FAC-003-4 Transmission Vegetation Management 

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A. Introduction

1. Title: Transmission Vegetation Management 

2. Number: FAC-003-4

3. 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. 

4. 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 federal1, 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 federal2, state, provincial, 

public, private, or tribal entities:

 

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

2 Id.
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4.3.1. Overhead transmission lines that (1) extend greater than one mile or 

1.609 kilometers beyond the fenced area of the generating station 

switchyard to the point of interconnection with a Transmission Owner’s 

Facility or (2) do not have a clear line of sight3 from the generating 

station switchyard fence to the point of interconnection with a 

Transmission Owner’s Facility and are:

4.3.1.1. Operated at 200kV or higher; or

4.3.1.2. Operated below 200kV 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

6. 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? 

b) 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? 

c) 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. 

 

3 “Clear line of sight” means the distance that can be seen by the average person without special instrumentation (e.g., 

binoculars, telescope, spyglasses, etc.) on a clear day.
FAC-003-4 Transmission Vegetation Management 

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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

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.
FAC-003-4 Transmission Vegetation Management 

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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 below4 [Violation Risk Factor:

High] [Time Horizon: Real-time]:

 

4 This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner or 

applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes, fires, tornados, 

hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable Transmission Owner or 

applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human or animal activity such as logging, 

animal severing tree, vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this footnote 

should be construed to limit the Transmission Owner’s or applicable Generator Owner’s right to exercise its full legal rights on 

the ROW.
FAC-003-4 Transmission Vegetation Management 

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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 Outage7,

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 below9 [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

 

5 If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that a vegetation 

encroachment within the MVCD has occurred from vegetation within the ROW, this shall be considered the equivalent of a 

Real-time observation. 6 Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage regardless

of the actual number of outages within a 24-hour period. 7 Id.

8 Id. 

9 See footnote 4. 

10 See footnote 5. 

11 See footnote 6. 12 Id. 

13 Id. 
FAC-003-4 Transmission Vegetation Management 

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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].
FAC-003-4 Transmission Vegetation Management 

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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 

ROW14 [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 Owner15

7.3. Rescheduling work between growing seasons

7.4. Crew or contractor availability/Mutual assistance agreements 

 

14 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.

15 Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner include but 

are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms, floods, or major 

storms as defined either by the TO or GO or an applicable regulatory body.
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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.
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• 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;
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• 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.
FAC-003-4 Transmission Vegetation Management 

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Violation Severity Levels (Table 1)

R # Table 1: Violation Severity Levels (VSL)

Lower VSL Moderate VSL High VSL Severe VSL

R1. 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 

The responsible entity failed 

to manage vegetation to 

prevent encroachment into 

the MVCD of a line not 

identified as an element of 
FAC-003-4 Transmission Vegetation Management 

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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. 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.

R4. The responsible entity 

experienced a confirmed 

The responsible entity 

experienced a confirmed 
FAC-003-4 Transmission Vegetation Management 

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vegetation threat and 

notified the control center 

holding switching authority 

for that applicable line, but 

there was intentional delay 

in that notification.

vegetation threat and did 

not notify the control center 

holding switching authority 

for that applicable line.

R5. 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
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None.

E. Associated Documents

• FAC-003-4 Implementation Plan

Version History

Version Date Action Change Tracking

1 January 20, 

2006

1. Added “Standard Development Roadmap.”

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.

New

1 April 4, 2007 Regulatory Approval - Effective Date New

2 November 3, 

2011

Adopted by the NERC Board of Trustees New

2 March 21, 

2013

FERC Order issued approving FAC-003-2 (Order No. 

777)

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 

 

16 Revisions to Reliability Standard for Transmission Vegetation Management, Order No. 777, 142 FERC ¶ 61,208 (2013) 
FAC-003-4 Transmission Vegetation Management 

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2 May 9, 2013 Board of Trustees adopted the modification of the 

VRF for Requirement R2 of FAC-003-2 by raising the 

VRF from “Medium” to “High.”

Revisions

3 May 9, 2013 FAC-003-3 adopted by Board of Trustees Revisions

3 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

3 November 22, 

2013

Updated the VRF for R2 from “Medium” to “High” 

per a Final Rule issued by FERC

Revisions

3 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

4 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

4 March 9, 2016 Corrected subpart 7.10 to M7, corrected value of .07 

to .7

Errata

4 April 26, 2016 FERC Letter Order approving FAC-003-4. Docket No. 

RD16-4-000.
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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 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

MVCD 

feet 

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 36219 4.3ft 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 4.3ft 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 2.7ft 2.8ft 2.9ft 2.9ft 3.0ft 3.0ft 3.1ft 3.2ft 3.3ft 3.3ft 3.4ft 3.5ft 3.6ft 3.7ft 3.8ft

