RD16-4, NERC Petition, Exhibit A, Proposed Rel. Std.

20160314-5293NERC Exhibit A Proposed Rel Std.pdf.pdf

FERC-725M, (Delegated Order in RD16-4) Mandatory Reliability Standards:Generator Requirements at the Transmission Interface

RD16-4, NERC Petition, Exhibit A, Proposed Rel. Std.

OMB: 1902-0263

⚠️ Notice: This form may be outdated. More recent filings and information on OMB 1902-0263 can be found here:

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Exhibit A
Proposed Reliability Standard FAC-003-4

FAC-003-4 Clean Version

FAC-003-4 Transmission Vegetation Management

A. Introduction
1.

Title:

Transmission Vegetation Management

Number:

FAC-003-4

Purpose:

To maintain a reliable electric transmission system by using a defensein-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 vegetationrelated 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 as an
element of an IROL under NERC Standard FAC-014 by the Planning
Coordinator.
4.2.3. Each overhead transmission line operated below 200 kV identified as an
element of a Major 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.
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:

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

Id.

Page 1 of 31

FAC-003-4 Transmission Vegetation Management

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 sight 3 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 identified as an element of an IROL
under NERC Standard FAC-014 by the Planning Coordinator; 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
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 defensein-depth strategy and comport with the quality objectives of a reliability standard.

“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.

Page 2 of 31

FAC-003-4 Transmission Vegetation Management

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

Page 3 of 31

FAC-003-4 Transmission Vegetation Management

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 causeeffect 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) which are either an element of an IROL, or an
element of a Major WECC Transfer Path; operating within their Rating and all Rated
Electrical Operating Conditions of the types shown below 4 [Violation Risk Factor:
High] [Time Horizon: Real-time]:

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.

Page 4 of 31

FAC-003-4 Transmission Vegetation Management

1.1. An encroachment into the MVCD as shown in FAC-003-Table 2, observed in Realtime, absent a Sustained Outage, 5
1.2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated 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.

Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which
are not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below 9 [Violation Risk Factor: High] [Time Horizon: Real-time]:
2.1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage,10
2.2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage, 11
2.3. An encroachment due to the blowing together of applicable lines and vegetation
located inside the ROW that caused a vegetation-related Sustained Outage, 12
2.4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage. 13

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.
9 See footnote 4.
10 See footnote 5.
11 See footnote 6.
12 Id.
5

Id.

Page 5 of 31

FAC-003-4 Transmission Vegetation Management

M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in
R2. 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. (R2)
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;
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: Realtime].

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].

Page 6 of 31

FAC-003-4 Transmission Vegetation Management

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
year and with no more than 18 calendar months between inspections on the same
ROW 14 [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 Owner 15
7.3. Rescheduling work between growing seasons
7.4. Crew or contractor availability/Mutual assistance agreements

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.

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.

Page 7 of 31

FAC-003-4 Transmission Vegetation Management

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
(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, R2, 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.

Page 8 of 31

FAC-003-4 Transmission Vegetation Management

•

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
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 2,
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 as an element of an IROL or Major
WECC Transfer Path, 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 as an element of an IROL or
Major WECC Transfer Path, 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 as an element of an IROL or Major WECC
Transfer Path, from within the ROW;

•

Category 2B — Fall-ins: Sustained Outages caused by vegetation falling into
applicable lines, but are not identified as an element of an IROL or Major
WECC Transfer Path, from within the ROW;

•

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 as an element of an IROL or Major
WECC Transfer Path, blowing together from within the ROW;
Page 9 of 31

FAC-003-4 Transmission Vegetation Management

•

Category 4B — Blowing together: Sustained Outages caused by vegetation
and applicable lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, 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.

Page 10 of 31

FAC-003-4 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
as an element of an IROL or
Major WECC transfer path
and encroachment into the
MVCD as identified in FAC003-4-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
as an element of an IROL or
Major WECC transfer path
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.

The responsible entity failed
to manage vegetation to
prevent encroachment into
the MVCD of a line not
identified as an element of

Page 11 of 31

FAC-003-4 Transmission Vegetation Management

an IROL or Major WECC
transfer path and
encroachment into the
MVCD as identified in FAC003-4-Table 2 was observed
in real time absent a
Sustained Outage.

an IROL or Major WECC
transfer path 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
R3.

R4.

