Fac-003-5

FAC-003-5.pdf

FERC-725D Mandatory Reliability Standards: FAC-Standards

FAC-003-5

OMB: 1902-0247

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FAC‐003‐5 Transmission Vegetation Management

A. Introduction
1.

Title:

Transmission Vegetation Management

Number:

FAC‐003‐5

Purpose:

To maintain a reliable electric transmission system by using a defense‐
in‐depth strategy to manage vegetation located on transmission rights
of way (ROW) and minimize encroachments from vegetation located
adjacent to the ROW, thus preventing the risk of those vegetation‐
related outages that could lead to Cascading.

Applicability:
4.1. Functional Entities:
4.1.1. Applicable Transmission Owners
4.1.1.1. Transmission Owners that own Transmission Facilities defined in
4.2.
4.1.2. Applicable Generator Owners
4.1.2.1. Generator Owners that own generation Facilities defined in 4.3.
4.2. Transmission Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal,1 state,
provincial, public, private, or tribal entities:
4.2.1. Each overhead transmission line operated at 200kV or higher.
4.2.2. Each overhead transmission line operated below 200kV, identified by the
Planning Coordinator or Transmission Planner, per its Planning
Assessment of the Near‐Term Transmission Planning Horizon as a Facility
that if lost or degraded are expected to result in instances of instability,
Cascading, or uncontrolled separation that adversely impacts the
reliability of the Bulk Electric System for a planning event.
4.2.3. Each overhead transmission line operated below 200 kV identified as an
element of a Major Western Electricity Coordinating Council (WECC)
Transfer Path in the Bulk Electric System by WECC.
4.2.4. Each overhead transmission line identified above (4.2.1. through 4.2.3.)
located outside the fenced area of the switchyard, station or substation
and any portion of the span of the transmission line that is crossing the
substation fence.

1 EPAct

2005 section 1211c: “Access approvals by Federal agencies.”

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FAC‐003‐5 Transmission Vegetation Management

4.3. Generation Facilities: Defined below (referred to as “applicable lines”), including
but not limited to those that cross lands owned by federal,2 state, provincial,
public, private, or tribal entities:
4.3.1. Overhead transmission lines that (1) extend greater than one mile or
1.609 kilometers beyond the fenced area of the generating station
switchyard to the point of interconnection with a Transmission Owner’s
Facility or (2) do not have a clear line of sight3 from the generating station
switchyard fence to the point of interconnection with a Transmission
Owner’s Facility and are:
4.3.1.1. Operated at 200kV or higher; or
4.3.1.2. Operated below 200kV and are identified by the Planning
Coordinator or Transmission Planner, per its Planning
Assessment of the Near‐Term Transmission Planning Horizon as a
Facility that if lost or degraded are expected to result in instances
of instability, Cascading, or uncontrolled separation that
adversely impacts the reliability of the Bulk Electric System for a
planning event; or
4.3.1.3. Operated below 200 kV identified as an element of a Major
WECC Transfer Path in the Bulk Electric System by WECC.
5.

Effective Date: See Implementation Plan

Background: This standard uses three types of requirements to provide layers of
protection to prevent vegetation related outages that could lead to Cascading:
a)

Performance‐based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results‐based requirement has four
components: who, under what conditions (if any), shall perform what action, to
achieve what particular bulk power system performance result or outcome?

Risk‐based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk‐based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what
particular result or outcome that reduces a stated risk to the reliability of the bulk
power system?

Competency‐based defines a minimum set of capabilities an entity needs to have
to demonstrate it is able to perform its designated reliability functions. A
competency‐based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or

2 Id.
3 “Clear

line of sight” means the distance that can be seen by the average person without special instrumentation (e.g.,
binoculars, telescope, spyglasses, etc.) on a clear day.

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FAC‐003‐5 Transmission Vegetation Management

outcome to perform an action to achieve a result or outcome or to reduce a risk
to the reliability of the bulk power system?
The defense‐in‐depth strategy for Reliability Standards development recognizes that
each requirement in a NERC Reliability Standard has a role in preventing system
failures, and that these roles are complementary and reinforcing. Reliability Standards
should not be viewed as a body of unrelated requirements, but rather should be
viewed as part of a portfolio of requirements designed to achieve an overall defense‐
in‐depth strategy and comport with the quality objectives of a Reliability Standard.
This standard uses a defense‐in‐depth approach to improve the reliability of the
electric Transmission system by:
•

Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash‐over clearance (R1 and R2);

•

Requiring documentation of the maintenance strategies, procedures, processes
and specifications used to manage vegetation to prevent potential flash‐over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);

•

Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash‐over at any moment (R4);

•

Requiring corrective actions to ensure that flash‐over distances will not be
violated due to work constrains such as legal injunctions (R5);

•

Requiring inspections of vegetation conditions to be performed annually (R6); and

•

Requiring that the annual work needed to prevent flash‐over is completed (R7).

For this standard, the requirements have been developed as follows:
•

Performance‐based: Requirements 1 and 2

•

Competency‐based: Requirement 3

•

Risk‐based: Requirements 4, 5, 6 and 7

Requirement R3 serves as the first line of defense by ensuring that entities understand
the problem they are trying to manage and have fully developed strategies and plans
to manage the problem. Requirements R1, R2, and R7 serve as the second line of
defense by requiring that entities carry out their plans and manage vegetation.
Requirement R6, which requires inspections, may be either a part of the first line of
defense (as input into the strategies and plans) or as a third line of defense (as a check
of the first and second lines of defense). Requirement R4 serves as the final line of
defense, as it addresses cases in which all the other lines of defense have failed.

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FAC‐003‐5 Transmission Vegetation Management

Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the standard requirements for applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial
lands, public or private lands, franchises, easements or lands owned in fee, will reduce
and manage this risk. For the purpose of the standard the term “public lands”
includes municipal lands, village lands, city lands, and a host of other governmental
entities.
This standard addresses vegetation management along applicable overhead lines and
does not apply to underground lines, submarine lines or to line sections inside an
electric station boundary.
This standard focuses on transmission lines to prevent those vegetation related
outages that could lead to Cascading. It is not intended to prevent customer outages
due to tree contact with lower voltage distribution system lines. For example,
localized customer service might be disrupted if vegetation were to make contact with
a 69kV transmission line supplying power to a 12kV distribution station. However, this
standard is not written to address such isolated situations which have little impact on
the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses
an increased outage risk, especially when numerous transmission lines are operating
at or near their Rating. This can present a significant risk of consecutive line failures
when lines are experiencing large sags thereby leading to Cascading. Once the first
line fails the shift of the current to the other lines and/or the increasing system loads
will lead to the second and subsequent line failures as contact to the vegetation under
those lines occurs. Conversely, most other outage causes (such as trees falling into
lines, lightning, animals, motor vehicles, etc.) are not an interrelated function of the
shift of currents or the increasing system loading. These events are not any more
likely to occur during heavy system loads than any other time. There is no cause‐
effect relationship which creates the probability of simultaneous occurrence of other
such events. Therefore these types of events are highly unlikely to cause large‐scale
grid failures. Thus, this standard places the highest priority on the management of
vegetation to prevent vegetation grow‐ins.

