HomeMy WebLinkAbout7 Consideration to Adopt 2020 Wildfire Mitiagation PlanAgenda Item #7
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Board of Directors
Stephen Moore
May 06, 2020
Consideration to Adopt the 2020 Wildfire Mitigation Plan
CONSENT
1. WHY THIS MATTER IS BEFORE THE BOARD
This item is before the Board for approval of the annual update of the Wildfire
MItigation Plan (WMP) as required by Senate Bill 901 (SB 901).
2. HISTORY
Staff presented wildfire mitigation overviews on March 6 and June 6, 2019, followed
by Board adoption of the District's Wildfire Mitigation Plan (WMP) on July 17, 2019.
The mandate of SB 901 required the adoption of a WMP and third party evaluation
before January 1, 2020. The evaluation is required to be from an independent, third
party expert and is required that the report be presented to the Board at a public
meeting for consideration. On October 16, 2019, the Board awarded a contract for
third party auditor services to Navigant Consulting, Inc. (Navigant) to review the WMP.
On December 4, 2019 staff presented the final wildfire mitigation overview and
presented Navigant's review of the District's WMP for the Board's consideration.
Navigant's review concluded that the District's WMP was consistent with SB 901 and
met the intent of the law. Navigant's review also identified areas to consider for future
revisions of the WMP.
3. NEW INFORMATION
Staff has completed preperation of the 2020 WMP (Attachment 1) in accordance with
the requirements of SB 901 and shared it with the following key local agencies who
were given the opportunity to comment:
Truckee Fire Protection District;
Town of Truckee Office of Emergency Services (OES);
Northern California Power Agency (NCPA).
The District has reviewed and revised the WMP with consideration given to Navigant's
final report and recommendation. During this process, internally tracked statistics and
wildfire mitigation best practices were reviewed to validate the effectiveness of the
WMP. SB 901 also requires that the District update the WMP annually and that it be
presented to the Districts Board for approval.
Joe Horvath Michael D. Holley
Electric Utility Director General Manager
Also per SB 901, the District's approved WMP must be submitted for review and
comment to the California Wildfire Safety Advisory Board (WSAB). The approved
WMP is required to be submitted to the WSAB by July 1, 2020 and annually
thereafter.
4. FISCAL IMPACT
The District’s efforts to respond to regulatory mandates and operational changes due
to wildfire has already had a significant fiscal impact. The direct costs of SB 901, in
addition to future unfunded mandates, is unknown. There is no cost associated with
this item, however, staff resource requirements to develop the WMP have been
significant.
5. RECOMMENDATION
Adopt the updated 2020 Wildfire Mitigation Plan and Direct staff to submit to the
California Wildfire Safety Advisary Board.
WILDFIRE
MITIGATION
PLAN
VERSION 1.2 (FIRST ANNUAL UPDATE)
May 1, 2020
T ABLE OF CONTENTS
I. Overview ................................................................................................................................................ 4
A. Utility Service Territory Description ……………………………………………………………………..4
B. Policy Statement ................................................................................................................................... 4
C. Purpose of the Wildfire Mitigation Plan ………………………………………………………………4
II. Objectives of the Wildfire Mitigation Plan …………………………………………………………..5
A. Minimizing Sources of Ignition............................................................................................................. 5
B. Resiliancy of the Electric Grid ............................................................................................................. 5
C. Minimizing Unnecessary or Ineffective Actions ............................................................................... 6
III. Roles and Responsibilities ................................................................................................................... 6
A. District Roles and Responsibilities ....................................................................................................... 6
B. Coordination with Water Utilities/Department................................................................................ 8
C. Coordination with Communication Infrastructure Providers ....................................................... 8
D. Standardized Emergency Management System ........................................................................... 8
IV. Wildfire Risks and Drivers associated with design, construction, operation, and
Maintenance ....................................................................................................................................... 10
A. Particular Risks and Risk Drivers Associated with Topographic and Climatological Risk
Factors .................................................................................................................................................. 10
B. Enterprisewide Safety Risks ................................................................................................................ 11
C. Changes to CPUC Fire Threat Map ................................................................................................. 11
V. Wildfire Preventative Strategies ........................................................................................................ 11