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

The responsible entity
experienced a confirmed
Page 12 of 31

FAC-003-4 Transmission Vegetation Management

vegetation threat and
notified the control center
holding switching authority
for that applicable line, but
there was intentional delay
in that notification.
R5.

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.

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
Page 13 of 31

FAC-003-4 Transmission Vegetation Management

None.

E. Associated Documents
•

FAC-003-4 Implementation Plan

Version History
Version

Date

January 20,
2006

Action

1. Added “Standard Development Roadmap.”

Change Tracking

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.

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.” 16

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

Page 14 of 31

FAC-003-4 Transmission Vegetation Management

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 FAC003-2 (for Transmission Owners) into FAC-003-3, per
the FAC-003-3 implementation plan

Revisions

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.

Revisions

March 9, 2016

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

Page 15 of 31

FAC-003-4 Transmission Vegetation Management

FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 17
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)+

( AC )
Maximu
m System
Voltage
(kV) 18

MVCD
(feet)

MVCD
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
14000 ft
up to
15000 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

362 19

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

88*

100

1.5ft

1.6ft

1.7ft

1.8ft

1.9ft

2.0ft

2.1ft

2.2ft

69*

1.1ft

1.2ft

1.3ft

1.4ft

1.5ft

1.6ft

∗

Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
+ 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)

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.

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.

19 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 16 of 31

FAC-003-4 Transmission Vegetation Management

TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD) 20
For Alternating Current Voltages (meters)
( AC )
Nominal
System
Voltage
(KV)+

( AC )
Maximum
System
Voltage
(kV) 21

MVCD
meters

Over sea
level up
to 153 m

Over
153m up
to 305m

Over
305m up
to 610m

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
4268m
up to
4572m

765

800

3.6m

3.7m

3.8m

3.9m

4.0m

4.1m

4.2m

4.3m

4.4m

500

550

2.1m

2.2m

2.3m

2.4m

2.5m

2..5m

2.5m

2.6m

2.7m

345

362 22

1.3m

1.4m

1.5m

1.6m

1.7m

1.8m

287

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

88*

100

0.4m

0.5m

0.6m

0.7m

69*

0.3m

0.4m

0.5m

∗

Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
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)
+

21Where 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.

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 31

FAC-003-4 Transmission Vegetation Management

TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD) 23
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)

Page 18 of 31

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 may designate lines below 200
kV to become elements of an IROL or Major WECC Transfer Path 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 as
an element of an IROL or Major WECC Transfer Path 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 IROL
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

Page 19 of 31

Supplemental Material

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.
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

Page 20 of 31

Supplemental Material

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 and R2:
R1 and R2 are 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. Content-wise, R1 and R2 are the same
requirements; however, they apply to different Facilities. Both R1 and R2 require 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 of an IROL or Major WECC Transfer Path. R2 is applicable to all other lines that are
not elements of IROLs, and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or a Major WECC Transfer Path
is a greater risk to the interconnected electric transmission system than applicable lines that are
not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of
IROLs or Major WECC Transfer Paths do require effective vegetation management, but these lines
are comparatively less operationally significant.
Requirements R1 and R2 state 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 and R2 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
Page 21 of 31

Supplemental Material

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 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 performancebased 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

Page 22 of 31

Supplemental Material

2. the work methods that the applicable Transmission Owner or applicable Generator
Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
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.

Supplemental Material

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.
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
Page 24 of 31

Supplemental Material

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.
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
Page 25 of 31

Supplemental Material

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.
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
Page 26 of 31

Supplemental Material

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.
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 walkthrough 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,
Page 27 of 31

Supplemental Material

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
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.
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Supplemental Material

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.
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)
( AC )

( AC )

Transient

Clearance (ft.)

IEEE 516-2003

Nom System

Max System

Over-voltage

Gallet (wet)

MAID (ft)

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 and R2:
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 30 of 31

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.