B. Requirements and Measures
R1.

Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the Minimum Vegetation Clearance
Distance (MVCD) of its applicable line(s), operating within their Rating and all Rated

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FAC‐003‐5 Transmission Vegetation Management

Electrical Operating Conditions of the types shown below4 [Violation Risk Factor:
High] [Time Horizon: Real‐time]:
1.1. An encroachment into the MVCD as shown in FAC‐003‐Table 2, observed in Real‐
time, absent a Sustained Outage,5
1.2. An encroachment due to a fall‐in from inside the ROW that caused a vegetation‐
related Sustained Outage,6
1.3. An encroachment due to the blowing together of applicable lines and vegetation
located inside the ROW that caused a vegetation‐related Sustained Outage,7
1.4. An encroachment due to vegetation growth into the MVCD that caused a
vegetation‐related Sustained Outage.8
M1. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in
R1. Examples of acceptable forms of evidence may include dated attestations, dated
reports containing no Sustained Outages associated with encroachment types 2
through 4 above, or records confirming no Real‐time observations of any MVCD
encroachments. (R1)
R2.

[Reserved for future use]

M2. [Reserved for future use]
R3.

Each applicable Transmission Owner and applicable Generator Owner shall have
documented maintenance strategies or procedures or processes or specifications it
uses to prevent the encroachment of vegetation into the MVCD of its applicable lines
that accounts for the following: [Violation Risk Factor: Lower] [Time Horizon: Long
Term Planning]:
3.1. Movement of applicable line conductors under their Rating and all Rated
Electrical Operating Conditions;

4 This

requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner subject to this Reliability Standard, including natural disasters such as earthquakes, fires, tornados,
hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable Transmission Owner or
applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human or animal activity such as logging,
animal severing tree, vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this footnote
should be construed to limit the Transmission Owner’s or applicable Generator Owner’s right to exercise its full legal rights on
the ROW.

5 If

a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this shall be considered the equivalent of a
Real‐time observation.
6 Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage regardless
of the actual number of outages within a 24‐hour period.
7 Id.
8 Id.

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FAC‐003‐5 Transmission Vegetation Management

3.2. Inter‐relationships between vegetation growth rates, vegetation control
methods, and inspection frequency.
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator
Owner can prevent encroachment into the MVCD considering the factors identified in
the requirement. (R3)
R4.

Each applicable Transmission Owner and applicable Generator Owner, without any
intentional time delay, shall notify the control center holding switching authority for
the associated applicable line when the applicable Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely
to cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Real‐
time].

M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of
evidence may include control center logs, voice recordings, switching orders,
clearance orders and subsequent work orders. (R4)
R5.

When an applicable Transmission Owner and an applicable Generator Owner are
constrained from performing vegetation work on an applicable line operating within
its Rating and all Rated Electrical Operating Conditions, and the constraint may lead to
a vegetation encroachment into the MVCD prior to the implementation of the next
annual work plan, then the applicable Transmission Owner or applicable Generator
Owner shall take corrective action to ensure continued vegetation management to
prevent encroachments [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning].

M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially‐planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de‐rating of
lines, revised work orders, invoices, or evidence that the line was de‐energized. (R5)
R6.

Each applicable Transmission Owner and applicable Generator Owner shall perform a
Vegetation Inspection of 100% of its applicable transmission lines (measured in units
of choice ‐ circuit, pole line, line miles or kilometers, etc.) at least once per calendar

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FAC‐003‐5 Transmission Vegetation Management

year and with no more than 18 calendar months between inspections on the same
ROW9 [Violation Risk Factor: Medium] [Time Horizon: Operations Planning].
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7.

Each applicable Transmission Owner and applicable Generator Owner shall complete
100% of its annual vegetation work plan of applicable lines to ensure no vegetation
encroachments occur within the MVCD. Modifications to the work plan in response
to changing conditions or to findings from vegetation inspections may be made
(provided they do not allow encroachment of vegetation into the MVCD) and must be
documented. The percent completed calculation is based on the number of units
actually completed divided by the number of units in the final amended plan
(measured in units of choice ‐ circuit, pole line, line miles or kilometers, etc.).
Examples of reasons for modification to annual plan may include [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]:
7.1. Change in expected growth rate/environmental factors
7.2. Circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner10
7.3. Rescheduling work between growing seasons
7.4. Crew or contractor availability/Mutual assistance agreements
7.5. Identified unanticipated high priority work
7.6. Weather conditions/Accessibility
7.7. Permitting delays
7.8. Land ownership changes/Change in land use by the landowner
7.9. Emerging technologies

M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
acceptable forms of evidence may include a copy of the completed annual work plan
9 When

the applicable Transmission Owner or applicable Generator Owner is prevented from performing a Vegetation
Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension that is equivalent to
the duration of the time the TO or GO was prevented from performing the Vegetation Inspection.

10 Circumstances

that are beyond the control of an applicable Transmission Owner or applicable Generator Owner include but
are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms, floods, or major
storms as defined either by the TO or GO or an applicable regulatory body.

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FAC‐003‐5 Transmission Vegetation Management

(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority:
“Compliance Enforcement Authority” means NERC or the Regional Entity, or any
entity as otherwise designated by an Applicable Governmental Authority, in
their respective roles of monitoring and/or enforcing compliance with
mandatory and enforceable Reliability Standards in their respective
jurisdictions.
1.2. Evidence Retention:
The following evidence retention period(s) identify the period of time an entity
is required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•

The applicable Transmission Owner and applicable Generator Owner retains
data or evidence to show compliance with Requirements R1, R3, R5, R6 and
R7, for three calendar years.

•

The applicable Transmission Owner and applicable Generator Owner retains
data or evidence to show compliance with Requirement R4, Measure M4 for
most recent 12 months of operator logs or most recent 3 months of voice
recordings or transcripts of voice recordings, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.

•

If an applicable Transmission Owner or applicable Generator Owner is found
non‐compliant, it shall keep information related to the non‐compliance until
found compliant or for the time period specified above, whichever is longer.