A. High Fire Threat District ....................................................................................................................... 11
B. Automated Metering Infrastructure (AMI) …………………………………………………………12
C. Outage Management System (OMS) ………………………………………………………………12
D. Supervisory Control and Data Acquisition (SCADA) …………………………………………….12
E. Weather Monitoring ......................................................................................................................... 123
F. Design and Construction Standards ............................................................................................. 133
G. Vegetation Management ................................................................................................................ 14
H. Inspections .......................................................................................................................................... 14
I. FR3 Insulating Fluid………………………………………………………………………………………15
J. Non-Expulsionary Current Limiting Fuses ....................................................................................... 15
K. Workforce Training…………………………………………………………………………………...….16
L. Recloser Operational Practice……………………………………………………………………….16
M. De-energization...…….……..………………………………………………………………….……….16
N. Re-energization ………………………………………………………………………………………....18
O. Tree Attachments (Legacy Attachment)……………………………………………….………….1 8
P. Proposed Service Requirements……………………………………………………………………..19
Q. Covered Primary Jumper Wire……………………………………………………………………….19
VI. Community Outreach and Public Awareness ............................................................................ 189
VII. Restoration of Service ........................................................................................................................ 20
VIII. Evaluating the Plan ............................................................................................................................. 21
A. Metrics and Assumptions for Measuring Plan Performance ....................................................... 21
Metric 1: Fire Ignitions .............................................................................................................................. 21
Metric 2: Wires Down ............................................................................................................................ 212
B. Impact of Metrics on Plan ................................................................................................................. 22
C. Monitoring and Auditing the Plan ................................................................................................... 22
D. Identifying and correcting Deficiencies in the Plan .................................................................... 22
E. Monitoring the effectiveness of inspections, ............................................................................... 223
IX. Independent Auditor .......................................................................................................................... 23
X. Appendix ……………………………...……………………………………………………………...….. 24
XI. References ……………………………………………………………………………………………......24
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I. OVERVIEW
A. UTILITY SE RVICE TERITORY DESCR IPTION
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 14,000 customers. The District is a Transmission-Dependent Utility
connected to NV Energy’s 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 servi ce 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 225 miles
total with 135 miles of 12.47 kV and 14.4 kV overhead distribution lines, and about one-half mile
of 60kV overhead transmission lines.
B. 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 stewa rdship 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.
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.
C. PURPOSE OF THE WILDF IRE MITIGATION PLAN
This Wildfire Mitigation Plan (WMP or Plan) describes the range of activities the District takes to
mitigate the threat of District equipment ignited wildfires. Included in within the Plan is an
explanation of various programs, practices, and procedures the District utilizes to comply with SB
901.
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This Plan is subject to direct approval by the District’s Board of Directors and is implemented by
the General Manager. The District’s Board adopted the initial WMP on July 17, 2019 and this is
the first annual update. This Plan complies with the requirements of Public Utilities Code Section
8387 for publicly owned electric utilities to prepare a wildfire mitigation Plan by January 1, 2020,
and annually review it thereafter.
D. ORGANIZATION OF THE WILDFIRE MITIGATION PLAN
This Wildfire Mitigation Plan includes the following elements:
Objectives of the Plan;
Roles and responsibilities for executing the Plan;
Identification of key wildfire risks and risk drivers;
Description of wildfire prevention strategies;
Metrics for measuring performance of the Plan and identifying areas for improvement;
and
Community outreach and education.
II. OBJECTIVES OF THE WI LDFIRE MITIGATION PLAN
A. MINIMIZING SOURCES O F IGNITION
The primary goal of this Plan is to minimize the probability the District’s distribution system may be
an original or contributing source of ignition. 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.
The District utilizes the California Public Utility Commission (CPUC) state-wide Fire Threat Map
(Map) adopted January 19, 2018 (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).
