
maintaining and removing trees, and for using equipment in such operations.
+ OSHA 29 CFR 1910.269 - Electric Power Generation, Transmission, and Distribution
This federal standard specifies requirements for worker safety in the electric power industry.
• 1SA Best Management Practices — Vegetation Managment
The International Society of Arboriculture (ISA) developed this BMP for the selection and
application of methods and techniques for vegetation control for electric rights -of -way.
• District and other standards as referenced in this document.
10
Exhibits
Vegetation Management Handouts
11
Required Clearances to
Vegetation for High Fire
Threat Areas
l of 12
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End of Document
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