1.3. Compliance Monitoring and Enforcement Program
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Enforcement Program” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated Reliability Standard.
1.4. Additional Compliance Information

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FAC‐003‐5 Transmission Vegetation Management

Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator
Owner to have been caused by vegetation, except as excluded in footnote 4,
and including as a minimum the following:
•

The name of the circuit(s), the date, time and duration of the outage; the
voltage of the circuit; a description of the cause of the outage; the category
associated with the Sustained Outage; other pertinent comments; and any
countermeasures taken by the applicable Transmission Owner or applicable
Generator Owner.
A Sustained Outage is to be categorized as one of the following:

•

Category 1A — Grow‐ins: Sustained Outages caused by vegetation growing
into applicable lines, that are identified by the Planning Coordinator, per its
Planning Assessment of the Near‐Term Transmission Planning Horizon as a
Facility that if lost or degraded are expected to result in instances of
instability, Cascading, or uncontrolled separation that adversely impacts the
reliability of the Bulk Electric System by vegetation inside and/or outside of
the ROW;

•

Category 1B — Grow‐ins: Sustained Outages caused by vegetation growing
into applicable lines, but are not identified by the Planning Coordinator, per
its Planning Assessment of the Near‐Term Transmission Planning Horizon as
a Facility that if lost or degraded are expected to result in instances of
instability, Cascading, or uncontrolled separation that adversely impacts the
reliability of the Bulk Electric System for a planning event by vegetation
inside and/or outside of the ROW;

•

Category 2A — Fall‐ins: Sustained Outages caused by vegetation falling into
applicable lines that are identified by the Planning Coordinator, per its
Planning Assessment of the Near‐Term Transmission Planning Horizon as
Facility that if lost or degraded are expected to result in instances of
instability, Cascading, or uncontrolled separation that adversely impacts the
reliability of the Bulk Electric System for a planning event from within the
ROW;

•

Category 2B — Fall‐ins: Sustained Outages caused by vegetation falling into
applicable lines, but are not identified by the Planning Coordinator, per its
Planning Assessment of the Near‐Term Transmission Planning Horizon as
Facilities that if lost or degraded are expected to result in instances of
instability, Cascading, or uncontrolled separation that adversely impacts the
reliability of the Bulk Electric System for a planning event from within the
ROW;

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FAC‐003‐5 Transmission Vegetation Management

•

Category 3 — Fall‐ins: Sustained Outages caused by vegetation falling into
applicable lines from outside the ROW;

•

Category 4A — Blowing together: Sustained Outages caused by vegetation
and applicable lines that are identified by the Planning Coordinator, per its
Planning Assessment of the Near‐Term Transmission Planning Horizon as a
Facility that if lost or degraded are expected to result in instances of
instability, Cascading, or uncontrolled separation that adversely impacts the
reliability of the Bulk Electric System for a planning event blowing together
from within the ROW;

•

Category 4B — Blowing together: Sustained Outages caused by vegetation
and applicable lines, but are not identified by the Planning Coordinator, per
its Planning Assessment of the Near‐Term Transmission Planning Horizon as
a Facility that if lost or degraded are expected to result in instances of
instability, Cascading, or uncontrolled separation that adversely impacts the
reliability of the Bulk Electric System for a planning event blowing together
from within the ROW.
The Regional Entity will report the outage information provided by
applicable Transmission Owners and applicable Generator Owners, as per
the above, quarterly to NERC, as well as any actions taken by the Regional
Entity as a result of any of the reported Sustained Outages.

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FAC‐003‐5 Transmission Vegetation Management

Violation Severity Levels (Table 1)
R#

Table 1: Violation Severity Levels (VSL)

Lower VSL
R1.

Moderate VSL

High VSL

Severe VSL

The responsible entity
failed to manage
vegetation to prevent
encroachment into the
MVCD of a line identified
in the Applicability section
4.2 and 4.3 and
encroachment into the
MVCD as identified in FAC‐
003‐5‐Table 2 was
observed in real time
absent a Sustained Outage.

The responsible entity
failed to manage
vegetation to prevent
encroachment into the
MVCD of a line identified in
the Applicability section 4.2
and 4.3 and a vegetation‐
related Sustained Outage
was caused by one of the
following:
•

A fall‐in from inside the
active transmission line
ROW

•

Blowing together of
applicable lines and
vegetation located
inside the active
transmission line ROW

• A grow‐in
R2.Reserved
for future
use

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FAC‐003‐5 Transmission Vegetation Management

R3.

R4.

R5.

The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications
but has not accounted for
the inter‐relationships
between vegetation
growth rates, vegetation
control methods, and
inspection frequency, for
the responsible entity’s
applicable lines.
(Requirement R3, Part 3.2.)

The responsible entity has
maintenance strategies or
documented procedures
or processes or
specifications but has not
accounted for the
movement of transmission
line conductors under their
Rating and all Rated
Electrical Operating
Conditions, for the
responsible entity’s
applicable lines.
(Requirement R3, Part 3.1.)

The responsible entity does
not have any maintenance
strategies or documented
procedures or processes or
specifications used to
prevent the encroachment
of vegetation into the
MVCD, for the responsible
entity’s applicable lines.

The responsible entity
experienced a confirmed
vegetation threat and
notified the control center
holding switching authority
for that applicable line, but
there was intentional delay
in that notification.

The responsible entity
experienced a confirmed
vegetation threat and did
not notify the control
center holding switching
authority for that
applicable line.
The responsible entity did
not take corrective action
when it was constrained
from performing planned
vegetation work where an
applicable line was put at
potential risk.

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FAC‐003‐5 Transmission Vegetation Management

R6.

The responsible entity
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice ‐ circuit, pole line,
line miles or kilometers,
etc.)

The responsible entity
failed to inspect more than
5% up to and including
10% of its applicable lines
(measured in units of
choice ‐ circuit, pole line,
line miles or kilometers,
etc.).

The responsible entity
failed to inspect more than
10% up to and including
15% of its applicable lines
(measured in units of
choice ‐ circuit, pole line,
line miles or kilometers,
etc.).

The responsible entity
failed to inspect more than
15% of its applicable lines
(measured in units of
choice ‐ circuit, pole line,
line miles or kilometers,
etc.).

R7.

The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).

The responsible entity
failed to complete more
than 5% and up to and
including 10% of its annual
vegetation work plan for
its applicable lines (as
finally modified).

The responsible entity
failed to complete more
than 10% and up to and
including 15% of its annual
vegetation work plan for
its applicable lines (as
finally modified).

The responsible entity
failed to complete more
than 15% of its annual
vegetation work plan for its
applicable lines (as finally
modified).

D. Regional Variances
None.

E. Associated Documents
•

FAC‐003‐4 Implementation Plan

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FAC‐003‐5 Transmission Vegetation Management

Version History
Version

Date

January 20, 2006

Action

Change
Tracking

1. Added “Standard Development Roadmap.”

New

2. Changed “60” to “Sixty” in section A, 5.2.
3. Added “Proposed Effective Date: April 7, 2006”
to footer.
4. Added “Draft 3: November 17, 2005” to footer.
1

April 4, 2007

Regulatory Approval ‐ Effective Date

New

November 3, 2011

Adopted by the NERC Board of Trustees

New

March 21, 2013

FERC Order issued approving FAC‐003‐2 (Order No.
777)

Revisions

FERC Order No. 777 was issued on March 21, 2013
directing NERC to “conduct or contract testing to
obtain empirical data and submit a report to the
Commission providing the results of the testing.”11
2

May 9, 2013

Board of Trustees adopted the modification of the
VRF for Requirement R2 of FAC‐003‐2 by raising the
VRF from “Medium” to “High.”