B. RESI LIE NCY OF THE ELECTRIC GRID
The secondary goal 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
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Plan, the District assesses new industry practices and technologies that may reduce the
likelihood of a disruption in service or improve the timeline for restoration of service.
To accomplish this, the District utilizes heavy-loading construction standards that are designed to
withstand sustained heavy winds; covered jumper wire (where practicable); FR3 insulating fluid;
current limiting fuses; and vegetation management, among other operational practices. The
Districts distribution system 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 goal for this Plan is to measure the effectiveness of specific mitigation strategies as they
apply to the District. Where a particular action, program, or protocol is determined to be
unnecessary or ineffective, the District will evaluate 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 VIII. D – Identifying and correction deficiencies.
III. ROLES AND RESPONSIBI LITIES
A. DISTRICT ROLES AND RESPONSIBILITIES
Truckee Donner Public Utility District
TDPUD
Customers
Board of
Directors
General
Manager
PIO / Strategic
Affairs Director
Electric Utility
Director / Asst.
General Manger
Electric
Operations
Manager
Electric
Engineering
Manager
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The District utilizes a Board/General Manager reporting hierarchy.
Board members are elected at large by District customers to rotating 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 of all policy and delegates the operational implementation of
policy to the General Manager.
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 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; 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.
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.
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.
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B. COORDINATION WITH WA TER UTILITIE S /DEPARTMENT
The District owns and operates a Water Utility within its service territory, providing retail service to
approximately 13,000 customers. 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, 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 I NFRASTRUCTURE
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 https://www.tdpud.org/i-want-to/outagecenter. 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,1 the District has planning, communication, and coordination
obligations pursuant to the California Office of Emergency Services’ Standardized Emergency
Management System (“SEMS”) Regulations,2 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.3 Pursuant to this structure, the District regularly coordinates and
1As defined in Cal. Gov. Code § 8680.2.
2 19 CCR § 2407.
3 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
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communicates with the relevant safety agencies as well as other relevant local and State
agencies.
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 made 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 Nevada County, overseen
by the Nevada County Operational Area Emergency Services Council (NC-ESC). The NC-ESC
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 NC-ESC, when requested by an emergency
the operational areas and the state level. This level along with 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
disaster response system.
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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
nationwide access to resources for system restoration and support after a major event that
exhausts District resources.
IV. WILDFIRE RISKS AND D RIVERS ASSOCIATED WITH DESIGN,
CONSTRUCTION, OPERAT ION, AND MAIN TENANCE
A. PARTICULAR RISKS AND RISK DRIVERS ASSOCIA TED WITH
TOPOGRAPHIC AND CLIM ATOLOGICAL RISK FACT ORS
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 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:
Climate change;
Extended drought;
Vegetation type;
High winds;
Mountainous terrain/accessibility;
Tree mortality;
Lightning;
Increased population; and
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Lack of early fall precipitation.
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 impac t recover. RA will be used to analyze
safety risks, which include:
Pole Replacement Ranking Tool (Attachment 2);
Unavailability of NV Energy’s transmission (Donner Lake Substation & Tahoe Donner
Substation) interconnection & its distribution interconnect ion (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
The District does not recommend any changes to the CPUC state-wide Fire Threat Map,
adopted January 19, 2018, at this time. Future changes in District knowledge or
recommendations going forward will be communicated as required by statute.
V. WILDFIRE PREVENTATIV E STRATEGIES
A. HIGH FIRE THREAT DIS TRICT
The District participated in the development of the California Public Utilities Commission’s (CPUC)
Fire-Threat Map,4 which designates the HFTD. 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 High Fire Threat District into its construction,
inspection, operation, maintenance, repair, and vegetation management practices.
The Fire Threat Areas as designated by both CalFire and the CPUC have been in corporated 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.
B. AUTOMATED METERING I NFRASTRUCTURE (AMI)
4 Adopted by CPUC Decision 17-12-024.
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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 and remotely measure electricity
use, connect and disconnect services, detect tampering, identify and isolate outages, and
monitor voltages.