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FAC-003-4 Redline Version

FAC-003-43 — Transmission Vegetation Management

Effective Dates
Generator Owners
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance strategies or procedures or processes or
specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the Generator Owner becomes
effective on the first calendar day of the first calendar quarter one year after the date of the order approving the standard from
applicable regulatory authorities where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the first calendar quarter one year following
Board of Trustees’ adoption or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6, and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7 applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter two years after the date of the order
approving the standard from applicable regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7 become effective on the
first day of the first calendar quarter two years following Board of Trustees’ adoption or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
Effective dates for individual lines when they undergo specific transition cases:

Page 1 of 51

FAC-003-43 — Transmission Vegetation Management

1. A line operated below 200kV, designated by the Planning Coordinator as an element of an Interconnection Reliability
Operating Limit (IROL) or designated by the Western Electricity Coordinating Council (WECC) as an element of a Major
WECC Transfer Path, becomes subject to this standard the latter of: 1) 12 months after the date the Planning Coordinator or
WECC initially designates the line as being an element of an IROL or an element of a Major WECC Transfer Path, or 2)
January 1 of the planning year when the line is forecast to become an element of an IROL or an element of a Major WECC
Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an IROL or a Major WECC
Transfer Path which has a specified date for the removal of such designation will no longer be subject to this standard effective
on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated element of an IROL or a Major
WECC Transfer Path and which has a specified date for the removal of such designation will be subject to Requirement R2
and no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset owner and which was not
previously subject to this standard becomes subject to this standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner and which was not previously
subject to this standard becomes subject to this standard 12 months after the acquisition date of the line if at the time of
acquisition the line is designated by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Transmission Owners [transferred from FAC-003-2]
This standard becomes effective on the first calendar day of the first calendar quarter one year after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval is required. Where no regulatory approval is required, the
standard becomes effective on the first calendar day of the first calendar quarter one year after Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
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FAC-003-43 — Transmission Vegetation Management

1. A line operated below 200kV, designated by the Planning Coordinator as an element of an Interconnection Reliability
Operating Limit (IROL) or designated by the Western Electricity Coordinating Council (WECC) as an element of a Major
WECC transfer Path, becomes subject to this standard the latter of: 1) 12 months after the date the Planning Coordinator or
WECC initially designates the line as being an element of an IROL or an element of a Major WECC transfer Path, or 2)
January 1 of the planning year when the line is forecast to become an element of an IROL or an element of a Major WECC
transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an IROL or a Major WECC
Transfer Path which has a specified date for the removal of such designation will no longer be subject to this standard effective
on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated element of an IROL or a Major
WECC Transfer Path and which has a specified date for the removal of such designation will be subject to Requirement R2
and no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset owner and which was not
previously subject to this standard, becomes subject to this standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner and which was not previously
subject to this standard becomes subject to this standard 12 months after the acquisition date of the line if at the time of
acquisition the line is designated by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.

Page 3 of 51

FAC-003-43 — Transmission Vegetation Management

A. Introduction
1.

Title:

Transmission Vegetation Management

Number:

FAC-003-34

Purpose:

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

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FAC-003-43 — 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 sight 3 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 identified as an element of an IROL
under NERC Standard FAC-014 by the Planning Coordinator; 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.
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.

Id.

“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-003-43 — Transmission Vegetation Management

The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”

4. Background:
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)

Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
Page 6 of 51

FAC-003-43 — Transmission Vegetation Management

•

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:

Page 7 of 51

FAC-003-43 Transmission Vegetation Management

•

Performance-based: Requirements 1 and 2

•

Competency-based: Requirement 3

•

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

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. R1, R2, and R7 serve as the second line of defense by requiring that
entities carry out their plans and manage vegetation. 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). R4
serves as the final line of defense, as it addresses cases in which all the other lines of
defense have failed.
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 causeeffect relationship which creates the probability of simultaneous occurrence of other

Page 8 of 51

FAC-003-43 Transmission Vegetation Management

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.

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FAC-003-43 Transmission Vegetation Management

B. Requirements and Measures
R1.

Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCDMinimum Vegetation Clearance
Distance (MVCD) of its applicable line(s) which are either an element of an IROL, or an
element of a Major WECC Transfer Path; operating within their Rating and all Rated
Electrical Operating Conditions of the types shown below 4 [Violation Risk Factor:
High] [Time Horizon: Real-time]:
1.1. An encroachment into the MVCD as shown in FAC-003-Table 2, observed in Realtime, absent a Sustained Outage, 5
1.2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated 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.

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FAC-003-43 Transmission Vegetation Management

operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below 9 [Violation Risk Factor: High] [Time Horizon: Real-time]:
2.1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage,10
2.2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage, 11
2.3. An encroachment due to the blowing together of applicable lines and vegetation
located inside the ROW that caused a vegetation-related Sustained Outage, 12
2.4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage. 13
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in
R2. 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. (R2)
R3.