Revisions

May 9, 2013

FAC‐003‐3 adopted by Board of Trustees

Revisions

September 19, 2013

A FERC order was issued on September 19, 2013,
approving FAC‐003‐3. This standard became
enforceable on July 1, 2014 for Transmission
Owners. For Generator Owners, R3 became
enforceable on January 1, 2015 and all other
requirements (R1, R2, R4, R5, R6, and R7) became
enforceable on January 1, 2016.

Revisions

November 22, 2013

Updated the VRF for R2 from “Medium” to “High”
per a Final Rule issued by FERC

Revisions

July 30, 2014

Transferred the effective dates section from FAC‐
003‐2 (for Transmission Owners) into FAC‐003‐3, per
the FAC‐003‐3 implementation plan

Revisions

11 Revisions

to Reliability Standard for Transmission Vegetation Management, Order No. 777, 142 FERC ¶ 61,208 (2013)

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FAC‐003‐5 Transmission Vegetation Management

February 11, 2016

Adopted by Board of Trustees. Adjusted MVCD
values in Table 2 for alternating current systems,
consistent with findings reported in report filed on
August 12, 2015 in Docket No. RM12‐4‐002
consistent with FERC’s directive in Order No. 777,
and based on empirical testing results for flashover
distances between conductors and vegetation.

March 9, 2016

Corrected subpart 7.10 to M7, corrected value of .07 Errata
to .7

April 26, 2016

FERC Letter Order approving FAC‐003‐4. Docket No.
RD16‐4‐000.

May 13, 2021

Adopted by Board of Trustees

Revisions

March 4,2022

March 4, 2022

FERC issued Letter Order approving FAC-0035.Docket No. RD22-2-000
Effective Date

4/1/2024

Page 16 of 32

Revisions

FAC‐003‐5 Transmission Vegetation Management

FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD)12
For Alternating Current Voltages (feet)
MVCD
(feet)

MVCD
feet

( AC )
Maximu
m System
Voltage
(kV)13

MVC
D
feet

Over sea
level up
to 500 ft

Over 500
ft up to
1000 ft

Over
1000 ft
up to
2000 ft

Over
2000 ft
up to
3000 ft

Over
3000 ft
up to
4000 ft

Over
4000 ft
up to
5000 ft

Over
5000 ft
up to
6000 ft

Over
6000 ft
up to
7000 ft

Over
7000 ft
up to
8000 ft

Over
8000 ft
up to
9000 ft

Over
9000 ft
up to
10000 ft

Over
10000 ft
up to
11000 ft

Over
11000 ft
up to
12000 ft

Over
12000 ft
up to
13000 ft

Over
13000 ft
up to
14000 ft

Over
1400
0 ft
up to
1500
0 ft

765

800

11.6ft

11.7ft

11.9ft

12.1ft

12.2ft

12.4ft

12.6ft

12.8ft

13.0ft

13.1ft

13.3ft

13.5ft

13.7ft

13.9ft

14.1ft

14.3ft

500

550

7.0ft

7.1ft

7.2ft

7.4ft

7.5ft

7.6ft

7.8ft

7.9ft

8.1ft

8.2ft

8.3ft

8.5ft

8.6ft

8.8ft

8.9ft

9.1ft

345

36214

4.3ft

4.4ft

4.5ft

4.6ft

4.7ft

4.8ft

4.9ft

5.0ft

5.1ft

5.2ft

5.3ft

5.4ft

5.5ft

5.6ft

5.7ft

287

302

5.2ft

5.3ft

5.4ft

5.5ft

5.6ft

5.7ft

5.8ft

5.9ft

6.1ft

6.2ft

6.3ft

6.4ft

6.5ft

6.6ft

6.8ft

6.9ft

230

242

4.0ft

4.1ft

4.2ft

4.3ft

4.4ft

4.5ft

4.6ft

4.7ft

4.8ft

4.9ft

5.0ft

5.1ft

5.2ft

5.3ft

5.4ft

161

169

2.7ft

2.8ft

2.9ft

3.0ft

3.1ft

3.2ft

3.3ft

3.4ft

3.5ft

3.6ft

3.7ft

3.8ft

138

145

2.3ft

2.4ft

2.5ft

2.6ft

2.7ft

2.8ft

2.9ft

3.0ft

3.1ft

3.2ft

115

121

1.9ft

2.0ft

2.1ft

2.2ft

2.3ft

2.4ft

2.5ft

2.6ft

2.7ft

100

1.5ft

1.6ft

1.7ft

1.8ft

1.9ft

2.0ft

2.1ft

2.2ft

1.1ft

1.2ft

1.3ft

1.4ft

1.5ft

1.6ft

( AC )
Nomi
nal
Syste
m
Voltag
e
(KV)+

+ Table

2 – Table of MVCD values at a 1.0 gap factor (in U.S. customary units), which is located in the EPRI report filed with FERC on August 12, 2015. (The 14000‐15000 foot
values were subsequently provided by EPRI in an updated Table 2 on December 1, 2015, filed with the FAC‐003‐4 Petition at FERC)

12 The

distances in this Table are the minimums required to prevent Flash‐over; however prudent vegetation maintenance practices dictate that substantially greater distances
will be achieved at time of vegetation maintenance.

13 Where

applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use the maximum
system voltage to determine the appropriate clearance for that line.

14 The

change in transient overvoltage factors in the calculations are the driver in the decrease in MVCDs for voltages of 345 kV and above. Refer to pp.29‐31 in the
Supplemental Materials for additional information.

Page 17 of 32

FAC‐003‐5 Transmission Vegetation Management

TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)15
For Alternating Current Voltages (meters)
MVCD
meters

MVCD
meters

Over
610m up
to 915m

Over
915m up
to 1220m

Over
1220m
up to
1524m

Over
1524m
up to
1829m

Over
1829m
up to
2134m

Over
2134m
up to
2439m

Over
2439m
up to
2744m

Over
2744m
up to
3048m

Over
3048m
up to
3353m

Over
3353m
up to
3657m

Over
3657m
up to
3962m

Over
3962 m
up to
4268 m

Over
4268
m up
to
4572
m

3.6m

3.7m

3.8m

3.9m

4.0m

4.1m

4.2m

4.3m

4.4m

2.2m

2.3m

2.4m

2.5m

2..5m

2.5m

2.6m

2.7m

1.3m

1.4m

1.5m

1.6m

1.7m

1.8m

302

1.6m

1.7m

1.8m

1.9m

2.0m

2.1m

230

242

1.2m

1.3m

1.4m

1.5m

1.6m

161

169

0.8m

0.9m

1.0m

1.1m

138

145

0.7m

0.8m

0.9m

1.0m

115

121

0.6m

0.7m

0.8m

100

0.4m

0.5m

0.6m

0.7m

0.3m

0.4m

0.5m

( AC )
Nomin
al
Syste
m
Voltag
e (KV)+

( AC )
Maximum
System
Voltage
(kV)16

Over sea
level up
to 153 m

Over
153m up
to 305m

Over
305m up
to 610m

765

800

3.6m

500

550

2.1m

345

36217

287

MVCD
meters

+ Table

15 The

16Where

17 The

change in transient overvoltage factors in the calculations are the driver in the decrease in MVCDs for voltages of 345 kV and above. Refer to pp.29‐31 in the supplemental
materials for additional information.