C. OUTAGE MANAGEMENT SY STEM (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 reclosures 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 field
reclosures, a function which is currently unavailable. These functions would allow the District to
remotely turn all reclosures on to Non-reclose (One Shot) 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.
E. WEATHER MONITORING
The District 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;
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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 ne cessary 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: If the National Weather Service declares a Red Flag Warning (RFW) for any
portion of District’s service territory, 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.
F. DESIGN AND CONSTRUCTION STANDAR DS
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
a 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). 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.
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G. VEGETATION MANAGEMEN T
The District meets or exceeds minimum State standard(s) for vegetation management practices.
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 circumstanc e.
The District has developed a comprehensive Vegetation Management Plan (VMP) (Attachment
1) that complies with the aforementioned statues. In addition, the VMP is subject to updates
from time-to-time as practices and technology evolve .
As part of the District’s Tree Trimming Program, contractors and internal District staff are
equipped with District provided mobile devices to record the location and dates of tree
trimming work. All tree trimming inspection records are stored in the District’s Geographic
Information System (GIS) and are used 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 2020, 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.)
H. INSPECTIONS
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 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
management/maintenance program.
The District’s GIS contains records for electric system inspections performed as part of the
General Order (G.O) 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
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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.
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). With the exception of padmounted
switchgear, the District switched exclusively to FR3 dielectric insulating fluid circa 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 padmounted switchgear.
J. NON -EXPULSIONARY CURRENT LIMITING FUSES
In 2019, the District started a pilot project in a Tier 3 neighborhood to evaluate the suitability of
non-expulsionary 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 fault ed condition. The
molten metal, however, can be a source of ignition for fire.
In contrast, 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 CalFire 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.
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Staff completed the evaluation of the ELF fuses, validating and confirming their suitability and
effectiveness for the District’s electric system. Beginning 2021, staff will be implementing a three
year capital improvement project and funding to replace all overhead fuses in the distribution
system with ELF fuses.
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 content of the
WMP; in proper use and storage of fire extinguishers; in required pre-job briefings to discuss the
potential(s) for ignition, environmental conditions (current and forecasted 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 will disable 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
district. During these types of weather events the Electric Operations Manager or h is designee
may suspend the summer one shot operation practice and return the automatic system
reclosures to normal operation. In the event there was the lack of winter precipitation, reclosures
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). 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 (i.e. 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.
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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 are significant
and extremely complex. Foremost concerns include: potential loss of water 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 program seem to far
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 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). It is 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
fully understand the conditions under which NV Energy would de -energize transmission and to
develop communication protocols so that NV Energy could notify the Dist rict 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 cond ucted extensive customer outreach to
encourage them to sign up for PSOM alerts. It should be noted that NV Energy did not have any
PSOM events in 2019
N. RE-ENERGIZATION
District staff, using the GIS system, have created Re-energization route maps. 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.
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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
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 Dist rict 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 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 and any time an attachment is removed due to a fallen
tree or other reason a utility pole is installed in its place
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 circa 1995, District code has required all new or reconstructed developments to take
service from the District via an underground system; however, exceptions exist in current District
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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:
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 PRIM A RY 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.
V I . COMMUNITY OUTREACH AND PUBLIC AWARENESS
As a key publicly-owned 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 req uirements, and District
programs.
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.tdpud.org), and archived on District’s website for access after the me eting.
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 Da y. The District staffs booths, has
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
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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.
The District also has robust marketing and communication efforts leveraging the website
(www.tdpud.org), 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 has a new 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 the recent regulatory cha nges 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 2020.
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. 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. Navigant made a presentation to the District’s Board in
December of 2019.
VII. RESTORATION OF SERVI CE
Although the District does not have a PSPS operational practice, it may participate 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
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As a result of a NV Energy Public Safety Power Shut Off (PSOM) event.
In such events 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.
VIII. EVALUAT ING THE PLAN
A. METRICS AND ASSUMPTI O NS 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
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.
In future Wildfire Mitigation Plans, the District will provide 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.
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.).
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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.
B. IMPACT OF METRICS ON PLAN
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 AUDITIN G 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.