See footnote 4.
See footnote 5.
11 See footnote 6.
12 Id.
9

Id.

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FAC-003-43 Transmission Vegetation Management

R4.

When aan applicable Transmission Owner and an applicable Generator Owner isare
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].

M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
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.

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FAC-003-43 Transmission Vegetation Management

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 Owner 15
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 (as finally modified), dated work orders, dated invoices, or dated
inspection records. (R7)

C. Compliance

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FAC-003-43 Transmission Vegetation Management

Compliance Monitoring Process
1.1. Compliance Enforcement Authority:
The Regional Entity shall serve as the “Compliance Enforcement Authority unless
the applicable” means NERC or the Regional Entity, or any entity is owned,
operated, or controlledas otherwise designated by the Regional Entity. In such cases
the ERO or a Regional entity approved by FERC or other applicable governmental
authority shall serve as the CEA.

For NERC, a third-party monitor without vested interest in the outcome for
NERC shall serve as the Compliance Enforcementan 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 periodsperiod(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, R2, R3, R5, R6
and R7, Measures M1, M2, M3, M5, M6 and M7 for three calendar years
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigationfor three
calendar years.

•

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

1.3. The Compliance Monitoring and Enforcement Authority shall keepProgram

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FAC-003-43 Transmission Vegetation Management

As defined in the last audit records and all requested and submitted subsequent
audit records.
NERC Rules of Procedure, “Compliance Monitoring and Enforcement
Processes: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.
2.

Compliance Audit

Self-Certification

Spot Checking

Compliance Violation Investigation

Self-Reporting
Complaint
Periodic Data Submittal
6.1.1.4.

Additional Compliance Information

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 2,
and including as a minimum the following:
•

•

Category 2A — Fall-ins: Sustained Outages caused by vegetation falling into
applicable lines that are identified as an element of an IROL or Major WECC
Transfer Path, from within the ROW;

Page 15 of 51

FAC-003-43 Transmission Vegetation Management

•

Category 2B — Fall-ins: Sustained Outages caused by vegetation falling into
applicable lines, but are not identified as an element of an IROL or Major
WECC Transfer Path, from within the ROW;

•

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

•

Page 16 of 51

FAC-003-43 Transmission Vegetation Management

Violation Severity Levels (Table of Compliance Elements1)

Time
Horizon

VRF

Table 1: Violation Severity LevelLevels (VSL)

Lower VSL
R1.

Real-time

Moderate VSL
High

High VSL

Severe VSL

The responsible entity
failed to manage
vegetation to prevent
encroachment into the
MVCD of a line identified
as an element of an IROL
or Major WECC transfer
path and encroachment
into the MVCD as
identified in FAC-003-4Table 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 as
an element of an
IROL or Major
WECC transfer
path and a
vegetationrelated Sustained
Outage was
caused by one of
the following:
•

A fall-in from
inside the
active

Page 17
of 51

FAC-003-43 Transmission Vegetation Management

transmission
line ROW
•

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

• A grow-in
R2.

Real-time

High

The responsible entity
failed to manage
vegetation to prevent
encroachment into the
MVCD of a line not
identified as an element
of an IROL or Major WECC
transfer path and
encroachment into the
MVCD as identified in
FAC-003-4-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 not
identified as an
element of an
IROL or Major
WECC transfer
path and a
vegetationrelated Sustained

Page 18
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FAC-003-43 Transmission Vegetation Management

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
R3.

Long-Term
Planning

Lower

The responsible entity
has maintenance
strategies or
documented procedures
or processes or
specifications but has
not accounted for the
inter-relationships
between vegetation

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

The responsible
entity does not
have any
maintenance
strategies or
documented
procedures or
processes or
specifications

Page 19
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FAC-003-43 Transmission Vegetation Management

growth rates, vegetation
control methods, and
inspection frequency, for
the responsible entity’s
applicable lines.
(Requirement R3, Part
3.2).)

Rating and all Rated
Electrical Operating
Conditions, for the
responsible entity’s
applicable lines.
(Requirement R3, Part
3.1).)

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.

R4.

Real-time

Medium

R5.

Operations Planning

Medium

The responsible
entity did not
take corrective
action when it
was constrained
from performing
planned
vegetation work
where an

Page 20
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FAC-003-43 Transmission Vegetation Management

applicable line
was put at
potential risk.
R6.

Operations
Planning

Medium

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.