Page 18 of 32

FAC‐003‐5 Transmission Vegetation Management

TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)18
For Direct Current Voltages feet (meters)

MVCD
meters

Over sea
level up to
500 ft

Over 500
ft up to
1000 ft

Over 1000
ft up to
2000 ft

Over 2000
ft up to
3000 ft

Over 3000
ft up to
4000 ft

Over 4000
ft up to
5000 ft

Over 5000
ft up to
6000 ft

Over 6000
ft up to
7000 ft

Over 7000
ft up to
8000 ft

Over 8000
ft up to
9000 ft

Over 9000
ft up to
10000 ft

Over 10000
ft up to
11000 ft

(Over sea
level up to
152.4 m)

(Over
152.4 m
up to
304.8 m

(Over
304.8 m
up to
609.6m)

(Over
609.6m up
to 914.4m

(Over
914.4m up
to
1219.2m

(Over
1219.2m
up to
1524m

(Over
1524 m up
to 1828.8
m)

(Over
1828.8m
up to
2133.6m)

(Over
2133.6m
up to
2438.4m)

(Over
2438.4m
up to
2743.2m)

(Over
2743.2m
up to
3048m)

(Over
3048m up
to
3352.8m)

±750

14.12ft
(4.30m)

14.31ft
(4.36m)

14.70ft
(4.48m)

15.07ft
(4.59m)

15.45ft
(4.71m)

15.82ft
(4.82m)

16.2ft
(4.94m)

16.55ft
(5.04m)

16.91ft
(5.15m)

17.27ft
(5.26m)

17.62ft
(5.37m)

17.97ft
(5.48m)

±600

10.23ft
(3.12m)

10.39ft
(3.17m)

10.74ft
(3.26m)

11.04ft
(3.36m)

11.35ft
(3.46m)

11.66ft
(3.55m)

11.98ft
(3.65m)

12.3ft
(3.75m)

12.62ft
(3.85m)

12.92ft
(3.94m)

13.24ft
(4.04m)

13.54ft
(4.13m)

±500

8.03ft
(2.45m)

8.16ft
(2.49m)

8.44ft
(2.57m)

8.71ft
(2.65m)

8.99ft
(2.74m)

9.25ft
(2.82m)

9.55ft
(2.91m)

9.82ft
(2.99m)

10.1ft
(3.08m)

10.38ft
(3.16m)

10.65ft
(3.25m)

10.92ft
(3.33m)

±400

6.07ft
(1.85m)

6.18ft
(1.88m)

6.41ft
(1.95m)

6.63ft
(2.02m)

6.86ft
(2.09m)

7.09ft
(2.16m)

7.33ft
(2.23m)

7.56ft
(2.30m)

7.80ft
(2.38m)

8.03ft
(2.45m)

8.27ft
(2.52m)

8.51ft
(2.59m)

±250

3.50ft
(1.07m)

3.57ft
(1.09m)

3.72ft
(1.13m)

3.87ft
(1.18m)

4.02ft
(1.23m)

4.18ft
(1.27m)

4.34ft
(1.32m)

4.5ft
(1.37m)

4.66ft
(1.42m)

4.83ft
(1.47m)

5.00ft
(1.52m)

5.17ft
(1.58m)

( DC )
Nominal
Pole to
Ground
Voltage
(kV)

18 The

Page 19 of 32

Supplemental Material

Guideline and Technical Basis
Effective dates:
The Compliance section is standard language used in most NERC standards to cover the general
effective date and covers the vast majority of situations. A special case covers effective dates
for (1) lines initially becoming subject to the Standard, (2) lines changing in applicability within
the standard.
The special case is needed because the Planning Coordinators or Transmission Planners may
designate lines below 200 kV, per its Planning Assessment of the Near‐Term Transmission
Planning Horizon or its Transfer Capability Assessment as Facilities that if lost or degraded are
expected to result in instances of instability, Cascading, or uncontrolled separation that
adversely impacts the reliability of the Bulk Electric System for a planning event in a future
Planning Year (PY). For example, studies by the Planning Coordinator in 2015 may identify a
line to have that designation beginning in PY 2025, ten years after the planning study is
performed. It is not intended for the Standard to be immediately applicable to, or in effect for,
that line until that future PY begins. The effective date provision for such lines ensures that the
line will become subject to the standard on January 1 of the PY specified with an allowance of
at least 12 months for the applicable Transmission Owner or applicable Generator Owner to
make the necessary preparations to achieve compliance on that line. A line operating below
200kV designated by the Planning Coordinator or Transmission Planner, per its Planning
Assessment of the Near‐Term Transmission Planning Horizon or its Transfer Capability
Assessment (Planning Coordinator only) as Facilities that if lost or degraded are expected to
result in instances of instability, Cascading, or uncontrolled separation that adversely impacts
the reliability of the Bulk Electric System for a planning event may be removed from that
designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network.

Date that
Planning Study is
completed

PY the line
will become
an identified
element

Date 1

Date 2

The later of Date 1
or Date 2

05/15/2011

2012

05/15/2012

01/01/2012

05/15/2012

05/15/2011

2013

05/15/2012

01/01/2013

05/15/2011

2014

05/15/2012

01/01/2014

05/15/2011

2021

05/15/2012

01/01/2021

Effective Date

Defined Terms:
Explanation for revising the definition of ROW:

Page 20 of 32

Supplemental Material

The current NERC glossary definition of Right of Way has been modified to include Generator
Owners and to address the matter set forth in Paragraph 734 of FERC Order 693. The Order
pointed out that Transmission Owners may in some cases own more property or rights than are
needed to reliably operate transmission lines. This definition represents a slight but significant
departure from the strict legal definition of “right of way” in that this definition is based on
engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre‐2007 maintenance records are included in the current definition to allow
the use of such vegetation widths if there were no engineering or construction standards that
referenced the width of right of way to be maintained for vegetation on a particular line but the
evidence exists in maintenance records for a width that was in fact maintained prior to this
standard becoming mandatory. Such widths may be the only information available for lines that
had limited or no vegetation easement rights and were typically maintained primarily to ensure
public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming
mandatory.
Explanation for revising the definition of Vegetation Inspection:
The current glossary definition of this NERC term was modified to include Generator Owners and
to allow both maintenance inspections and vegetation inspections to be performed concurrently.
This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the derivation of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet equation. This is a
method of calculating a flash over distance that has been used in the design of high voltage
transmission lines. Keeping vegetation away from high voltage conductors by this distance will
prevent voltage flash‐over to the vegetation. See the explanatory text below for Requirement R3
and associated Figure 1. Table 2 of the standard provides MVCD values for various voltages and
altitudes. The table is based on empirical testing data from EPRI as requested by FERC in Order
No. 777.
Project 2010‐07.1 Adjusted MVCDs per EPRI Testing:
In Order No. 777, FERC directed NERC to undertake testing to gather empirical data validating
the appropriate gap factor used in the Gallet equation to calculate MVCDs, specifically the gap
factor for the flash‐over distances between conductors and vegetation. See, Order No. 777, at P
60. NERC engaged industry through a collaborative research project and contracted EPRI to
complete the scope of work. In January 2014, NERC formed an advisory group to assist with
developing the scope of work for the project. This team provided subject matter expertise for
developing the test plan, monitoring testing, and vetting the analysis and conclusions to be
submitted in a final report. The advisory team was comprised of NERC staff, arborists, and
industry members with wide‐ranging expertise in transmission engineering, insulation
coordination, and vegetation management. The testing project commenced in April 2014 and
continued through October 2014 with the final set of testing completed in May 2015. Based on
these testing results conducted by EPRI, and consistent with the report filed in FERC Docket No.
Page 21 of 32

Supplemental Material

RM12‐4‐000, the gap factor used in the Gallet equation required adjustment from 1.3 to 1.0.
This resulted in increased MVCD values for all alternating current system voltages identified.
The adjusted MVCD values, reflecting the 1.0 gap factor, are included in Table 2 of version 4 of
FAC‐003.
The air gap testing completed by EPRI per FERC Order No. 777 established that trees with
large spreading canopies growing directly below energized high voltage conductors create the
greatest likelihood of an air gap flash over incident and was a key driver in changing the gap
factor to a more conservative value of 1.0 in version 4 of this standard.
Requirements R1:
R1 is a performance‐based requirements. The reliability objective or outcome to be achieved is
the management of vegetation such that there are no vegetation encroachments within a
minimum distance of transmission lines R1 requires each applicable Transmission Owner or
applicable Generator Owner to manage vegetation to prevent encroachment within the MVCD of
transmission lines. R1 is applicable to lines that are identified as an element in the Applicability
section 4.2 and 4.3.
Requirements R1 states that if inadequate vegetation management allows vegetation to
encroach within the MVCD distance as shown in Table 2, it is a violation of the standard. Table 2
distances are the minimum clearances that will prevent spark‐over based on the Gallet equations.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the occurrence
of a clearance encroachment may occur solely due to that condition. For example, emergency
actions taken by an applicable Transmission Owner or applicable Generator Owner or Reliability
Coordinator to protect an Interconnection may cause excessive sagging and an outage. Another
example would be ice loading beyond the line’s Rating and Rated Electrical Operating Condition.
Such vegetation‐related encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real‐time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation‐related
encroachment resulting in a Sustained Outage due to a fall‐in from inside the ROW, or a
vegetation‐related encroachment resulting in a Sustained Outage due to the blowing together of
the lines and vegetation located inside the ROW, or a vegetation‐related encroachment resulting
in a Sustained Outage due to a grow‐in. Faults which do not cause a Sustained outage and which
are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real‐time observation for violation severity levels.
With this approach, the VSLs for R1 are structured such that they directly correlate to the severity
of a failure of an applicable Transmission Owner or applicable Generator Owner to manage
vegetation and to the corresponding performance level of the Transmission Owner’s vegetation
program’s ability to meet the objective of “preventing the risk of those vegetation related
outages that could lead to Cascading.” Thus violation severity increases with an applicable
Page 22 of 32

Supplemental Material

Transmission Owner’s or applicable Generator Owner’s inability to meet this goal and its
potential of leading to a Cascading event. The additional benefits of such a combination are that
it simplifies the standard and clearly defines performance for compliance. A performance‐based
requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example initial investigations and corrective actions may not identify and remove the actual
outage cause then another outage occurs after the line is re‐energized and previous high
conductor temperatures return. Such events are considered to be a single vegetation‐related
Sustained Outage under the standard where the Sustained Outages occur within a 24 hour
period.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines
operated at nominal voltage levels not listed in Table 2, then the applicable TO or applicable GO
should use the next largest clearance distance based on the next highest nominal voltage in the
table to determine an acceptable distance.
Requirement R3:
R3 is a competency based requirement concerned with the maintenance strategies,
procedures, processes, or specifications, an applicable Transmission Owner or applicable
Generator Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach
the applicable Transmission Owner or applicable Generator Owner uses to plan and perform
vegetation work to prevent transmission Sustained Outages and minimize risk to the
transmission system. The approach provides the basis for evaluating the intent, allocation of
appropriate resources, and the competency of the applicable Transmission Owner or applicable
Generator Owner in managing vegetation. There are many acceptable approaches to manage
vegetation and avoid Sustained Outages. However, the applicable Transmission Owner or
applicable Generator Owner must be able to show the documentation of its approach and how
it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach an
applicable Transmission Owner or applicable Generator Owner chooses to use will generally
contain the following elements:
1. the maintenance strategy used (such as minimum vegetation‐to‐conductor distance
or maximum vegetation height) to ensure that MVCD clearances are never violated
2. the work methods that the applicable Transmission Owner or applicable Generator
Owner uses to control vegetation
3. a stated Vegetation Inspection frequency

Page 23 of 32

Supplemental Material

4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below.

Figure 1
A cross‐section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
Requirement R4:
R4 is a risk‐based requirement. It focuses on preventative actions to be taken by the applicable
Transmission Owner or applicable Generator Owner for the mitigation of Fault risk when a
vegetation threat is confirmed. R4 involves the notification of potentially threatening
vegetation conditions, without any intentional delay, to the control center holding switching
authority for that specific transmission line. Examples of acceptable unintentional delays may
include communication system problems (for example, cellular service or two‐way radio
disabled), crews located in remote field locations with no communication access, delays due to
severe weather, etc.

Page 24 of 32

Supplemental Material

Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of an applicable Transmission Owner or applicable Generator Owner employee who
personally identifies such a threat in the field. Confirmation could also be made by sending out
an employee to evaluate a situation reported by a landowner.
Vegetation‐related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow‐in issue) or vegetation that could fall into the transmission
conductor (a fall‐in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no‐load conditions
and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to
ensure the proper communication between field personnel and the control center to allow the
control center to take the appropriate action until or as the vegetation threat is relieved.
Appropriate actions may include a temporary reduction in the line loading, switching the line
out of service, or other preparatory actions in recognition of the increased risk of outage on
that circuit. The notification of the threat should be communicated in terms of minutes or
hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow‐in or fall‐in vegetation‐related conditions will not necessarily cause a Fault at
any moment. For example, some applicable Transmission Owners or applicable Generator
Owners may have a danger tree identification program that identifies trees for removal with
the potential to fall near the line. These trees would not require notification to the control
center unless they pose an immediate fall‐in threat.
Requirement R5:
R5 is a risk‐based requirement. It focuses upon preventative actions to be taken by the
applicable Transmission Owner or applicable Generator Owner for the mitigation of Sustained
Outage risk when temporarily constrained from performing vegetation maintenance. The intent
of this requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner from performing planned vegetation management work and, as a
result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the applicable Transmission Owner’s
or applicable Generator Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re‐planned using an alternate work
methodology. For example, a land owner may prevent the planned use of herbicides to control
incompatible vegetation outside of the MVCD, but agree to the use of mechanical clearing. In
this case the applicable Transmission Owner or applicable Generator Owner is not under any
immediate time constraint for achieving the management objective, can easily reschedule work
using an alternate approach, and therefore does not need to take interim corrective action.