D. IDENTIFYING AND CORR ECTING 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 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 EFFEC TIVENESS OF INSPECTI ONS
The District currently utilizes General Orders 95 (GO95) and 165 (GO165), 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
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supporting documentation being tracked within the District’s Geographical Information System
(GIS).
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.
IX. INDEPENDENT AUDITOR
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
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 901and this updated WMP considers the
recommendations of the independent auditor.
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X. APPENDIX
Exhibit A – California Public Utilities Commission Fire Threat Map, Adopted January 19, 2018
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
XI. REFERENCES
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
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
Vegetation
Management Program
Legacy: July 2, 2018
Revised: October 29, 2019
1
INDEX
Section Page
Introduction 2
Service Area 2
Program Description 2
Regulatory Requirements 3
Clearance Requirements 5
Program Personnel 6
Program Operation Elements 6
2
VEGETATION MANAGEMENT PROGRAM
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, en vironmentally sound manner at the
lowest practical cost.
Introduction
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 Program (the Program) 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 Program include: (1) ensuring
the safety of District linemen and the general public, (2) re duction of fire risks due to tree
contacts or electrical sparks igniting brush, (3) the prevention of customer outages due to tree
contacts, and (4) aesthetics. The Program 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 system and is located high on the e astern 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.
Program 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. 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.
3
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 that contain transformers and switches, 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:
1. 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 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 must
maintain a minimum 2 foot clearance f rom supply service drops to trees and other
vegetation. 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. District employees must
be able to access this equipment at any time for routine maintenance,
troubleshooting, or emergency repairs. This equipment must be visually and
phyisically 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 must
maintain these clear working areas for District access.
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.
4
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.
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.
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OSHA 29 CFR 1910.269 - Electric Power Generation, Transmission, and
Distribution
This federal standard specifies requirements for worker safety in the electric power
industry.
ISA 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.
Clearance Requirements
The following table reflects the District’s current minimum clearances required between
conductors and trees:
Clearance of Conductor to Vegetation
Trimmed Minimum
Type of
Conductor
Voltage
Clearance Clearance
Secondary
Supply
0 to 750v 4 ft. 2 ft.
Conductors
Primary
Supply
Conductors
750v to
22,500v
12 ft. (1., 3.)
4 ft. (2.,3.,4.&5.)
Primary
Supply
22.5kV to
72.5kV
12 ft. (1., 3.) 4 ft. (2.,3.& 4.)
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 requiremen ts apply as compared to
being in a non-fire threat area.
4. California PRC Section 4293
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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.
Program Personnel
District crews consisting of licensed Journeymen Linemen perform tree trimming operations
on an as-needed basis. The majority of the Program work is performed by licensed tree
contractors specializing in vegetation management operations for electric utiltities. 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
trimmer personnel meeting the requirements of OSHA 29 CFR 1 910.269, 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 a State of California issued Licensed
Timber Operator, (LTO)
Program 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 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
required by safety concerns. All traffic control and related devices conf orm 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
program. 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 program 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
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District's Geographical Information Systems mapping database to track maintenance cycle
goals.
3. Notification of Customers and/or Property Owners
Customers and/or property owners are notified a minimum of twenty-four hours prior to any
scheduled tree trimming 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 communicated to and authorized by the Electric
Operations Manager or his designee prior to the commencment of work. The customer
communication contains information such as contractor name, address, contact name, phone
number, approximate time and duration of planned outage, etc. including District contact
information.
4. 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 objective s. 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 Clea rances 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.
5. Tree Removal
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
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may be dead, dying, diseased, damaged, leaning or otherwise structurally unsound trees that
could fall into electric facilities. Tree removal includes the falling of the entire tree and the
removal and disposal of trunks, limbs and branches.
6. Pole Clearing
Pole clearing consists of removing all plant material including grasses or low-lying shrubs, for
a distance of not less than 10 feet in all directions from the outer circumference of an electric
utility pole, for firebreak purposes. Pole clearing operations, as required by California PRC
Section 4292, are only performed around poles that contain switches, fuses, transformers, or
other electric equipment.