Operations
Planning

Medium

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).

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FAC-003-43 Transmission Vegetation Management

D. Regional DifferencesVariances
None.
B. Interpretations
None.

E. Associated Documents
•

FAC-003-4 Implementation Plan

Version History
Version

Date

January 20,
2006

Action

1. Added “Standard Development Roadmap.”

Change Tracking

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.

April 4, 2007

Regulatory Approval - Effective Date

New

Page 22
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FAC-003-43 Transmission Vegetation Management

Guideline and Technical Basis (attached).

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

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

Revisions

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

Page 23
of 51

FAC-003-43 Transmission Vegetation Management

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 FAC003-2 (for Transmission Owners) into FAC-003-3, per
the FAC-003-3 implementation plan

Revisions

February 11,
2016

Revisions

March 9, 2016

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

Page 24
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FAC-003-43 Transmission Vegetation Management

FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 17
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)+

( AC )
Maximu
m System
Voltage
(kV) 18

MVCD
(feet)

MVCD
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
14000 ft
up to
15000 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

362 19

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

88*

100

1.5ft

1.6ft

1.7ft

1.8ft

1.9ft

2.0ft

2.1ft

2.2ft

69*

1.1ft

1.2ft

1.3ft

1.4ft

1.5ft

1.6ft

∗

Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)

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.
19

Page 25
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FAC-003-43 Transmission Vegetation Management
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)
+

TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD) 20
For Alternating Current Voltages (meters)
( AC )
Nominal
System
Voltage
(KV)+

( AC )
Maximum
System
Voltage
(kV) 21

MVCD
meters

Over sea
level up
to 153 m

Over
153m up
to 305m

Over
305m up
to 610m

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
4268m
up to
4572m

765

800

3.6m

3.7m

3.8m

3.9m

4.0m

4.1m

4.2m

4.3m

4.4m

500

550

2.1m

2.2m

2.3m

2.4m

2.5m

2..5m

2.5m

2.6m

2.7m

345

362 22

1.3m

1.4m

1.5m

1.6m

1.7m

1.8m

287

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

88*

100

0.4m

0.5m

0.6m

0.7m

69*

0.3m

0.4m

0.5m

21Where

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.
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.
22

Page 26
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FAC-003-43 Transmission Vegetation Management
∗

TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD) 23
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)

Page 27
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FAC-003-43 Transmission Vegetation Management

Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective DatesCompliance section is standard language used in
most NERC standards to cover the general effective date and is sufficient to covercovers the
vast majority of situations. FiveA special cases are needed to covercase covers effective dates
for individual(1) lines which undergo transitions after the general effective date. These special
cases cover the effective dates for those lines which are initially becoming subject to the
standard, thoseStandard, (2) lines which are changing theirin applicability within the standard,
and those lines which are changing in a manner that removes their applicability to the standard..
Case 1The special case is needed because the Planning Coordinators may designate lines below
200 kV to become elements of an IROL or Major WECC Transfer Path in a future Planning Year
(PY). For example, studies by the Planning Coordinator in 20115 may identify a line to have that
designation beginning in PY 20215, 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. The table below has some explanatory
examples of the application.

Date that Planning
Study is
completed

PY the line
will become
an IROL
element

Date 1

Date 2

The latter of Date 1
or Date 2

A05/15/2011

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

Page 28 of 51

FAC-003-43 Transmission Vegetation Management

Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path 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 IROL
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

Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path 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. Such changes result in the need to apply R1 to that line until that date is
reached and then to apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by an applicable Transmission Owner or applicable Generator Owner from a third party
such as a Distribution Provider or other end-user who was using the line solely for local
distribution purposes, but the applicable Transmission Owner or applicable Generator Owner,
upon acquisition, is incorporating the line into the interconnected electrical energy transmission
network which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an
applicable Transmission Owner or applicable Generator Owner from a third party such as a
Distribution Provider or other end-user who was using the line solely for local distribution
purposes, but the applicable Transmission Owner or applicable Generator Owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer
Path.

Page 29 of 51

FAC-003-43 Transmission Vegetation Management

Defined Terms:
Explanation for revising the definition of ROW:
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 modified 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 revisedcurrent 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.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.

Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is beingwas 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.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.