Page 25 of 32

Supplemental Material

However, in situations where transmission line reliability is potentially at risk due to a
constraint, the applicable Transmission Owner or applicable Generator Owner is required to
take an interim corrective action to mitigate the potential risk to the transmission line. A wide
range of actions can be taken to address various situations. General considerations include:
•

Identifying locations where the applicable Transmission Owner or applicable Generator
Owner is constrained from performing planned vegetation maintenance work which
potentially leaves the transmission line at risk.

•

Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.

•

Documenting and tracking the specific action taken for the location.

•

In developing the specific action to mitigate the potential risk to the transmission line
the applicable Transmission Owner or applicable Generator Owner could consider
location specific measures such as modifying the inspection and/or maintenance
intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.

•

The applicable Transmission Owner or applicable Generator Owner should document
and track the specific corrective action taken at each location. This location may be
indicated as one span, one tree or a combination of spans on one property where the
constraint is considered to be temporary.

Requirement R6:
R6 is a risk‐based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections. The provision that Vegetation Inspections can be performed in
conjunction with general line inspections facilitates a Transmission Owner’s ability to meet this
requirement. However, the applicable Transmission Owner or applicable Generator Owner
may determine that more frequent vegetation specific inspections are needed to maintain
reliability levels, based on factors such as anticipated growth rates of the local vegetation,
length of the local growing season, limited ROW width, and local rainfall. Therefore it is
expected that some transmission lines may be designated with a higher frequency of
inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the
applicable lines to be inspected. To calculate the appropriate VSL the applicable Transmission
Owner or applicable Generator Owner may choose units such as: circuit, pole line, line miles or
kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates
2,000 miles of applicable transmission lines this applicable Transmission Owner or applicable
Generator Owner will be responsible for inspecting all the 2,000 miles of lines at least once
during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%.
The “Low VSL” for R6 would apply in this example.
Page 26 of 32

Supplemental Material

Requirement R7:
R7 is a risk‐based requirement. The applicable Transmission Owner or applicable Generator
Owner is required to complete its annual work plan for vegetation management to accomplish
the purpose of this standard. Modifications to the work plan in response to changing conditions
or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to
necessarily require a “span‐by‐span”, or even a “line‐by‐line” detailed description of all work to
be performed. It is only intended to require that the applicable Transmission Owner or
applicable Generator Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation
into the MVCD.
When an applicable Transmission Owner or applicable Generator Owner identifies 1,000 miles
of applicable transmission lines to be completed in the applicable Transmission Owner’s or
applicable Generator Owner’s annual plan, the applicable Transmission Owner or applicable
Generator Owner will be responsible completing those identified miles. If an applicable
Transmission Owner or applicable Generator Owner makes a modification to the annual plan
that does not put the transmission system at risk of an encroachment the annual plan may be
modified. If 100 miles of the annual plan is deferred until next year the calculation to
determine what percentage was completed for the current year would be: 1000 – 100
(deferred miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles. If an
applicable Transmission Owner or applicable Generator Owner only completed 875 of the total
1000 miles with no acceptable documentation for modification of the annual plan the
calculation for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to
complete then, 125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to
complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable
Generator Owner to change priorities or treatment methodologies during the year as
conditions or situations dictate. For example recent line inspections may identify unanticipated
high priority work, weather conditions (drought) could make herbicide application ineffective
during the plan year, or a major storm could require redirecting local resources away from
planned maintenance. This situation may also include complying with mutual assistance
agreements by moving resources off the applicable Transmission Owner’s or applicable
Generator Owner’s system to work on another system. Any of these examples could result in
acceptable deferrals or additions to the annual work plan provided that they do not put the
transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the
applicable Transmission Owner’s or applicable Generator Owner’s easement, fee simple and
other legal rights allowed. A comprehensive approach that exercises the full extent of legal
rights on the ROW is superior to incremental management because in the long term it reduces
the overall potential for encroachments, and it ensures that future planned work and future
planned inspection cycles are sufficient.
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Supplemental Material

When developing the annual work plan the applicable Transmission Owner or applicable
Generator Owner should allow time for procedural requirements to obtain permits to work on
federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits
may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners may also need to consider those special
landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the applicable
Transmission Owner or applicable Generator Owner, evidence of successful annual work plan
execution could consist of signed‐off work orders, signed contracts, printouts from work
management systems, spreadsheets of planned versus completed work, timesheets, work
inspection reports, or paid invoices. Other evidence may include photographs, and walk‐
through reports.
Notes:
The SDT determined that the use of IEEE 516‐2003 in version 1 of FAC‐003 was a misapplication.
The SDT consulted specialists who advised that the Gallet equation would be a technically
justified method. The explanation of why the Gallet approach is more appropriate is explained in
the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses
realistic weather conditions and realistic maximum transient over‐voltages factors for in‐service
transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to
conductor distances in FAC‐003‐1:
•

avoid the problem associated with referring to tables in another standard (IEEE‐516‐2003)

•

transmission lines operate in non‐laboratory environments (wet conditions)

•

transient over‐voltage factors are lower for in‐service transmission lines than for
inadvertently re‐energized transmission lines with trapped charges.