138* 145 2.3ft 2.3ft 2.4ft 2.4ft 2.5ft 2.5ft 2.6ft 2.7ft 2.7ft 2.8ft 2.8ft 2.9ft 3.0ft 3.0ft 3.1ft 3.2ft

115* 121 1.9ft 1.9ft 1.9ft 2.0ft 2.0ft 2.1ft 2.1ft 2.2ft 2.2ft 2.3ft 2.3ft 2.4ft 2.5ft 2.5ft 2.6ft 2.7ft

88* 100 1.5ft 1.5ft 1.6ft 1.6ft 1.7ft 1.7ft 1.8ft 1.8ft 1.8ft 1.9ft 1.9ft 2.0ft 2.0ft 2.1ft 2.2ft 2.2ft

69* 72 1.1ft 1.1ft 1.1ft 1.2ft 1.2ft 1.2ft 1.2ft 1.3ft 1.3ft 1.3ft 1.4ft 1.4ft 1.4ft 1.5ft 1.6ft 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)

 

17 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.

18 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.
FAC-003-4 Transmission Vegetation Management 

 Page 17 of 31

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 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

MVCD 

meters 

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 3.6m 3.6m 3.7m 3.7m 3.8m 3.8m 3.9m 4.0m 4.0m 4.1m 4.1m 4.2m 4.2m 4.3m 4.4m

500 550 2.1m 2.2m 2.2m 2.3m 2.3m 2.3m 2.4m 2.4m 2.5m 2..5m 2.5m 2.6m 2.6m 2.7m 2.7m 2.7m

345 36222 1.3m 1.3m 1.3m 1.4m 1.4m 1.4m 1.5m 1.5m 1.5m 1.6m 1.6m 1.6m 1.6m 1.7m 1.7m 1.8m

287 302 1.6m 1.6m 1.7m 1.7m 1.7m 1.7m 1.8m 1.8m 1.9m 1.9m 1.9m 2.0m 2.0m 2.0m 2.1m 2.1m

230 242 1.2m 1.3m 1.3m 1.3m 1.3m 1.3m 1.4m 1.4m 1.4m 1.5m 1.5m 1.5m 1.6m 1.6m 1.6m 1.6m

161* 169 0.8m 0.8m 0.9m 0.9m 0.9m 0.9m 0.9m 1.0m 1.0m 1.0m 1.0m 1.0m 1.1m 1.1m 1.1m 1.1m

138* 145 0.7m 0.7m 0.7m 0.7m 0.7m 0.7m 0.8m 0.8m 0.8m 0.9m 0.9m 0.9m 0.9m 0.9m 1.0m 1.0m

115* 121 0.6m 0.6m 0.6m 0.6m 0.6m 0.6m 0.6m 0.7m 0.7m 0.7m 0.7m 0.7m 0.8m 0.8m 0.8m 0.8m

88* 100 0.4m 0.4m 0.5m 0.5m 0.5m 0.5m 0.6m 0.6m 0.6m 0.6m 0.6m 0.6m 0.6m 0.6m 0.7m 0.7m

69* 72 0.3m 0.3m 0.3m 0.4m 0.4m 0.4m 0.4m 0.4m 0.4m 0.4m 0.4m 0.4m 0.4m 0.5m 0.5m 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)

 

20 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.

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.

22 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.
FAC-003-4 Transmission Vegetation Management 

 Page 18 of 31

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

For Direct Current Voltages feet (meters) 

( DC ) 

Nominal 

Pole to 

Ground

Voltage 

(kV)

MVCD 

meters

MVCD 

meters

MVCD 

meters

MVCD 

meters

MVCD 

meters

MVCD 

meters

MVCD 

meters

MVCD 

meters

MVCD 

meters

MVCD 

meters

MVCD 

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)

 

23 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.
Supplemental Material

Page 19 of 31

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

Effective Date

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 01/01/2013

05/15/2011 2014 05/15/2012 01/01/2014 01/01/2014

05/15/2011 2021 05/15/2012 01/01/2021 01/01/2021

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 definition represents a slight but significant 

departure from the strict legal definition of “right of way” in that this definition is based on 

engineering and construction considerations that establish the width of a corridor from a 

technical basis. The pre-2007 maintenance records are included in the current definition to allow 

the use of such vegetation widths if there were no engineering or construction standards that 
Supplemental Material

Page 20 of 31

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 
Supplemental Material

Page 21 of 31

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 
Supplemental Material

Page 22 of 31

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
Supplemental Material

Page 23 of 31

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.

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 
Supplemental Material

Page 24 of 31

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 
Supplemental Material

Page 25 of 31

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 
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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 
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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, 
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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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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) Voltage (kV) Factor (T) @ Alt. 3000 feet @ Alt. 3000 feet

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
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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 
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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.