Page 30 of 51

FAC-003-43 Transmission Vegetation Management

Explanation of the defrinivation of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Eequations. 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 belowof the Standard provides MVCD values for various voltages
and altitudes. Details of the equations and an example calculation are providedThe table is based
on empirical testing data from EPRI as requested by FERC in Appendix 1 of the Technical
Reference Document.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.
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 and R2:
R1 and R2 are 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. Content-wise, R1 and R2 are the same
requirements; however, they apply to different Facilities. Both R1 and R2 require each applicable

Page 31 of 51

FAC-003-43 Transmission Vegetation Management

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 of an IROL or Major WECC Transfer Path. R2 is applicable to all other lines that are
not elements of IROLs, and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or a Major WECC Transfer Path
is a greater risk to the interconnected electric transmission system than applicable lines that are
not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of
IROLs or Major WECC Transfer Paths do require effective vegetation management, but these lines
are comparatively less operationally significant. As a reflection of this difference in risk impact,
the Violation Risk Factors (VRFs) are assigned as High for R1 and High for R2.
Requirements R1 and R2 state 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
as described more fully in the Technical Reference document.
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 and R2 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

Page 32 of 51

FAC-003-43 Transmission Vegetation Management

related outages that could lead to Cascading.” Thus violation severity increases with an
applicable 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 performancebased 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.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
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

Page 33 of 51

FAC-003-43 Transmission Vegetation Management

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
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. In the Technical Reference document more figures and explanations of
conductor dynamics are provided.

Page 34 of 51

FAC-003-43 Transmission Vegetation Management

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.
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.

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FAC-003-43 Transmission Vegetation Management

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 chemicals on nonthreatening, low growthherbicides 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 36 of 51

FAC-003-43 Transmission Vegetation Management

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:
•

•

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.

•

Page 37 of 51

FAC-003-43 Transmission Vegetation Management

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.

Requirement R7:
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator
Owner is required to complete its an 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.
For example, whenWhen 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 aan 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

Page 38 of 51

FAC-003-43 Transmission Vegetation Management

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.
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 walkthrough reports.

Page 39 of 51

FAC-003-43 Transmission Vegetation Management

FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 24
For Alternating Current Voltages (feet)
MVCD
(feet)

MVCD
(feet)

MVCD
feet

( AC )
Nominal
System
Voltage
(KV)

( AC )
Maximum
System
Voltage
(kV) 25

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

765

800

8.2ft

8.33ft

8.61ft

8.89ft

9.17ft

9.45ft

9.73ft

10.01ft

10.29ft

10.57ft

10.85ft

11.13ft

500

550

5.15ft

5.25ft

5.45ft

5.66ft

5.86ft

6.07ft

6.28ft

6.49ft

6.7ft

6.92ft

7.13ft

7.35ft

345

362

3.19ft

3.26ft

3.39ft

3.53ft

3.67ft

3.82ft

3.97ft

4.12ft

4.27ft

4.43ft

4.58ft

4.74ft

287

302

3.88ft

3.96ft

4.12ft

4.29ft

4.45ft

4.62ft

4.79ft

4.97ft

5.14ft

5.32ft

5.50ft

5.68ft

230

242

3.03ft

3.09ft

3.22ft

3.36ft

3.49ft

3.63ft

3.78ft

3.92ft

4.07ft

4.22ft

4.37ft

4.53ft

161*

169

2.05ft

2.09ft

2.19ft

2.28ft

2.38ft

2.48ft

2.58ft

2.69ft

2.8ft

2.91ft

3.03ft

3.14ft

138*

145

1.74ft

1.78ft

1.86ft

1.94ft

2.03ft

2.12ft

2.21ft

2.3ft

2.4ft

2.49ft

2.59ft

2.7ft

115*

121

1.44ft

1.47ft

1.54ft

1.61ft

1.68ft

1.75ft

1.83ft

1.91ft

1.99ft

2.07ft

2.16ft

2.25ft

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.