FAC‐003‐1 used the minimum air insulation distance (MAID) without tools formula provided in
IEEE 516‐2003 to determine the minimum distance between a transmission line conductor and
vegetation. The equations and methods provided in IEEE 516 were developed by an IEEE Task
Force in 1968 from test data provided by thirteen independent laboratories. The distances
provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod‐rod air gap,
or in other words, dry laboratory conditions. Consequently, the validity of using these distances
in an outside environment application has been questioned.
FAC‐003‐1 allowed Transmission Owners to use either Table 5 or Table 7 to establish the
minimum clearance distances. Table 7 could be used if the Transmission Owner knew the
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Supplemental Material

maximum transient over‐voltage factor for its system. Otherwise, Table 5 would have to be
used. Table 5 represented minimum air insulation distances under the worst possible case for
transient over‐voltage factors. These worst case transient over‐voltage factors were as follows:
3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 ‐ 550 kV phase to phase; and 2.5 for
765 to 800 kV phase to phase. These worst case over‐voltage factors were also a cause for
concern in this particular application of the distances.
In general, the worst case transient over‐voltages occur on a transmission line that is
inadvertently re‐energized immediately after the line is de‐energized and a trapped charge is
still present. The intent of FAC‐003 is to keep a transmission line that is in service from
becoming de‐energized (i.e. tripped out) due to spark‐over from the line conductor to nearby
vegetation. Thus, the worst case transient overvoltage assumptions are not appropriate for this
application. Rather, the appropriate over voltage values are those that occur only while the line
is energized.
Typical values of transient over‐voltages of in‐service lines are not readily available in the
literature because they are negligible compared with the maximums. A conservative value for
the maximum transient over‐voltage that can occur anywhere along the length of an in‐service
ac line was approximately 2.0 per unit. This value was a conservative estimate of the transient
over‐voltage that is created at the point of application (e.g. a substation) by switching a
capacitor bank without pre‐insertion devices (e.g. closing resistors). At voltage levels where
capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the maximum
transient over‐voltage of an in‐service ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over‐voltages will not be experienced at locations remote from the
bus at which they are created, in order to be conservative, it is assumed that all nearby ac lines
are subjected to this same level of over‐voltage. Thus, a maximum transient over‐voltage factor
of 2.0 per unit for transmission lines operated at 302 kV and below was considered to be a
realistic maximum in this application. Likewise, for ac transmission lines operated at Maximum
System Voltages of 362 kV and above a transient over‐voltage factor of 1.4 per unit was
considered a realistic maximum.
The Gallet equations are an accepted method for insulation coordination in tower design. These
equations are used for computing the required strike distances for proper transmission line
insulation coordination. They were developed for both wet and dry applications and can be
used with any value of transient over‐voltage factor. The Gallet equation also can take into
account various air gap geometries. This approach was used to design the first 500 kV and 765
kV lines in North America.
If one compares the MAID using the IEEE 516‐2003 Table 7 (table D.5 for English values) with
the critical spark‐over distances computed using the Gallet wet equations, for each of the
nominal voltage classes and identical transient over‐voltage factors, the Gallet equations yield
a more conservative (larger) minimum distance value.
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Supplemental Material

Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are
not vastly different when the same transient overvoltage factors are used; the “wet”
equations will consistently produce slightly larger distances than the IEEE 516 equations when
the same transient overvoltage is used. While the IEEE 516 equations were only developed for
dry conditions the Gallet equations have provisions to calculate spark‐over distances for both
wet and dry conditions.
Since no empirical data for spark over distances to live vegetation existed at the time version 3
was developed, the SDT chose a proven method that has been used in other EHV applications.
The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage
Factor that is consistent with the absence of trapped charges on an in‐service transmission line
make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the
Gallet equations.
Comparison of spark‐over distances computed using Gallet wet equations vs.
IEEE 516‐2003 MAID distances
Table 7
(Table D.5 for feet)
Transient

Clearance (ft.)

IEEE 516‐2003

Gallet (wet)

MAID (ft)

( AC )

Nom System

Max System

Over‐voltage

Voltage (kV)

Factor (T)

765

800

2.0

14.36

13.95

500

550

2.4

11.0

10.07

345

362

3.0

8.55

7.47

230

242

3.0

5.28

4.2

115

121

3.0

2.46

2.1

@ Alt. 3000 feet

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Supplemental Material

Rationale:
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from the rationale
text boxes was moved to this section.
Rationale for Applicability (section 4.2.4):
The areas excluded in 4.2.4 were excluded based on comments from industry for reasons
summarized as follows:
1) There is a very low risk from vegetation in this area. Based on an informal survey, no
TOs reported such an event.
2) Substations, switchyards, and stations have many inspection and maintenance
activities that are necessary for reliability. Those existing process manage the threat.
As such, the formal steps in this standard are not well suited for this environment.
3) Specifically addressing the areas where the standard does and does not apply makes
the standard clearer.
Rationale for Applicability (section 4.3):
Within the text of NERC Reliability Standard FAC‐003‐3, “transmission line(s)” and “applicable
line(s)” can also refer to the generation Facilities as referenced in 4.3 and its subsections.
Rationale for R1:
Lines with the highest significance to reliability are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage vegetation which are listed in order of increasing
degrees of severity in non‐compliant performance as it relates to a failure of an applicable
Transmission Owner's or applicable Generator Owner’s vegetation maintenance program:
1. This management failure is found by routine inspection or Fault event investigation, and
is normally symptomatic of unusual conditions in an otherwise sound program.
2. This management failure occurs when the height and location of a side tree within the
ROW is not adequately addressed by the program.
3. This management failure occurs when side growth is not adequately addressed and may
be indicative of an unsound program.
4. This management failure is usually indicative of a program that is not addressing the
most fundamental dynamic of vegetation management, (i.e. a grow‐in under the line). If
this type of failure is pervasive on multiple lines, it provides a mechanism for a Cascade.
Rationale for R3:
The documentation provides a basis for evaluating the competency of the applicable
Transmission Owner’s or applicable Generator Owner’s vegetation program. There may be
many acceptable approaches to maintain clearances. Any approach must demonstrate that the
Page 31 of 32

Supplemental Material

applicable Transmission Owner or applicable Generator Owner avoids vegetation‐to‐wire
conflicts under all Ratings and all Rated Electrical Operating Conditions.
Rationale for R4:
This is to ensure expeditious communication between the applicable Transmission Owner or
applicable Generator Owner and the control center when a critical situation is confirmed.
Rationale for R5:
Legal actions and other events may occur which result in constraints that prevent the applicable
Transmission Owner or applicable Generator Owner from performing planned vegetation
maintenance work.
In cases where the transmission line is put at potential risk due to constraints, the intent is for
the applicable Transmission Owner and applicable Generator Owner to put interim measures in
place, rather than do nothing.
The corrective action process is not intended to address situations where a planned work
methodology cannot be performed but an alternate work methodology can be used.
Rationale for R6:
Inspections are used by applicable Transmission Owners and applicable Generator Owners to
assess the condition of the entire ROW. The information from the assessment can be used to
determine risk, determine future work and evaluate recently‐completed work. This
requirement sets a minimum Vegetation Inspection frequency of once per calendar year but
with no more than 18 months between inspections on the same ROW. Based upon average
growth rates across North America and on common utility practice, this minimum frequency is
reasonable. Transmission Owners should consider local and environmental factors that could
warrant more frequent inspections.
Rationale for R7:
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. It allows modifications to the planned work for changing conditions,
taking into consideration anticipated growth of vegetation and all other environmental factors,
provided that those modifications do not put the transmission system at risk of a vegetation
encroachment.

Page 32 of 32

File Type	application/pdf
File Title	Microsoft Word - 2015-09_FAC-003-5 - Redline_to_approved_clean
Author	harknessl
File Modified	2023-01-31
File Created	2023-01-31