7. Tree Attachements (Legacy Attachments)
The District has legacy attachments to trees that consist of: service drop(s); secondary
conductor(s); or, security lighting. Although these installations were permitted pursuant to
14CCR § 1257, The District does not engage in this practice for new installations.
The Contractor shall:
Inspect Legacy Tree Attachments and immediately notify a District Representative
if a hazardous condition is found such as tree growth around conductors, physical
signs of damage, etc;
Ensure that limbing of a tree used as an attachment point(s) will be consistent with
14CCR § 1257;
Accurately report attachment point(s) inspected for District audit purposes.
8. 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. 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.
End of Document
11/6/2019 Page 1
Pole Replacement Ranking Tool
BACKGROUND
In March 2017 District staff initiated a project to prioritize utility pole replacements based on
quantitative data. Prior to that, pole replacements associated with Master Plan line upgrades were
given priority and other replacements were prioritized by Operation’s intuition with limited logical
rationale. Staff recognized the importance of prioritizing projects considering Safety, Reliability and
Code Compliance.
There are approximately 5400 poles maintained by the District. Assuming a service life of 30-50 years
approximately 100 to 180 poles should be replaced annually for an asset management/preventative
maintenance program. Planning is required to achieve this rate of annual pole replacements and insure
engineering, vegetation management, and joint pole planning proceed at a similar rate in advance of the
replacement.
THE TOOL
The Pole Replacement Ranking tool uses GIS feature attributes to assign a score to each pole feature
based on the equation:
Replacement Score = Age Score + Condition Score + Critical Asset Score + Reliability Score
This score then becomes an attribute of the pole feature in GIS. The replacement score attribute is then
mapped in GIS to provide a visual report of pole replacement priority. The score factors and associated
weights are:
Age 30%
Condition 40%
Critical Asset 20%
Reliability 10%
The maximum score for a pole is 100 pts (100%). The weight assigned to each score represents the
estimated risk associated with leaving a given pole in service.
Age and Condition establish a ‘health’ score for the pole. Poles under 35 years old are considered low
risk and are assigned an age score of zero. As poles age the age score increases as noted below. The
Condition score is a rating from 1 (best) to 5 (worst) recorded in the GO165 inspection Poles Requiring
Replacement reports.
Age (years) Score
60 or older Oldest 30
55-59 25
50-54 20
45-49 15
40-44 10
35-39 5
0-34 Newest 0
Condition Score
1 Best 8
Pole Replacement Ranking Tool
11/6/2019 Page 2
2 16
3 24
4 32
5 Worst 40
The Critical Asset factor ranks facilities based on the impact an event on a given pole could have on
Safety, Reliability and Compliance.
Attribute ID Asset Score
1 Distribution 20
2 Secondary 15
4 Guy 5
3 Street Light 0
5 Transmission 0
6 Broadband 0
7 Tree 0
While an event on a Transmission pole could have a significant impact on the distribution system, these
facilities are not owned by the DISTRICT so not included in the pole replacement tool. Currently the tool
assigns the Tree asset a zero score as trees typically have secondary/service attachments and, if the tree
fails, then the impact on the distribution system is limited. With the increased emphasis on wildfire
mitigation and the District’s stance on tree attachments, this weighting may be reconsidered.
The Reliability score is based on outage management system (OMS) data and reflects the frequency of
events on a given device. The Reliability score is currently under development and not yet included in
the total Replacement Score, and as such, the maximum score at this time is 90 pts. It is envisioned this
score will be associated with events at devices and related to poles on associated feeders or taps.
The final Replacement Score is mapped in GIS by range.
Score Range Color
71-100 Red
61-70 Orange
51-60 Yellow
31-50 Light Green
<30 Dark Green
Below is the District map with the top 2 ranges shown.
Pole Replacement Ranking Tool
11/6/2019 Page 3
FUTURE TOOL IMPROVEMENTS
Add OMS/Responder information by device and associated weights to the tool in the Reliability factor.
Add patrol inspection data to the Condition Factor.