Page 40
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FAC-003-43 Transmission Vegetation Management

∗

88*

100

1.18ft

1.21ft

1.26ft

1.32ft

1.38ft

1.44ft

1.5ft

1.57ft

1.64ft

1.71ft

1.78ft

1.86ft

69*

0.84ft

0.86ft

0.90ft

0.94ft

0.99ft

1.03ft

1.08ft

1.13ft

1.18ft

1.23ft

1.28ft

1.34ft

Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)

TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters

MVCD
meters

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

( AC )
Nominal
System
Voltage
(KV)

( AC )
Maximum
System
Voltage
8
(kV)

765

800

2.49m

2.54m

2.62m

2.71m

2.80m

2.88m

2.97m

3.05m

3.14m

3.22m

3.31m

3.39m

500

550

1.57m

1.6m

1.66m

1.73m

1.79m

1.85m

1.91m

1.98m

2.04m

2.11m

2.17m

2.24m

345

362

0.97m

0.99m

1.03m

1.08m

1.12m

1.16m

1.21m

1.26m

1.30m

1.35m

1.40m

1.44m

287

302

1.18m

0.88m

1.26m

1.31m

1.36m

1.41m

1.46m

1.51m

1.57m

1.62m

1.68m

1.73m

230

242

0.92m

0.94m

0.98m

1.02m

1.06m

1.11m

1.15m

1.19m

1.24m

1.29m

1.33m

1.38m

161*

169

0.62m

0.64m

0.67m

0.69m

0.73m

0.76m

0.79m

0.82m

0.85m

0.89m

0.92m

0.96m

Page 41
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FAC-003-43 Transmission Vegetation Management
138*

145

0.53m

0.54m

0.57m

0.59m

0.62m

0.65m

0.67m

0.70m

0.73m

0.76m

0.79m

0.82m

115*

121

0.44m

0.45m

0.47m

0.49m

0.51m

0.53m

0.56m

0.58m

0.61m

0.63m

0.66m

0.69m

88*

100

0.36m

0.37m

0.38m

0.40m

0.42m

0.44m

0.46m

0.48m

0.50m

0.52m

0.54m

0.57m

69*

0.26m

0.27m

0.29m

0.30m

0.31m

0.33m

0.34m

0.36m

0.37m

0.39m

0.41m

∗

Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)

TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)

( DC )
Nominal
Pole to

MVCD
meters

Page 42
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FAC-003-43 Transmission Vegetation Management
Ground
Voltage
(kV)

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)

Page 43
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Supplemental Material

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 Eequation 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 usesd 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-003-011 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
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

Page 44 of 51

Supplemental Material

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, as such, 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 inservice ac line iswas approximately 2.0 per unit. This value iswas 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 iswas 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 iswas
considered a realistic maximum.
The Gallet Eequations 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 Eequation 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.
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.
While EPRI is currently trying to establish Since no empirical data for spark- over distances to
live vegetation, there are no spark-over formulas currently derived expressly for vegetation to
conductor minimum distances. Therefore 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
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Supplemental Material

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.

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Supplemental Material

Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances

Table 7
(Table D.5 for feet)
( AC )

( AC )

Transient

Clearance (ft.)

IEEE 516-2003

Nom System

Max System

Over-voltage

Gallet (wet)

MAID (ft)

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)
1) There is a very low risk from vegetation in this area. Based on an informal survey, no
TOs reported such an event. 2)
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)
1)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 and R2:
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. 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. 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. 3. This management failure occurs when side growth is not adequately addressed and
may be indicative of an unsound program.
4. 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.

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Supplemental Material

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
applicable Transmission Owner or applicable Generator Owner avoids vegetation-to-wire
conflicts under all Ratings and all Rated Electrical Operating Conditions. See Figure
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.

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Supplemental Material

Version History
Version
1

Date

Action

Change
Tracking

TBA

1. Added “Standard
Development Roadmap.”

01/20/06

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

November
3, 2011

Adopted by the NERC Board
of Trustees

March 21,
2013

FERC Order issued approving
FAC-003-2

May 9,
2013

Board of Trustees adopted the

New

modification of the VRF for
Requirement
R2 of FAC-003-2 by raising
the VRF from
“Medium” to “High.”

May 9,
2012

FAC-003-3 adopted by Board
of Trustees

September
19, 2013

A FERC order was issued on
September 19, 2013,
approving FAC-003-3. This
standard becomes enforceable
on July 1, 2014 for
Transmission Owners. For
Generator Owners, R3
becomes enforceable on
January 1, 2015 and all other
requirements (R1, R2, R4, R5,
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Supplemental Material

R6, and R7) will become
enforceable on January 1,
2016.
3

November
22, 2013

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

July 30,
2014

Transferred the effective dates
section from FAC-003-2 (for
Transmission Owners) into
FAC-003-3, per the FAC-0033 implementation plan

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File Type	application/pdf
Author	Courtney Baughan
File Modified	2016-07-11
File Created	2016-03-09